Well Control Manual

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WELL CONTROL MANUAL

Table of Contents Introduction and Responsibilities Section A Basic Calculations and Terminology Section B Causes and Detection of Kicks Section C Tripping Procedures Section D Shut-In Procedures Section E Well Killing Procedures Section F Pre-recorded Data Sheet Section G Driller’s Method Section H Engineer’s Method Section I Volumetric Control Section J Equipment Requirements Section K Maintenance and Testing Requirements Section L Diverting Operations and Equipment Section M Training and Well Control Drills Section N Hydrogen Sulfide ( H2S) Considerations Section O Stripping and Snubbing Section P Tables and Charts Section Q Well Control Equations Section R Well Control Policies Section S Supplemental References

WELL CONTROL MANUAL

Drilling & Workover October 2002 __

INTRODUCTION AND RESPONSIBILITIES

Current Edition: October 2002 1 3rd Edition Previous Revision: October 1998

Table of Contents

Introduction.......................................................................................................... 2 1.0 Responsibilities of Drilling Staff ........................................................ 3

1.1 Well Planning................................................................................... 3 1.2 Drilling Program............................................................................... 3 1.3 Geological Information..................................................................... 3 1.4 Area Drilling Experience .................................................................. 4 1.5 Casing Design and Depths of Setting .............................................. 4 1.6 Equipment Selection........................................................................ 4 1.7 Hiring Contract Rigs. ........................................................................ 4 1.8 Specification of Rig Equipment ....................................................... 4 1.9 Contract Responsibilities................................................................. 4 1.10 Training of Company and Contract Personnel ................................. 5 1.11 BOP Equipment ............................................................................... 5 1.12 BOP Testing ..................................................................................... 5 1.13 Well Control ..................................................................................... 5 1.14 Pre-recorded Data Sheet ................................................................. 5 1.15 Slow Pump Rate Data....................................................................... 5 1.16 Blowout Prevention Training ........................................................... 6 1.17 Information to be Posted.................................................................. 6

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Introduction The single most important step to blowout prevention is closing the blowout preventers when the well kicks. The decision to do so may well be the most important of your working life. It ranks with keeping the hole full of fluid as a matter of extreme importance in drilling operations. The successful detection and handling of threatened blowouts (‘kicks’) is a matter of maximum importance to our company. Considerable study and experience has enabled the industry to develop simple and easily understood procedures for detecting and controlling threatened blowouts. It is extremely important that supervisory personnel have a thorough understanding of these procedures as they apply to Saudi Aramco operated drilling rigs. The reasons for promoting proper well control and blowout prevention are overwhelming. An uncontrolled flowing well can cause any or all of the following:

• Personal injury and/or loss of life • Damage and/or loss of contractor equipment • Loss of operator investment • Loss of future production due to formation damage • Loss of reservoir pressures • Damage to the environment through pollution • Adverse publicity • Negative governmental reaction, especially near populated areas

This manual describes Saudi Aramco’s policies and equipment standards for well control/blowout prevention. It has been designed to serve as a reference for company and contractor personnel working in drilling and workover operations. Changes in this 3rd Edition of the Saudi Aramco Well Control Manual are indicated by a bold vertical line in the right margin, opposite the revision.

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1.0 Responsibilities of Drilling Staff

The Drilling and Workover Organization includes an office drilling staff comprised of the Drilling Operations Manager(s), Drilling Engineering Manager, Drilling Superintendent(s), and Drilling Engineer(s) in addition to the onsite Drilling Foreman. Their responsibilities include:

1.1 Well Planning

Planning for maximum efficiency and safe operations is primarily the office drilling staff's responsibility. They must, with concurrence of the Drilling Operations Manager, use all known information and good judgment to make the best possible well plan for a particular area.

1.2 Drilling Program

This program should include the casing program, mud program, consideration of special equipment that will be required and specific well problems that may be encountered, and any other information pertinent to the safe and efficient drilling of the particular well. The drilling program is written by the Drilling Engineer (assigned to the rig) and approved by the Drilling Superintendent and/or Drilling Operations Manager. A directional program is also required to avoid existing holes, or when the target location is different than the surface location, or in case a relief well is needed. The amount of detail required depends on the depth, pressure, presence of H2S,

crookedness, etc. In high angle holes, singleshot readings should be taken on two instruments, and an ellipse-of-uncertainty calculated. It is very important, especially in offshore operations, to know accurately the surface and subsurface locations of the well. In directionally drilled wells, the well course should be pre-planned, and horizontal and vertical sections should be maintained continuously during drilling, to insure that the well course is accurate. Deviations should be corrected early to avoid excessive doglegs. Often multi-shot readings are made prior to setting surface casing, so its position is accurately known. All reasonable effort must be made to know accurately the well position and course, from the surface to total depth. The degree of effort required varies with the drilling operation.

1.3 Geological Information

The Drilling Engineer needs all available geological information for the area to prepare a good drilling program. This requires good communication with the geologists to explore possible drilling problems, and preparing a method of handling each.

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1.4 Area Drilling Experience

Each area has characteristic drilling problems that experienced personnel can handle most efficiently and safely. The Drilling Superintendent and Manager should be primarily responsible for seeing such assignments are filled with qualified Drilling Foremen.

1.5 Casing Design and Depths of Setting

Compliance to proper casing design and setting depths, calculated from expected formation pressures and fracture gradients, is vital, particularly in high-pressure areas. Isolation of fresh water aquifers must also be considered in the casing program.

1.6 Equipment Selection

Proper equipment is necessary for an efficient and safe operation. Considerable care must be exercised in selecting equipment with the pressure rating and design for the specific job. This should be primarily the Drilling Superintendent’s responsibility, with concurrence of the Drilling Operations Manager and Drilling Engineering Manager.

1.7 Hiring Contract Rigs

The Drilling Superintendent and Drilling Operations Manager will usually provide the proper rig for the job. The rig’s experience in the area could be a factor, and rig evaluations should include past performance and condition of equipment. Where crews change seasonally, the decision could be based on the general performance of the contractor.

1.8 Specification of Rig Equipment

Selecting the proper equipment to do a particular job is very important. The Drilling Superintendent’s closeness to the operation makes him best qualified to recommend equipment.

1.9 Contract Responsibilities

The Drilling Superintendent and Drilling Operations Manager have the responsibility to see that the contracts between Saudi Aramco and the drilling contractor are written clearly, defining the obligations of both contracting parties.

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1.10 Training of Company and Contract Personnel

The Drilling Superintendent and Drilling Operations Manager should maintain a training program for the less experienced drilling employees. The program should pair the newer employees with experienced Drilling Foremen at the wellsite, and include attendance at company-sponsored and external schools/seminars. Drilling Superintendents should periodically review well control procedures with the Drilling Foreman. The contractor shall be required to train his men in well control, either by contract or by direction from the Drilling Superintendent and Foremen.

1.11 BOP Equipment

The Drilling Foreman must ensure that the proper BOP equipment is available and installed correctly and in good working order. He must also verify that the equipment is in compliance with all Saudi Aramco requirements and API specifications. ALL SECTIONS of the BOP Test and Equipment Checklist must be completed upon initial nipple-up.

1.12 BOP Testing

Saudi Aramco requires that the blowout preventer stack be tested once every two weeks and before drilling out each new casing string. Accurate and complete testing of the BOP equipment is the responsibility of the Drilling Foreman on location. The BOP Test and Equipment Checklist should be completed after each test.

1.13 Well Control

The Drilling Foreman is primarily responsible for keeping the well under control. This responsibility includes maintaining the proper mud properties, recognizing indicators of abnormal pressure and executing the proper well control procedures after the well kicks.

1.14 Pre-recorded Data Sheet

The pre-recorded data sheet should be filled out as completely as possible at all times on drilling and workover wells. The data sheet lists critical wellbore information, which will be needed in nearly all well control situations.

1.15 Slow Pump Rate Data

The Drilling Foreman must make sure that slow pump rates and pressures are recorded:

• Tourly • After a mud weight change • After a bit nozzle or BHA change (after breaking circulation gels) • After each 500 ft depth interval

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• After a drilling/completion, or workover fluid type change • Whenever mudflow properties change significantly

Slow pump pressure measurements should not be taken at the following times:

• If the mud flow properties are contaminated • Hydrostatic imbalance exists between drill/work string and annulus • During times of loss of circulation or washouts in the drill/work string

1.16 Blowout Prevention Training

The finest equipment and the best procedures are of little use unless the rig crews are properly trained to use them. The Drilling Foreman must see that the crews are properly trained and respond immediately in all well control situations. The Drilling Foreman should make sure that the shut-in procedures while tripping and drilling are clearly posted at several locations around the rig, and that every crewmember knows his shut-in responsibilities.

1.17 Information to be Posted

The Drilling Foreman should know and post the following information:

• Maximum allowable initial shut -in casing pressure to fracture shoe • Maximum allowable casing pressure • Maximum number of stands pulled prior to filling the hole (collars,

HW, and DP) • Volume required to fill the hole on trips (collars, HW, and DP) • Crew responsibilities for well control drills

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SECTION A – BASIC CALCULATIONS AND TERMINOLOGY

Current Edition: October 2002 A - 1 3rd Edition Previous Revision: October 1998

Table of Contents

1.0 Understanding Pressures................................................................. A-2 1.1 Hydrostatic Pressure .................................................................... A-2 1.2 Pressure Gradient......................................................................... A-2 1.3 Formation Pressure ...................................................................... A-3 1.4 Surface Pressure .......................................................................... A-3 1.5 Bottomhole Pressure .................................................................... A-4 1.6 Equivalent Circulating Density...................................................... A-4 1.7 Differential Pressure ..................................................................... A-5 1.8 Choke Pressure ............................................................................ A-5 1.9 Swab and Surge Pressures........................................................... A-5 1.10 Fracture Pressure ......................................................................... A-6

2.0 Relationship of Pressure to Volume .............................................. A-7 2.1 Liquids .......................................................................................... A-7 2.2 Gases............................................................................................ A-7

3.0 Relationship of Pump Pressure to Mud Weight .......................... A-8 4.0 Relationship of Pump Pressure to Circulating Rate.................. A-8 5.0 Capacity Factors and Displacement .............................................. A-9

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1.0 Understanding Pressures

1.1 Hydrostatic Pressure

All vertical columns of fluid exert hydrostatic pressure. The magnitude of the hydrostatic pressure is determined by the height of the column of fluid and the density of the fluid. It should be remembered that both liquids and gases could exert hydrostatic pressure. The hydrostatic pressure exerted by a column of fluid can be calculated using Equation A.1. While drilling ahead, the hydrostatic pressure exerted by the drilling mud is our number one defense against taking kicks.

Equation A.1 Hydrostatic Pressure

HP = MW x 0.007 x TVD

where: HP = Hydrostatic Pressure (psi) MW = Mud Weight (pcf) TVD = True Vertical Depth (ft)

1.2 Pressure Gradient

When comparing fluid densities and hydrostatic pressures, it is often useful to think in terms of a pressure gradient. The pressure gradient associated with a given fluid is simply the hydrostatic pressure per vertical foot of that fluid. Heavier (more dense) fluids have higher-pressure gradients than lighter fluids. The pressure gradient of a given fluid can be calculated with the formula given in Equation A.2.

Equation A.2 Pressure Gradient

PG = MW x 0.007

where: PG = Pressure Gradient (psi/ft)

MW = Mud Weight (pcf)

As you can see from the above equation, the pressure gradient can be thought of as an alternate way of describing a fluid’s density. This is useful because other parameters, such as reservoir pressure, are often expressed in terms of pressure gradients as well.

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1.3 Formation Pressure

Formation pressure is the pressure contained inside the rock pore spaces. Knowledge of formation pressure is important because it will dictate the mud hydrostatic pressure and therefore the mud weight required in the well. If the formation pressure is greater than the hydrostatic pressure of the mud column, fluids (gas, oil or salt water) can flow into the well from permeable formations. Normal pressure gradients for formations will depend on the environment in which they were laid down in and will vary from area to area. Consider a formation located at a vertical depth of 5000’ and with a reservoir pressure of 2325 psi. The pressure gradient of this formation can be easily figured with the following formula:

Pressure PG = Vertical Depth 2,325 psi = = 0.465 psi/ft 5,000 ft

In order to keep this formation from flowing into the well, the mud in the hole must also have a pressure gradient of at least 0.465 psi/ft. This condition could be achieved by filling the hole with 67 pcf salt water.

1.4 Surface Pressure

We use the term surface pressure to describe any pressure that is exerted at the top of a column of fluid. Most often we refer to surface pressure as the pressure, which is observed at the top of a well. Surface pressure may be generated from a variety of sources including downhole formation pressures, surface-pumping equipment, or surface chokes. Some surface pressures are conveyed throughout the wellbore while others are not. For example, circulating an open well with 1,000 psi pump pressure will not increase the bottomhole pressure by 1,000 psi. The reason for this is that the pump pressure is due primarily to internal drillpipe friction, which acts opposite to the direction of flow. In a similar way, the annular friction loss generated while circulating will increase the bottomhole pressure but will not increase the annular surface pressure. The key to understanding frictional pressure losses is to remember that they only increase the pressures in the fluids, which are upstream of the point of friction. Under static conditions (not pumping or flowing) frictional pressure losses are equal to zero. Therefore, under static conditions, any pressure which we observe at surface will also be conveyed downhole.

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1.5 Bottomhole Pressure Bottomhole pressure is equal to the sum of all pressures acting in a well. Generally speaking, bottomhole pressure is the sum of the hydrostatic pressure of the fluid column above the point of interest, plus any surface pressure, which may be exerted on top of the fluid column, plus any annular friction pressure. This concept is expressed mathematically in Equation A.3.

Equation A.3 Bottomhole Pressure

BHP = HP + SP + FP

where: BHP = Bottomhole Pressure (psi)

HP = Hydrostatic Pressure (psi) SP = Surface Pressure (psi)

FP = Friction Pressure (psi)

When the hole is full and the mud column is at rest with no surface pressure, the bottomhole pressure is the same as the mud hydrostatic pressure. However, if circulating through a choke or separator at the surface, the annular surface pressure and friction pressure (back pressures) will be conveyed downhole and must be added to the mud hydrostatic pressure to obtain the total bottomhole pressure. If the well is shut in, under static conditions, the bottomhole pressure will be equal to the sum of the hydrostatic pressure and any observed surface pressure. In this static case, the bottomhole pressure will also equal the formation pressure.

1.6 Equivalent Circulating Density

When circulating fluid in a wellbore, frictional pressures occur in the surface system, drill pipe, bit and in the annulus, which in turn are reflected in the standpipe pressure. As also discussed, these frictional pressures always act opposite to the direction of flow. When circulating conventionally, or the “long way”, all the frictional pressures, including annular friction, act against the pump. The annular friction, or annular pressure loss as it is sometimes referred to, acts against the bottom of the wellbore, which results in an increase in bottomhole pressure. This is known as Equivalent Circulating Density, or ECD. ECD is normally expressed as a pound per cubic foot equivalent mud weight and is shown mathematically in Equation A.4.

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Equation A.4 Equivalent Circulating Density

Annular Pressure Loss ECD = + Present Mud Weight 0.007 x TVD hole ECD is a result of annular friction and is affected by such items as:

• Clearance between large OD tools and the ID of the wellbore • Circulating rates (or annular velocity) • Viscosity of the mud

An accurate value for annular pressure loss, and subsequently ECD, is very difficult to arrive at for any particular situation and, once calculated, would change with increasing hole depth and changes in hole geometry (hole washout, etc.). Thus, attempting to keep up with ECD in the field would be an effort in futility. The important thing to remember is that while circulating, bottomhole pressure will be higher than when the well is static due to the presence of annular friction.

1.7 Differential Pressure

In well control, differential pressure is the difference between the bottomhole pressure and the formation pressure. The differential is positive if the bottomhole pressure is greater than the formation pressure, which creates what is called an ‘overbalanced’ condition.

1.8 Choke Pressure

Choke pressure is the pressure loss created by directing the return flow from a shut-in well through a small opening or orifice for the purpose of creating a backpressure on the well while circulating out a kick. The choke or back pressure can be thought of as a frictional pressure loss which will be imposed on all points in the circulating system, including the bottom of the hole.

1.9 Swab and Surge Pressures

Swab pressure is the temporary reduction in the bottomhole pressure that results from the upward movement of pipe in the hole. Surge pressure is the opposite effect, whereby wellbore pressure is temporarily increased as pipe is run into the well. The movement of the drilling string or casing through the wellbore is similar to the movement of a loosely fit piston through a vertical cylinder. A pressure reduction or suction pressure occurs as the piston or the pipe is moved upward in the cylinder or wellbore and a pressure increase occurs as the piston, or pipe, is moved downward.

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Swab and surge pressures are mostly affected by the velocity of upward or downward movement in the hole. Other factors affecting these pressures include:

• Mud gel strength • Mud weight • Mud viscosity • Annular clearance between pipe and hole • Annular restrictions, such as bit balling

In order to prevent the influx of formation fluids into the wellbore during times when the pipe is moved upward from bottom, the difference between mud hydrostatic and swab pressure must not fall below the formation pressure.

1.10 Fracture Pressure

The formations penetrated by the bit are under considerable stress, due to the weight of the overlying sediments. If additional stress is applied while drilling, the combined stresses may be enough to cause the rock to fail or split, allowing the loss of whole mud to the formation. Fracture pressure is the amount of borehole pressure that it takes to split or fail a formation. Rock strength usually increases with increasing depth and overburden load. As load is increased the rock becomes highly compacted, giving it the ability to withstand higher horizontal and vertical stresses. Therefore, fracture pressure normally increases with depth. Fracture pressure is normally expressed as a gradient or an equivalent density with units of psi/ft or pcf, respectively.

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2.0 Relationship of Pressure to Volume All fluids under pressure will change in volume as the pressure changes. As pressure increases, the volume of the fluid will decrease (i.e., the fluid will compress). As pressure decreases the volume will increase (i.e., the fluid will expand). Volume of a fluid is related to a lesser extent to its temperature. In general, volume will increase with an increase in temperature and decrease with a decrease in temperature. Fluids will compress or expand differently depending on their compressibility. Liquids have a low compressibility compared to gas. The relative compressibility of liquids and gases is an important factor in well control.

2.1 Liquids

Liquids of concern in well control include mud, salt water, oil, or any combination of these liquids. Since the compressibility of these liquids is low, little change in volume due to pressure or temperature changes should be expected as liquids are circulated from the wellbore. Therefore, liquid expansion due to pressure and temperature changes is considered negligible for nearly all well control calculations.

2.2 Gases

Gases, on the other hand, are very compressible and are subject to large changes in volume as they migrate or are circulated from the wellbore. The expansion of a gas bubble while circulating out a kick displaces large volumes of mud from the annulus, which lowers the hydrostatic pressure. In order to maintain the bottomhole pressure at a constant value equal to formation pressure, the choke must be decreased which increases the surface pressure. The expanding gas also causes the pit level to increase, which must be considered. With constant surface pressure, the volume of the gas bubble will roughly double each time the bubble depth of an open well is halved. If ‘V’ is the volume of a gas and ‘P’ is the pressure then, disregarding temperature effects, the relationship between volume and pressure of a gas is given by Boyle’s Law in Equation A.5.

Equation A.5 Boyle’s Law

P1 x V1 = P2 x V2

where: P1 = Pressure of gas at depth 1 V1 = Volume of gas at depth 1 P2 = Pressure of gas at depth 2 V2 = Volume of gas at depth 2

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3.0 Relationship of Pump Pressure to Mud Weight The relationship between mud weight and pump pressure is given by the following formula:

Equation A.6 New Pump Pressure = Old Pump Pressure x New Mud Weight Old Mud Weight where:

New Pump Pressure & Old Pump Pressure (psi) New Mud Weight & Old Mud Weight (pcf)

Example:

Old Pump Pressure = 2800 psi Old Mud Weight = 97 pcf New Mud Weight = 105 pcf Calculate the pump pressure required to circulate the well with the new mud weight? New Pump Pressure = 2800 x (105/97) = 3030 psi

4.0 Relationship of Pump Pressure to Circulating Rate

The relationship between pump pressure and circulating rate is given by the formula below:

Equation A.7 New Pump Pressure = Old Pump Pressure x ( New Circ. Rate/Old Circ. Rate )2

where:

New Pump Pressure & Old Pump Pressure (psi) Circulating Rate (spm, gpm, or bpm)

Example:

Old Pump Pressure = 2800 psi New Pump Speed = 60 spm Old Pump Speed = 80 spm Calculate the new pump pressure for the slower pump rate? New Pump Pressure = 2800 x (60/80)2 = 1575 psi

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5.0 Capacity Factors and Displacement In well control and in routine drilling operations, frequent calculations of capacity and displacement must be made. A brief review of the mechanics involved is provided below.

The capacity factor is defined as the volume of fluid held per foot of container. The container may be any number of things including a mud pit, an open hole, the inside of a drill string, or an annulus. Capacity factors change as the dimensions of the container change. The internal capacity factor is used to calculate internal drillstring volumes and the annular capacity factor is used to calculate annular volumes. The formulas for calculating these capacity factors are given in Equations A.6 and A.7. In lieu of these equations, Tables P.1 - P.4 can be used to determine internal and annular capacity factors for several wellbore configurations.

Equation A.8 Internal Capacity Factor

ID2 CF =

1029

where: CF = Capacity Factor (bbl/ft) ID = Internal pipe diameter (inches)

Equation A.9 Annular Capacity Factor

OD2 - ID2 CF = 1029

where: CF = Capacity Factor (bbl/ft) OD = Inside diameter of larger pipe (inches) ID = Outside diameter of smaller pipe (inches)

Capacity is the volume of fluid held within a specific container. Internal (drillstring) and annular capacities are some of the most important parameters, which are calculated in a well control situation. Capacity is determined by multiplying the height (or length) of the container by its capacity factor.

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Displacement is the volume of fl uid displaced by placing a solid, such as drill pipe, tubing etc., into a fixed volume of liquid. Total displacement of drillpipe, casing, tubing, etc. can be determined by multiplying the length of pipe immersed times the displacement factor (bbls/ft) as determined from Tables P.1 - P.4. The volume of mud in the hole is always equal to the capacity of the entire hole, minus the displacement of the pipe in the hole (assuming the pipe and annulus are full). The annular capacity between drillstring components and the casing or hole can be calculated by subtracting both the capacity and displacement of the drillstring component from the capacity of the hole.

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SECTION B – CAUSES AND DETECTION OF KICKS

Current Revision: October 2002 B - 1 3rd Edition Previous Revision: October 1998

Table of Contents

1.0 Causes of Kicks................................................................................... B-2 1.1 Low Density Drilling Fluid............................................................. B-2

1.1.1 Gas Cutting ........................................................................ B-2 1.1.2 Oil or Saltwater Cutting........................................................ B-3

1.2 Abnormal Reservoir Pressure ....................................................... B-4 1.3 Swabbing...................................................................................... B-6

1.3.1 Balled-Up Bottomhole Assembly .......................................... B-7 1.3.2 Pulling Pipe Too Fast .......................................................... B-7 1.3.3 Poor Mud Properties ........................................................... B-7 1.3.4 Heaving or Swelling Formations ........................................... B-7 1.3.5 Large OD Tools .................................................................. B-7

1.4 Not Keeping Hole Full................................................................... B-8 1.4.1 Use of Mud Log Unit ........................................................... B-8 1.4.2 Stroke Counter ................................................................... B-8 1.4.3 Pit Volume Monitoring ......................................................... B-8 1.4.4 Flowline Monitors ................................................................ B-9

1.5. Lost Circulation ............................................................................ B-9 1.5.1 High Mud Weight ................................................................ B-9 1.5.2 Going into Hole Too Fast..................................................... B-9 1.5.3 Pressure Due to Annular Circulating Friction ......................... B-9 1.5.4 Sloughing or Balled-Up Tools ............................................ B-10

1.5.5 Mud-Cap Drilling ............................................................... B-10 2.0 Detection of Kicks............................................................................. B-13

2.1 Positive Indicators of a Kick ....................................................... B-13 2.2 Secondary Indicators of a Kick ................................................... B-13 2.3 Indicators of Abnormal Pressure ................................................ B-13 2.4 Increase in Pit Volume ............................................................... B-14 2.5 Increase in Flow Rate ................................................................ B-14 2.6 Decrease in Circulating Pressure ............................................... B-14 2.7 Gradual Increase in Drilling Rate ............................................... B-15 2.8 Drilling Breaks ........................................................................... B-16 2.9 Increase in Gas Cutting .............................................................. B-17

2.9.1 Drilled Gas ....................................................................... B-17 2.9.2 Connection Gas ................................................................ B-17 2.9.3 Trip Gas ........................................................................... B-17

2.10 Increase in Chlorides.................................................................. B-18 2.11 Decrease in Shale Density .......................................................... B-18 2.12 Change in Cuttings Size and Shape............................................ B-18 2.13 Increasing Fill on Bottom after Trips........................................... B-18 2.14 Temperature................................................................................ B-18 2.15 Increasing Rotary Torque ........................................................... B-19 2.16 Tight Hole on Connections ......................................................... B-19

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1.0 Causes of Kicks

A kick is defined as any undesirable flow of formation fluids from the reservoir to the wellbore, which occurs as a result of a negative pressure differential across the formation face. Wells kick because the reservoir pressure of an exposed permeable formation is higher than the wellbore pressure at that depth. There are many situations, which can produce this unfavorable downhole condition. Among the most likely and recurring are:

• Low Density Drilling Fluid • Abnormal Reservoir Pressure • Swabbing • Not Keeping the Hole Full on Trips • Lost Circulation

These causes will be examined in detail in this section with emphasis placed on the human elements of avoidance.

1.1 Low Density Drilling Fluid

The density of the drilling fluid is normally monitored and adjusted to provide the hydrostatic pressure necessary to balance or slightly exceed the formation pressure. Accidental dilution of the drilling fluid with makeup water in the surface pits or the addition of drilled-up, low density formation fluids into the mud column are possible sources of a density reduction which could initiate a kick. Diligence on the mud pits is the best way to insure that the required fluid density is maintained in the fluids we pump downhole. Most wells are drilled with sufficient overbalance so that a slight reduction in the density of the mud returns will not be sufficient to cause a kick. However, any reduction in mud weight during circulation must be investigated and corrective action taken. A major distinction must be drawn between density reductions caused by gas cutting and those caused by oil or saltwater cutting.

1.1.1 Gas Cutting

The presence of large volumes of gas in the returns can cause a drop in the average density and hydrostatic pressure of the drilling fluid. However, the appearance of gas cut mud at the surface usually causes over concern, and many times results in unnecessary and sometimes dangerous over-weighting of the mud. The reduction of bottomhole pressure due to gas cutting at the surface is illustrated in the Table B.1.

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Table B.1 Effect of Gas-Cut Mud on Bottomhole Hydrostatic Pressure

Pressure Reduction (psi)

75 PCF Cut to 135 PCF Cut to 135 PCF Cut to Depth (ft) 37 PCF 121 PCF 67 PCF

1000 51 31 60 5000 72 41 82 10000 86 48 95 20000 97 51 105

Notice that the total reduction in hydrostatic pressure at 20,000 feet is only about 100 psi even though mud density is cut by 50 percent at the surface. This is because gas is very compressible and a very small volume of gas, which has an insignificant effect on mud density downhole, will approximately double in size each time the hydrostatic pressure is halved. Near the surface, this small volume of gas would have expanded many times resulting in a pronounced reduction of surface density.

It is interesting to note that most gas cutting occurs with an overbalanced condition downhole. For example, if a formation containing gas is drilled, the gas in the pore space of the formation is circulated up the hole along with the cuttings. The hydrostatic pressure of the gas in a cutting is greatly reduced as it moves up the annulus, allowing the gas to expand and enter the mud column. The mud will be gas cut at the surface, even though an overbalanced condition exists downhole. If the amount of ‘drilled gas’ is large enough, it is even possible that a well could be flowing at the surface as the gas breaks out and still have an overbalanced condition downhole. However, a flowing well is always treated as a positive indication that the well has kicked, and the well should be shut in immediately upon its discovery.

In a balanced or slightly overbalanced condition, gas originating from cuttings could reduce the bottomhole pressure sufficiently to initiate a kick. Gradual inc reases in pit level would be observed at first, but as the influx of gas caused by the underbalanced condition arrives at the surface, rapid expansion and pit level increase will occur. The well should be shut in and the proper kill procedure initiated. When gas cut mud causes a hydrostatic pressure reduction large enough to initiate a kick, the density of the mud being pumped downhole will usually not have to be increased to kill the well. This can be verified by shutting-in the well and confirming that the shut-in drillpipe pressure is zero.

1.1.2 Oil or Saltwater Cutting

Oil and/or salt water can also invade the wellbore from cuttings and/or swabbing, reduce the average mud column density, and cause a drop in mud hydrostatic pressure large enough to initiate a kick. However, since these liquids are much heavier than gas, the effect on average density for the same downhole volumes is not as great.

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Also, since liquids are only slightly compressible, little or no expansion will occur when circulating out these liquids. However, a given mud weight reduction measured at the surface due to oil and/or saltwater invasions will cause a much greater decrease in the bottomhole pressure than a similar mud which is cut by gas. This is because the density reduction is uniform throughout the entire mud column when it is cut by a liquid.

1.2 Abnormal Reservoir Pressure

Formation pressure is due to the action of gravity on the liquids and solids contained in the earth's crust. If the pressure is due to a full column of salt water with average salinity for the area, the pressure is defined as normal. If the pressure is partly due to the weight of the overburden and is therefore greater, the pressure is known as abnormal. Pressures below normal due to depleted zones or less than a full fluid column to the surface are called sub normally pressured. In the simplest case, usually at relatively shallow depth, the formation pressure is due to the hydrostatic pressure of formation fluids above the depth of interest. Salt water is a common formation fluid and averages about 67 pcf or 0.465 psi/ft. Therefore, 0.465 psi/ft is considered the normal formation pressure gradient. Normally pressured formations are usually drilled with about 70 to 75 pcf mud in the hole. For the formation pressure to be normal, fluids within the pore spaces must be interconnected to the surface. Sometimes a seal or barrier interrupts the connection. In this case, the fluids below the barrier must also support part of the rocks or overburden. Since rock is heavier than fluids, the formation pressure can exceed the normal hydrostatic pressure. During normal sedimentation the water surrounding the shale is squeezed out because of the addition of overburden pressure. The available pore space, or porosity, will decrease and, therefore, the density per unit volume will increase with depth. However, if a permeability barrier, or if rapid deposition prevents the water from escaping, the fluids within the pore space will support part of the overburden load, which results in above normal pressure. This scenario is depicted in Figure B.1.

Figure B.1 Abnormally Pressured Sand Formation

Figure B.1 Abnormally Pressured Sand Formation

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Another common cause of abnormal pressure is faulting. As can be seen in Figure B.2, a formation originally deposited under normal pressure conditions is uplifted 2,000 ft. The pressure within the uplifted section is trapped in the formation. The pressure in the formation is now abnormal for that depth. There may be no rig floor warning prior to drilling into an abnormal pressure zone of this nature.

Figure B.2 Abnormal Pressure Due To Faulting

Abnormal pressure can also occur as the result of depth and structure changes within a reservoir. As shown in Figure B.3, at 3,000 ft, the formation pressure at the gas-water contact is normal and equal to (0.465 psi/ft x 3,000 ft)=1,395 psi. However, at the top of the structure (2,000 ft) the formation is overpressured and approximately equal to 1,295 psi. Figure B.3 Abnormal Pressure Due To Folding

Figure B.2 Abnormal Pressure Due To Faulting

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Example: The pressure at 3,000 ft (1,395 psi) less a 1,000 ft gas column (1,000' x .1 psi/ft) equals 1,295 psi. The mud weight required at 2,000 ft to balance this formation is 1,295/(0.007 x 2,000') = 93 pcf.

Prior to drilling a particular well, all information regarding abnormally pressured zones should be gathered and on hand for the drilling engineer. Seismic data can often be helpful. Logs on nearby wells, along with the drilling reports of these wells, should be studied. If the well is a rank wildcat in a new area, no knowledge of pressures to be encountered may exist. In these cases pressure determination from techniques such as plotting the ‘dc’ exponent while drilling, and pore pressure calculations from electric logs run in the well are invaluable. Other warning signs are available while drilling and are discussed later in this section. Usually, abnormally pressured formations give enough warning that proper steps can be taken. As noted elsewhere in this guide, low mud weights provide the best indication of abnormal or high-pressure zones. Once these zones are detected, it is normally possible to drill into them a reasonable distance while raising the mud weight as necessary to control formation fluid entry. However, when pressure due to mud weight approaches the fracture gradient of an exposed formation, it is good practice to set casing. Failure to do this has been the cause of many underground blowouts and lost or junked holes. If abnormal pressure zones are drilled with mud weights insufficient to control the formation, a kick situation develops. This occurs when the pressure in the formation drilled exceeds the hydrostatic head exerted by the mud column. A pressure imbalance results and fluids from the formation are produced into the wellbore.

1.3 Swabbing

Swabbing is a condition, which arises when pipe is pulled from the well and produces a temporary bottomhole pressure reduction. In many cases, the bottomhole pressure reduction may be large enough to cause the well to go underbalanced and allow formation fluids to enter the wellbore. By strict definition, every time the well is swabbed in, it means that a kick has been taken. While the swab may not necessarily cause the well to flow or cause a pit gain increase, the well has produced formation fluids into the annulus, which have almost certainly lowered the hydrostatic pressure of the mud column. Usually, the volume of fluid swabbed in to the well is of an insignificant amount and creates no well control problems (e.g., a small amount of connection gas). Many times however, immediate action will need to be taken to prevent a further reduction in hydrostatic pressure, which could cause the well to flow on its own. It can be very difficult at times to recognize swabbing. The most reliable method of detection is proper hole filling. If a length of drillpipe composed of five barrels of metal volume is pulled from the well and the hole fill-up is only four barrels, a barrel of gas, oil, or salt water has possibly been swabbed into the wellbore. If swabbing is indicated, even if no flow is seen, the pipe should be immediately run back to bottom the mud circulated out, and the mud densified or conditioned before making the trip.

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A short trip is often made to determine the combined effects of bottomhole pressure reductions, which are due to the loss of equivalent circulating density and swabbing. When drilling under or near balanced conditions, a short trip is particularly important since it would quickly indicate a need to raise mud density or slow pulling speeds. Expansion of swabbed gas or flow from the formation later during the trip can be much more difficult to overcome, possibly requiring stripping back to bottom to kill the well. Many downhole conditions tend to increase the likelihood that a well will be swabbed-in when pipe is pulled. Several of these are discussed below.

1.3.1 Balled-Up Bottomhole Assembly

The drill string becomes a more efficient piston when drill collars, stabilizers and other bottomhole assembly components are balled-up. This causes a greater bottomhole pressure reduction, which can swab more fl uids into the wellbore. If the well is almost at balance, only a few vertical feet of fluid swabbed-in can cause the well to flow on its own.

1.3.2 Pulling Pipe Too Fast

The piston action is also enhanced when pipe is pulled too fast. The driller should be sure that the pipe is pulled slowly off bottom for a reasonable distance. However, the hole should be watched closely at all times to be sure it is taking the correct amount of mud.

1.3.3 Poor Mud Properties

Swabbing problems are compounded by poor mud properties, such as high viscosity and gels. Mud in this condition tends to cling to the drill pipe as it moves up or down the hole, causing swabbing coming out and lost circulation going in.

1.3.4 Heaving or Swelling Formations

Swabbing can result if the formations exposed either heave or swell, effectively reducing the diameter of the hole and clearance around the bit or stabilizers. In these formations even a clean bit acts like a balled bit or stabilizer.

1.3.5 Large OD Tools

Drill stem testing tools, fishing tools, core barrels, or large drill collars in small holes enhance swabbing by creating a piston action when the pipe is pulled too fast. Extra care should be taken whenever pulling equipment with close tolerances out of the hole.

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Good practices to prevent or minimize swabbing are aimed at keeping the mud in good condition, pulling pipe at a reasonable speed, and using some type of effective lubricant mud additive to reduce balling. Additives such as blown asphalt, gilsonite, detergent, and extreme pressure additives are effective in many cases. Good hydraulics will often help clean a balled-up bit or bottomhole assembly.

1.4 Not Keeping Hole Full

Blowouts that occur on trips are usually the result of either swabbing or not keeping the hole full of mud. Much progress has been made in prevention, but constant vigilance must be maintained. As drill pipe and drill collars are pulled from the hole during tripping operations, the fluid level in the hole drops. In order to maintain fluid level and mud hydrostatic pressure, a volume of mud equal to the volume of steel removed must be pumped into the annulus. An accurate means of measuring the amount of fluid required to fill the hole must be provided. The volume of steel in a given length of collars can be as much as five times the volume for the same length of drill pipe. The fluid level in the hole will also drop five times farther, and the reduction in bottomhole pressure will be five times as great. If the hole is normally filled after pulling fives stands of drill pipe, it may be necessary to fill the hole after pulling each stand of drill collars. As a general rule, the hole should always be filled on trips before the reduction in hydrostatic pressure exceeds 75 psi . It is the responsibility of the Drilling Foreman to see that the rig crews are thoroughly trained in the necessity of keeping the hole full. Many mechanical devices have been developed to aid in the task of keeping the hole full. These include:

1.4.1 Use of Mud Log Unit

These units are equipped with pump stroke counters, normally used for correlating well cuttings with depth. Counters can also be used during trips to aid in determining the proper amount of mud to keep the hole full and to detect swabbing. However, the mud log crews must be alerted to the need for this service during trips, when there is no logging.

1.4.2 Stroke Counter

These counters mounted near the driller’s position enable him to easily check his filling volume requirements. As the driller himself operates them, there should be no communication problem.

1.4.3 Pit Volume Monitoring

Bulk mud volume checking is also very helpful, but large pits will not show small changes; these can best be seen in a trip tank. The trip tank should be near the rig floor and calibrated so the driller can easily see and compare the volumes pumped into the hole vs. steel pulled out. If the trip tank cannot be monitored from the floor, an experienced crew hand should man it.

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1.4.4 Flowline Monitors

Besides monitoring flow while drilling, these devices detect fluid immediately when the hole fills, so that a good comparison is possible between pump strokes and returning fluid flow rate. Also, these devices detect no-flow when lost circulation occurs. Their proper use, in combination with other means, should prevent blowouts due to not keeping the hole full or swabbing. As flowline monitors can detect flow while the drill string is out of the hole, they should be left on continuously.

1.5 Lost Circulation

An important cause of well kicks is the loss of whole mud to natural and/or induced fractures and to depleted reservoirs. A drop in fluid level in the wellbore can lower the mud hydrostatic pressure across permeable zones sufficiently to cause flow from the formation. Some of the more common causes of lost circulation include: 1.5.1 High Mud Weight

If the bottomhole pressure exceeds the fracture gradient of the weakest exposed formation, circulation is lost and the fluid level in the hole drops. This reduces the effective hydrostatic head acting against the formations that did not break down. If the mud level falls far enough to reduce the BHP below the formation pressure, the well will begin flowing. Thus, it is important to avoid losing circulation. Should returns cease, loss of hydrostatic pressure can be minimized by immediately pumping measured volumes of water into the hole. Measuring the volumes will enable the drilling supervisor to calculate what weight of mud the formation will support without fracturing. Upon gaining returns, verify that the well is not flowing on its own.

1.5.2 Going into Hole Too Fast

Loss of circulation can also result from too rapid lowering of the drill pipe and bottom assembly (drill collars, reamers, and bit). This is similar to swabbing, only in reverse; the piston action forces the drilling fluid into the weakest formation. This problem is compounded if the string has a float in it and the pipe is large compared to the hole. Particular care is required when running pipe into a hole having exposed weaker formations and heavy mud to counter high formation pressure.

1.5.3 Pressure Due to Annular Circulating Friction

Another item to be considered when drilling with a heavy mud near the fracture gradient of the formation is the pressure added by circulating friction. This can be quite large, particularly in small holes with large drill pipes, or stabilizers inside the protective casing.

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It is sometimes necessary to reduce the pumping rate to lower the circulating pressure. This problem can become acute when trying to break circulation with high gel fluids.

1.5.4 Sloughing or Balled-Up Tools

Partial plugging of the annulus by sloughing shale can restrict the flow of fluids in the annulus. This imposes a back pressure on the formations below and can quickly cause a breakdown if pumping continues. Annular plugging is most common around the larger drillstring components such as stabilizers, so efforts to reduce balling will also diminish the chances of this type of lost circulation.

1.5.5 Mud-Cap Drilling

In general, good operating practice calls for regaining circulation before drilling ahead. However, in Saudi Aramco drilling operations there is one notable exception, mud-cap drilling. Mud-cap drilling permits continued drilling despite the presence of a pressured formation and a lost-circulation zone in the same interval of open hole. Although mud-cap drilling has been employed in a limited manner in other oil producing regions of the world, Saudi Aramco is unique in the routine application of this methodology.

Drilling with a floating mud-cap involves drilling ahead blind (i.e., without returns) by pumping different fluid densities down the drill string and annulus simultaneously. All fluid is lost to the thief zone, the Shu’aiba. Figure B.4 illustrates this procedure, indicating the intervals exposed during the mud-cap drilling operation. Employing a mud-cap in this manner provides the option of cotinued drilling to the next casing point, if circulation cannot be regained.

Note: The practice of drilling with a mud cap through hydrocarbon bearing reservoirs is not recommended, as a kick may not be controlled from surface (resulting in an underground blowout).

Mud-cap drilling is utilized because the troublesome Cretaceous interval, Wasia group and Shu’aiba must be penetrated before reaching pay in the Jurassic Arab formation, Sections A, B, C, and D. The Wasia group consists of a series of limestones, shales and sands. Some of these shales can be extremely water sensitive. In addition, some permeable members of the Wasia can be abnormally pressured. Compounding these drilling complications is the Shu’aiba limestone, which underlies the Wasia group and is subnormally pressured and extremely permeable. Given this situation, conventional drilling practice would suggest running and cementing casing at the top of the Shu’aiba, but employing mud-cap drilling permits drilling to continue to the top of pay.

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As noted above, the shale members of the Wasia can be extremely water sensitive. Contact with water or high fluid loss mud can cause them to swell rapidly and slough, resulting in stuck pipe. Therefore, it is a drilling imperative that water not be permitted to contact the Wasia shales. An added complication is that some permeable sand members of the Wasia can be abnormally pressured, requiring mud densities ranging between 75 pcf and 100 pcf to contain them, with the norm around 90 pcf. This abnormal pressure is evidenced by massive water flows. If unchecked, water flows from the Wasia would produce sloughing of water sensitive shales situated above and below the Wasia sand members. Since the Shu’aiba is subnormally pressured, an inexpensive low-density fluid is all that is required to drill it. In practice, fresh water (drill water) is used to drill through the Shu’aiba, and a low-solids, non-dispersed mud is used to mud-cap the Wasia. The mud-cap mud is virtually untreated and is thus relatively inexpensive for its density. Ideally then, in mud-cap drilling water is the only fluid to contract the Shu’aiba and mud-cap fluid is the only fluid to contact the Wasia.

A brief description of the typical mud-capping procedure follows. As drilling progresses, water is pumped down the drill pipe to remove cuttings from beneath the bit and around the bottomhole assembly. These cuttings and the water are lost to the lost circulation zone. Meanwhile, mud of a density just sufficient to kill the pressured zone is pumped slowly into the annulus. Thus, a critical balance of pressure control is maintained. In practice, 50 barrels of premixed mud-cap mud is pumped down the annulus as soon as circulation is lost to the Shu’aiba. Drilling proceeds blind (i.e., no returns), pumping water down the drill string and adding 10 barrels of mud-cap mud down the annulus every hour. If either partial or complete returns are regained while drilling, the pumps are shut down to determine whether the Wasia is flowing or if partial circulation has been restored. If it is determined that partial circulation is the case (i.e., the Shu’aiba is not taking all of the drill water), the Shu’aiba is intentionally broken down by squeezing mud-cap mud down the annulus to avoid drill water contacting any water sensitive shales. On the other hand, if the well is flowing, the mud-cap is not providing sufficient hydrostatic pressure on the Wasia. The remedy is either to increase the density of the mud-cap mud or increase the frequency of addition of mud down the annulus. This assumes the reduction of hydrostatic pressure is due to greater losses of mud per hour into the Shu’aiba than originally anticipated. Prior to any trip, the drill pipe is displaced with mud-cap mud. During a trip, 10 barrels of mud-cap mud are added every 10 stands or every 30 minutes, whichever is less. While pipe is out of the hole, 10 barrels of mud-cap mud are pumped down the hole every hour.

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Mud-capping a well is a mix of art and science, requiring deligent monitoring. If the pump rate down the drill string is too low, stuck pipe could result. Also, if pump rates down either side are excessive, mud losses and mud expenses can become prohibitive. Conversely, if either injection rate is insufficient, the well could kick. Fortunately, experience has defined the general range of applicable pump rates for Saudi Aramco’s drilling operations, as indicated in Fig. B.4.

Figure B.4 Mud Cap Drilling

During mud-cap drilling, all kicks or suspected kicks are handled by increasing the injection rate of mud-cap mud down the annulus, squeezing if necessary. If the well is still not dead at surface, the density of the mud-cap mud is increased until the well is killed at surface. Naturally, any water flows (i.e. kicks) simply flow into the Shu’aiba lost circulation zone. This practice has been used extensively over the years and has been demonstrated to be quite safe.

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2.0 Detection of Kicks

It is highly unlikely that a blowout or a well kick can occur without some warning signals. If the crew can learn to identify these warning signals and to react quickly, the well can be shut in with only a small amount of formation fluids in the wellbore. Smaller kick volumes decrease the likelihood of damage to the wellbore and minimize the casing pressures. Kick indicators are classified into two groups; positive and secondary. Any time the well experiences a positive indicator of a kick, immediate action must be taken to shut in the well. When a secondary indicator of a kick is identified, confirmation steps should be taken to verify if the well is indeed kicking. 2.1 Positive Indicators of a Kick

Positive Indicators of a Kick → Increase in Pit Volume → Increase in Flow Rate

The “Positive Indicators of a Kick” are shown to the left. Immediate action should be taken to shut-in the well whenever these indicators are experienced. It is not recommended to check for flow after a positive indicator or has been identified.

2.2 Secondary Indicators of a Kick

Secondary Indicators of a Kick → Decrease in Circulating Pressure → Gradual Increase in Drilling Rate → Drilling Breaks → Increase in Gas Cutting → Increase in Water Cutting or Chlorides

The “Secondary Indicators of a Kick” are shown to the left. The occurrence of any of these indicators should alert the Drilling Foreman that the well may be kicking, or is about to kick. These indicators should never be ignored. Instead, once realized, steps should be taken to determine the reason for the indication (indicating a flow check if necessary).

2.3 Indicators of Abnormal Pressure

Indicators of Abnormal Pressure → Decrease in Shale Density → Change in Cuttings Size and Shape → Increasing Fill on Bottom After a Trip → Increase in Flow Line Temperature → Increase in Rotary Torque

→ Increasing Tight Hole on Connections

“Indicators of Abnormal Pressure” are shown to the left. Observance of any of these indicators often means that the well is penetrating an abnormally pressured formation. Remedial action may range from increasing the mud weight to setting casing.

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The following describe these indicators in detail and prescribe the proper remedial action to take in the event of their occurrence.

2.4 Increase in Pit Volume

A gain in the total pit volume at the surface, assuming no mud materials are being added at the surface, indicates either an influx of formation fluids into the wellbore or the expansion of gas in the annulus. Fluid influx at the bottom of the hole shows an immediate gain of surface volume due to the incompressibility of a fluid, (i.e., a barrel in at the bottom pushes out an extra barrel at the surface). The influx of a barrel of gas will also push out a barrel of mud at the surface, but as the gas approaches the surface, an additional increase in pit level will occur due to gas expansion. This is a positive indicator of a kick and the well should be shut in immediately any time an increase in pit volume is detected. All additions to the mud system should be done with the driller's knowledge. He should also be told of each change in addition rate, particularly of water or barite. Any change in valve settings, which could affect fluid into or out of the system, should be noted and relayed to the driller. This is the only way to prevent unnecessary shut in of the well. Again, the driller should always shut the well in first and determine the reasons for a pit gain second.

2.5 Increase in Flow Rate

An increase in the rate of mud returning from the well above the normal pumping rate indicates a possible influx of fluid into the wellbore or gas expanding in the annulus. Flow rate indicators like the "FloSho" measure small increases in rate of flow and can give warning of kicks before pit level gains can be detected. Therefore, an observed increase in flow rate is usually one of the first indicators of a kick. This is a positive indicator of a kick and the well should be shut in immediately any time an increase in flow rate is detected. Positive readings of a shut-in drillpipe pressure indicate that the well will have to be circulated using the driller's or engineer's kill procedure. If the increase in flow was due to gas expansion in the annulus, the shut-in drillpipe pressure will read zero because no drillpipe underbalance exists.

2.6 Decrease in Circulating Pressure

Invading formation fluid will usually reduce the average density of the mud in the annulus. If the density of mud in the drillpipe remains greater than in the annulus, the fluids will U-tube. At the surface, this causes a decrease in the pump pressure and an increase in the pump speed. The same surface indications can be caused by a washout in the drillstring. To verify the cause, the pump should be shut down and the well checked for flow. If the flow continues, the well should be shut in and checked for drillpipe pressure to determine whether an underbalanced condition exists.

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2.7 Gradual Increase in Drilling Rate

While drilling in the normal pressured shales of a well, there will be a uniform decrease in the drilling rate. This assumes that bit weight, RPM, bit types, hydraulics and mud weight remain fairly constant. This decrease is due to the increase in shale density. When abnormal pressure is encountered, the density of the shale is decreased with a resultant increase in porosity. These higher porosity shales will be softer and can be drilled faster. Therefore, the drilling rate will almost always increase as the bit enters abnormally pressured shale. This increase will not be rapid but gradual. A penetration rate recorder simplifies detecting such changes. In development drilling, this recorder can be used with electric logs for the area to pinpoint the top of an abnormal pressure zone before any other indicators appears. In areas where correlation with other wells may be difficult, calculation and plotting of the “d” exponent can be helpful in detecting abnormal pressure. The “d” exponent is obtained from the basic drilling equation shown below. As penetration rate is affected by mud weight, a correction for actual mud weight must be made. This correction is made as shown in Equation B.1.

Equation B.1 ‘d’ Exponent Equation

Log ( )60N

R

dexp =

Log ( ) 1000

12W

where: R = Penetration Rate (ft/hr) W = Weight on Bit (m-lbs) Db = Bit Diameter (in)

N = Rotary Speed (rpm) dexp = Drilling Exponent

Corrected ‘d’ Exponents

67 dc = x dexp : for Saudi Aramco

Actual Mud Weight 62 dc = x dexp : for Hard Rock

Actual Mud Weight

db

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Figure B.5 dc versus Depth

Plotting dc versus depth would result in a plot similar to the one shown in Figure B.5.

Where the plot shifted left would be where abnormal pressure was encountered. If a mud logger is on location, he normally maintains a plot of this type.

2.8 Drilling Breaks

Abrupt changes in the drilling rate without changes in weight on bit and RPM are usually caused by a change in the type of formation being drilled. A universal definition of a drilling break is difficult, because of the wide variation in penetration rates, types of formations, etB. Experience in the specific area is required. In some sand-shale sequences, a break may be from 10 ft/hr to 50 ft/hr, or perhaps from 5 ft/hr to 10 ft/hr. In any case, while drilling in expected high-pressure areas, if a relatively long interval of slow (shale) drilling is suddenly interrupted by faster drilling, indicating a sand, the kelly should be picked up immediately, the pump is shut off, and the hole observed for flow. Very fast flow from the wellbore can result if permeability is high and mud weight is low. Then the well must be shut in immediately. If the permeable sand formation has only slightly higher pressure than the mud, flow may be difficult to detect. If there is doubt and drilling is in an expected pressure area, it may be best to circulate the

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break to the surface. If the sand is abnormally pressured, the gassy mud nearing the surface will expand, causing a rise in pit level. It may be necessary to control this expansion through the choke manifold, with the blowout preventer closed, then increase the mud weight before drilling ahead.

2.9 Increase in Gas Cutting

A gas detector or hot wire device provides a valuable warning signal of an impending kick. These instruments measure changes in the relative amounts of gas in the mud and cuttings, but do not provide a quantitative value. Increases in the gas content can mean increase in gas content of the formation being drilled, gas from cavings and/or an underbalanced pressure condition. Gas in the drilling mud is reported in several different ways.

2.9.1 Drilled Gas

This is the gas, which is entrained in the rocks, which are drilled. The drilled (or background) gas will usually increase as the bit penetrates abnormally pressured shale. Abnormally pressured shale gas will continue to feed in after all drilled-up gas has been removed from the mud. Occasionally drilled gas will be slow to drop out, but will finally do so if the mud weight is high enough to control the formation pressure.

2.9.2 Connection Gas

Connection gas is a measure of gas, which is either swabbed into the hole while pulling up for a connection or as a result of the loss in ECD while shutting the pumps off for a connection. It is reported in total units observed. Connection gas can be identified by estimating the time to pump mud from the bottom of the hole to the surface and checking the gas detector recording at that time. The connection gas will almost always increase when an abnormal pressure zone is penetrated. At low mud weights, the gas increase will be gradual. That is, one connection may show 20 units; the next, 30 units; and the third, 40 units. Mud weight increases may be necessary, even though there may be little or no change in background gas.

2.9.3 Trip Gas

The trip gas is very similar to connection gas except that it is a measure of swabbed gas over an entire trip. Often a short trip of 15-20 stands is made in order to circulate bottoms up and measure units of swabbed gas. Excessive units of trip gas could indicate the need for increasing the trip margin and/or reducing swab pressure. Failure to fill the hole on trips may also cause an increase in trip gas. The trip gas will generally increase when an abnormal-pressure section has been penetrated and the mud weight has not been raised. This alone is not a good indicator for abnormal pressure but is useful with the other indications. Trip gas should be reported as the total units observed.

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2.10 Increase in Chlorides

Invasion of the drilling mud by formation water can sometimes be detected by changes in the average density or the salinity of the mud returning from the annulus. Depending on the density of the mud, dilution with formation water will normally reduce average density. If the density of the invading fluid is close to that of the mud, the density would be unaffected, but perhaps a change in salinity will be apparent. This would depend on the salinity contrast between the formation fluid and the mud. Usually formation fluids are saltier than drilling muds and an influx can be detected by marked increases of chloride content of the mud filtrate. Chloride changes alone are not a good indicator of abnormal pressures but can be used in conjunction with other indicators to present a clearer picture.

2.11 Decrease in Shale Density

The shale density will generally decrease when an abnormal pressure zone is penetrated. This indicator would be good if it were possible to consistently select cutting samples and accurately measure their bulk densities. This decrease in density is a result of an increase in the water content within the shale.

2.12 Change in Cuttings Size and Shape

The amount of shale cuttings will usually increase, along with a change in shape, when an abnormal pressure zone is penetrated. Cuttings from normal pressured shales are small with rounded edges and are generally flat, while cuttings from an abnormal pressure often become long, splintery with angular edges. As the differential between the pore pressure and the drilling fluid hydrostatic pressure is increased, the pressured shales will explode into the wellbore rather than being drilled up. This change in shape, along with an increase in the amount of cuttings recovered at the surface, could be an indication that the mud hydrostatic pressure is too low and that a kick could occur while drilling the next permeable formation.

2.13 Increasing Fill on Bottom After Trips

Increasing fill on bottom after a trip, accompanied by an increase in trip gas, may indicate abnormally pressured shale. This condition can also be created by not filling the hole or poor mud properties during a trip, so it is not conclusive by itself.

2.14 Temperature

Flow line temperature often increases before an abnormal pressure zone is penetrated. This has been observed in many parts of the world, but can be tricky. Temperature also increases temporarily with the addition of barite or caustic, and by changes in hydraulics, such as hole size. Sharp, stable increases in temperature, possibly indicating abnormally pressured shale, are best seen on a relatively large-scale depth vs. temperature plot.

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2.15 Increasing Rotary Torque

Torque sometimes increases when an abnormal shale section is penetrated due to the pressured shales above the bit continuing to explode into the hole.

2.16 Tight Hole on Connections

A tight hole when making connections can indicate that abnormally pressured shale is being penetrated with low mud weight. Often the hole must be reamed several times before a connection can be made. Failure to suspect abnormal pressure when this occurs could lead to the drill pipe sticking or a blowout if drilling is continued without taking some corrective action.

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Drilling & Workover October 2002 __ SECTION C – TRIPPING PROCEDURES

Current Revision: October 2002 C - 1 3rd Edition Previous Revision: October 1998

Table of Contents

Introduction ................................................................................................C-2 1.0 Pulling Out of Hole (Tripping Out) ....................................................C-2

1.1 General Information .........................................................................................C-2 1.2 Procedures .......................................................................................................C-3

2.0 Running in the Hole (Tripping In)......................................................C-4 2.1 General Information .........................................................................................C-4 2.2 Procedures .......................................................................................................C-4

3.0 Trip Sheet............................................................................................C-6 4.0 Capacities and Displacements..........................................................C-7

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Introduction When running in and out of the hole with drill pipe (Tripping In and Out), it is essential to monitor the volume of fluid that is put in or removed from the hole through use of the trip tank. By comparing the drill pipe displacement volume with the mud volume, loss circulation or formation influx (kick) can be identified. See Section J of this manual for further information on trip tanks.

1.0 Pulling Out Of Hole (Tripping Out):

Prior to Tripping Out, ensure that the trip tank is about 75% to 85% full and note the volume on the gauge. Also, have a trip sheet available and ready to be filled out. All calculations of drill pipe and collar displacements should be done in advance of pulling operations. The major concern in pulling drill pipe out of hole is the possibility of taking a kick as a result of swabbing or not filling the hole properly.

1.1 General Information

1) When pulling the drill string out of hole, be aware of the hole fill-up difference between the drill pipe and the drill collars.

2) As a general rule, industry standards and various government regulations call for checking the trip tank volume after 5 stands for drill pipe, 3 stands for heavy weight drill pipe and every stand for drill collars or when the hydrostatic mud column pressure is reduced by 75 psi.

3) Leave drill pipe wiper rubber off pipe for first five stands to observe hole.

4) Since most fluid influxes or kicks occur during pulling the first 10 stands, it is important for the Drilling Foreman or Contract Toolpusher witness the operation. For more critical tripping out operations in high angle wells, the supervisors should be on the rig floor until the drill pipe is pulled into the casing.

5) If the well kicks at any time during the tripping operations, immediately

shut in the well using the correct shut-in procedures and record the pressure build-up on the drill pipe and casing. Do not run back to bottom if a kick is suspected or detected. Industry experience has shown that this practice is unsafe and can result in losing the rig.

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Note: 5 stands of 5” 19.5#/ft. drill pipe pulled from 9-5/8”, 53.5 #/ft. casing will lower the fluid level 56’ if there is no loss to or gain from the hole and the float is working properly. For example: 0.007645 bbl/ft. displacement in 0.070765 bbls/ft. capacity, (0.070765 – 0.007645)/0.007645 = 8.26’ of drill pipe pulled per foot of fluid drop in casing and inside drill pipe.

1.2 Procedures

1) Prior to pulling out of hole,

a) Ensure suitable safety valves and crossovers are available on the rig floor, including a closing/opening wrench.

b) Condition the mud and perform a flowcheck to ensure the well is dead.

Duration of the flowcheck will vary according to formation and mud characteristics but should be long enough to ensure the well is dead. If the hole is taking fluid and is open to a potential hydrocarbon producing zone, obtain approval from the Superintendent prior to pulling out of hole.

2) Pull out of hole with the drill string and record the Trip Tank gauge data on

the Trip Sheet (Page C-7) every 5 stands for drill pipe, 2 stands for heavy weight drill pipe and every stand for the drill collars. The hole is continuously and automatically being filled by the trip tank pump.

3) Check the Trip Sheet data often to ensure the well has not taken a kick.

This is done by comparing the amount of mud required to fill the hole with the displacement volume of the pulled string.

4) While tripping out, refill the trip tank with mud and record the new volume

when the trip tank mud volume becomes low or when there is a break in the operations. Do not trip pipe while filling the trip tank.

5) Perform a flowcheck at the casing shoe and just before pulling into the

BOPs with the bottom hole assembly.

WELL CONTROL MANUAL



2.0 Running into the Hole (Tripping In):

Prior to Tripping In, ensure that the trip tank is empty and that the trip tank gauge is functioning properly, set at “0”. Also, have a trip sheet available and ready to be filled out. All calculations of drill pipe and collar displacements should be done in advance of tripping operations. The major concerns in running drill pipe in hole are:

1) The possibility of breaking the formation down due to surging, losing mud

column and thus taking a kick, and 2) If a small gas bubble is slowly moving up the hole, the running of drill

collars through it will cause the bubble to string out, displace mud out of hole, lower the hydrostatic pressure and cause a kick.

2.1 General Information

1) When running the drill string into the hole, be aware of the hole fill-up difference between the drill pipe and the drill collars.

2) As a general rule, industry standards and various government regulations

call for checking the trip tank volume after every 5 stands for drill pipe, 3 stands for heavy weight drill pipe and every stand for drill collars.

3) If the well kicks at any time during the tripping operations, immediately

shut in the well using the correct shut-in procedures and record the pressure build-up on the drill pipe and casing. Do not run back to bottom if a kick is suspected or detected. Industry experience has shown that this practice is unsafe and can result in losing the rig.

2.2 Procedures

1) Run into hole at approximately 1 stand per minute while filling the drill

string every 10 to 20 stands or when there is a break in the operation. For casing, fill hole every joint while running in hole and top off every 10 joints.

2) Control tripping speed to prevent excessive surge pressure. If potential for

loss circulation or excessive fluid loss exists, break circulation (as often as required) prior to reaching the potential loss zone.

3) While running in hole, record the Trip Tank gauge data on the Trip Sheet

every 5 stands for drill pipe, 2 stands for heavy weight drill pipe and every 1 stand for drill collars, and ensure the absence of loss circulation or kick every 10 stands. The mud in the hole is continuously unloaded as the drill string is run in hole.

WELL CONTROL MANUAL



4) While tripping in, empty the trip tank when getting full or when there is a break in the operations. Do not trip pipe while emptying the trip tank.

5) Check the Trip Sheet data often to ensure the well does not lose circulation or kick. This is done by comparing the amount of mud filling the trip tank with the displacement volume of the string in hole.

6) Once on bottom, circulate mud only if hole conditions dictate.


3.0 TRIP SHEET RIG:__________ Well No: ______________ ________________________________________________________________________________________________________________________________ Tripping: In Out Driller: _____________________ Date: ___________ Start Time: __________

Depth: ____________ Hole Size: __________ Trip Tank Increments: _____bbls/inch

String Size & Type Total

Stands Displacement Bbls/foot Displacement/Std.

Bbls/93 feet Displacement/5 Stds. Bbls/465 feet Capacity

Bbls/ft. Dry Wet Dry Wet Dry Wet 3-1/2” DP 5” DP 5-1/2” DP 3-1/2” HWDP 5” HWDP 5-1/2” HWDP 4-3/4” DC 6-1/4” DC 8-1/2” DC 9-1/2” DC

COMPARISON BETWEEN ACTUAL AND CALCULATED STRING DISPLACEMENT (A)

Stands (B)

String Size & Type

(C) Trip Tank Gauge Reading (bbls)

(D) Actual Mud from

Trip Tank (bbls)

(E) Calculated

(bbls)

(F) Difference (D) – (E) (bbls)

(G) Running

Total (bbls)

TOTAL Tripping In or Out: If column (F) is negative, well is taking a kick (influx). If column (F) is positive, well is losing

circulation.


4.0 Capacities and Displacements Capacities and Displacements

Pipe Displacementbbl./ft.

Displacement bbls/93. ft. stand

Capacity bbl./ft.

Tubular Type

Size inches

Weight lbs/ft.

Coupling & Thread

Tubing * 2-3/8 4.7 8rd, EUE 0.0016 0.1488 0.0039 2-7/8 6.5 8rd, EUE 0.0022 0.2046 0.0058 3-1/2 9.3 8rd, EUE 0.00320 0.2976 0.0087 3-1/2 12.95 L-80, PH-6 0.00455 0.4232 0.0074 Drill Pipe 2-3/8 6.65 0.0028 0.298 0.0032 3-1/2 13.3 0.0049 0.456 0.0072 5 19.5 0.0076 0.707 0.0177 5 26.5 0.0098 0.911 0.0153 5-1/2 24.7 0.0095 0.8835 0.0208 HWDP 3-1/2 25.6 0.0092 0.8556 0.0042 5 x 3 50 0.0184 1.710 0.0087 5-1/2 64.2 0.0203 1.888 0.0091 Drill Collars 3-1/2 x 1-1/2 0.0097 0.0022 4-3/4 x 2 0.0181 0.0039 6-1/4 x 2-7/8 0.0330 0.0080 7-1/4 x 2-1/4 0.046 0.0049 8-1/4 x 2-1/2 0.0583 0.0061 8-1/2 x 2-7/8 0.0613 0.0080 9-1/2 x 2-1/2 0.0884 0.0061 10 x 3 0.0884 0.0087 Casing * 24 176 X42,RL4S 0.0616 0.4971 24 97 GR-B, SJ 0.0344 0.5251 18-5/8 115 K55, BTC 0.0418 0.2953 18-5/8 87.5 K55, BTC 0.0307 0.3062 13-3/8 86 95HS, NS-CC 0.0302 0.1399 13-3/8” 72 95HS, NS-CC 0.0257 0.1480 13-3/8 68 J/K55,BTC 0.0241 0.1497 13-3/8” 61 J/K55,STC 0.0216 0.1521 9-5/8 58.4 110HS, NS-CC 0.0209 0.0691 9-5/8 53.5 90HSS, NS-CC 0.0192 0.0707 9-5/8 47 L-80,LTC 0.0168 0.0732 9-5/8 43.5 L80, LTC 0.0155 0.0744 9-5/8 40 J/K55, L80 LTC 0.0142 0.0758 9-5/8 36 J/K55, LTC 0.0127 0.0773 7 35 L-80, LTC 0.0126 0.0350 7 35 L-80, New VAM-MS 0.0126 0.0350 7 32 C-95VTS, New VAM-MS 0.0115 0.0361 7 32 NT-95HSS, NS-CC 0.0115 0.0361 7 26 J/K55, New VAM-MS 0.00934 0.0382 7 26 J/K55, LTC 0.00934 0.0382 7 23 J55, LTC 0.00823 0.0393 5-1`/2 20 95HSS,NS-CC 0.00721 0.0221 5 15 L80, 13CR, BTC 0.00541 0.0188 5 15 K55, BTC 0.00541 0.0188 4-1/2 13.5 95HSS, NS-CC 0.00474 0.0149 4-1/2 11.6 J-55, OLD VAM 0.00413 0.0155 4-1/2 11.6 J-55, STC 0.00413 0.0155 Open Hole 34 1.1230 30 0.8743 28 0.7616 24 0.5595 22 0.4702 17-1/2 0.2975 17 0.2807 12-1/4 0.1458 12 0.1399 10-3/4 0.1123 8-1/2 0.0702 8-3/8 0.0681 6-1/8 0.0364 6 0.0350 5-7/8 0.0335

* Displacement figures for tubing and casing do not include connections. Displacement figures for DP and HWDP include tool joints.

WELL CONTROL MANUAL


SECTION D – SHUT-IN PROCEDURES

Current Revision: October 2002 D - 1 3rd Edition Previous Revision: October 1998

Table of Contents

1.0 Minimize the Size of the Influx ...........................................................D-2 2.0 Shut-In Procedure while Drilling .......................................................D-3 3.0 Post Shut-In Procedure while Drilling .............................................D-3

3.1 Shut-In Casing Pressure (SICP) ......................................................D-3 3.2 Shut-In Drillpipe Pressure (SIDP)....................................................D-4 3.3 Pit Gain ...........................................................................................D-4 3.4 Time................................................................................................D-4 3.5 Closing Pressure ............................................................................D-4

4.0 Shut-In Procedure while Tripping.....................................................D-4 5.0 Post Shut-In Procedure while Tripping ...........................................D-6

5.1 Shut-In Casing Pressure (SICP) ......................................................D-6 5.2 Pit Gain ...........................................................................................D-6 5.3 Time................................................................................................D-6 5.4 Bit Depth .........................................................................................D-6 5.5 Well Control Options for Ki ck w/Bit off Bottom ..............................D-7

6.0 Bumping the Drillpipe Float................................................................D-8 7.0 Understanding SICP and SIDP...........................................................D-9 8.0 Differential Pressure Sticking ..........................................................D-10 9.0 Failure of Blowout Prevention Equipment ...................................D-10

WELL CONTROL MANUAL




1.0 Minimize the Size of the Influx

Early recognition of a kick and rapid shut in are the keys to effective well control. By taking action quickly, the amount of formation fluid that enters the wellbore and the amount of drilling fluid expelled from the annulus are minimized. As Figure D.1 illustrates, smaller kicks provide lower initial shut-in casing pressure and lower maximum casing pressures while circulating out the kick. This translates to lower casing shoe pressures at all points during the circulation and reduces the chance of formation breakdown and an underground blowout.

Figure D.1 Effect of Influx Size on Casing Pressure

Note: The larger the influx, the higher the casing pressures; therefore, minimize the size of the influx.

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2.0 Shut-In Procedure while Drilling

Drilling crews must be alert while drilling ahead and be on the lookout for indicators that the well is kicking or that the bit is penetrating abnormal pressure. (These items were discussed in detail in Section C). The well must be shut in immediately when there is a positive indicator of a kick in the form of an increase in pit volume or flow rate. If a secondary indicator of a kick is recognized then the well should be checked for flow before shutting in.

Shut-in Procedure while Drilling

(1) SPACE OUT Pick up drill string and spot tool joint.

(2) SHUT DOWN Stop the mud pumps.

(3) SHUT IN Close the annular preventer or uppermost pipe ram preventer. Confirm that the well is shut in and flow has stopped. Open HCR valve.

The person most likely to shut in the well is the Driller. The Saudi Aramco Drilling Foreman must make sure that the driller is trained and will be able to take the initiative to perform this important function on his own without prompting or assistance. After the well is securely shut in, the Driller should notify the Drilling Foreman and Contract Tool pusher. At this time, all members of the drilling crew should be at their pre-determined stations awaiting further instructions. Saudi Aramco requires a Hard Shut-in Procedure . This means that the choke line valves on the drilling spool are in the closed position while drilling and remain closed until after the preventer is sealed and well shut-in. In the ‘soft shut -in’ procedure, the choke line valves are opened to allow the well to flow through the surface choke. After the preventers are sealed, the choke is then closed to stop the flow. The ‘soft shut-in’ procedure gives the well additional time to flow before shut-in. Therefore, it is not recommended because it doesn’t minimize the size of the influx.

3.0 Post Shut-In Procedures while Drilling

After the well has been shut in, the Drilling Foreman has several items to read and record. These include:

3.1 Shut-In Casing Pressure (SICP)

Read and record the shut-in casing pressure. Valves on the drilling spool and choke manifold will need to be lined-up so that wellbore pressure is transmitted to the closed drilling choke. The shut-in casing pressure should be read from a gauge installed upstream of the closed choke.

WELL CONTROL MANUAL




3.2 Shut-In Drillpipe Pressure (SIDP)

Read and record the shut-in drillpipe pressure. If no float is in the drillstring, this pressure can be read directly from a pressure tap on the standpipe manifold. Since it is recommended practice however, most drillstrings should have floats installed, which will require bumping in order to determine the SIDP. The float bumping procedure is given later in this section.

3.3 Pit Gain

Read and record the pit gain. The amount of influx is important for accurate calculation of the maximum casing pressure. Pit level charts or other volume totalizers can be examined to determine the pit gain.

3.4 Time

Make a note of the time the kick occurred. Also, keep an accurate log of the entire kill operation as it progresses.

3.5 Closing Pressure

The proper amount of closing pressure will depend on the size and make of the preventer and the wellbore pressure underneath. The closing pressure should be high enough to prevent wellbore fluid from leaking by the element.

After this information has been gathered, the Drilling Foreman should notify his supervisor to discuss the appropriate method for killing the well.

4.0 Shut-In Procedure while Tripping

Statistics indicate that the majority of kicks occur while tripping. Pulling out of the hole is a critical operation, which warrants extra well control diligence by the drilling crews. This is not the time to be lax about well control! Hole filling and hole monitoring equipment should be in top condition so that a kicking well can be detected as early as possible. You should prepare for a trip with the same intensity as you prepare to penetrate a known abnormal pressure zone. Be prepared for the well to kick on every trip. Every time a well is swabbed-in, it takes a mini-kick; formation fluids enter the wellbore as a result of a negative pressure differential generated by the swabbing effect. The well may not continue to flow after the pipe is stopped, but formation fluids have entered the annulus and reduced the hydrostatic pressure. If the well continues to swab-in on successive stands, then the hydrostatic pressure in the annulus may be sufficiently reduced to allow the well to flow when the pipe is stationary. For this reason, any time swabbing is indicated during a trip, the drillpipe should be run back to bottom and the well circulated at least to bottoms-up.

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Furthermore, any time the well is detected to be flowing during a trip, it must be shut in immediately using the following "Three S" Shut-In Procedure:

Shut-In Procedure while Tripping (1) STAB VALVE Install Full-Open Safety Valve (open position) in drill string.

Close Safety Valve. (2) SPACE OUT Spot tool joint. (3) SHUT- IN Close the annular preventer or uppermost pipe ram

preventer. Confirm that the well is shut-in and flow has stopped. Open HCR valve.

Shut-In Procedure with BHA across Stack

(1) SET SLIPS Set slips on drill collars across BOP stack. (2) INSTALL XO Install crossover to Full-Open Safety Valve. (3) STAB VALVE Stab Full-Open Safety Valve (open position) in drill

string. Close Safety Valve. (4) SHUT –IN Close annular. Confirm well is shut-in and flow is

stopped. (5) INSTALL INSIDE BOP Install inside BOP. Open Safety Valve. (6) MU DRILL PIPE Make-up a stand of drillpipe. Reduce closing

pressure on annular and strip-in stand of drill pipe.

In the event of a failure in the annular (with BHA across BOP stack) and uncontrolled flow, the emergency response should consist of dropping the BHA and shutting in the well with blind rams.

Note: It is recommended that these Shut -In Procedures be followed even when the rig is equipped with a top drive unit. The temptation would be to screw in the tope drive unit instead of the safety valve hoping that it would be quicker and safer. This can be problematic if it is necessary to strip and the float leaks. The manual valve on the top drive unit will not necessarily be strippable and it may not be possible to install the inside BOP on top of it.

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5.0 Post Shut-In Procedures While Tripping

Taking a kick while tripping is a severe well control complication. Because there is no steady-state while tripping, the data that was previously relied upon to kill the well may not be valid. Nevertheless, after the well is securely shut in, the Drilling Foreman will need to gather as much information about the wellbore condition as possible. These will include:

5.1 SICP

Read and record the shut-in casing pressure. Valves on the drilling spool and choke manifold will need to be lined-up so that wellbore pressure is transmitted up to the closed drilling choke. The shut-in casing pressure should be read from a gauge installed upstream of the closed choke.

5.2 Pit Gain

Read and record the pit gain. The amount of influx is important for accurate calculation of the maximum casing pressure. If a trip tank is in use and an accurate trip log was being maintained, then the pit gain is simply the difference between the present trip tank volume and the volume after the last fill-up, plus the volume of metal pulled from the well since the last fill -up. If the hole was being filled out of the active pits, which is not recommended, then determination of the kick volume is much more difficult. Pit level charts or other volume totalisers can be examined in an attempt to determine the pit gain in these instances.

5.3 Time

Make a note of the time the kick occurred. Also, keep an accurate log of the entire kill and/or stripping operation as it progresses.

5.4 Bit Depth

Determine the bit depth from the Driller’s pipe figures. This number is important for a variety of calculations and determinations discussed later in this section.

Note: It will usually not be necessary to record a value for the shut-in drillpipe

pressure. This is because the mud weight does not usually have to be increased when a kick is taken during a trip unless the well is going to be killed off-bottom. However, if a shut -in drillpipe pressure is taken, then allowances must be made for the volume of drillpipe slug remaining in the pipe. If this volume cannot be determined, then an accurate value for shut-in drillpipe cannot be calculated.

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5.5 Well Control Options for Kick with Bit Off Bottom After the post shut-in information has been gathered, the Drilling Foreman should consult with the Drilling Superintendent to determine the proper action to take in controlling the well while off bottom. This will usually involve stripping, although bullheading may be a consideration.

BULLHEADING Consider bullheading if,

a) The kick was detected with the bit a considerable distance off bottom.

b) Bullhead pressure does not exceed the MASP (for casing burst, surface equipment limitations. ‘down weight’ of the drilling string in hole, or leak-off pressure at casing shoe).

Bullheading will be discussed further in Section E.

STRIPPING Consider stripping to bottom based on SICP, distance off bottom, and available BOP stack as described below,

a) SICP is 1000 psi or less, strip with annular preventer.

b) SICP is 1000-1500 psi and < 1000’ off bottom. strip with annular.

c) SICP is 1000-1500 psi and > 1000’ off bottom, strip with annular and ram preventer combination.

d) If SICP is 1500 psi or more, strip with ram preventer combination.

Stripping procedure,

a) Install Inside BOP

b) Open Safety Valve

c) Adjust hydraulic closing pressure to minimize excessive wear in BOP elastomers.

d) Bleed off appropriate annular volume per stand by maintaining a constant SICP during stripping.

e) Fill drillpipe accordingly while stripping.

f) Kill well with Driller’s Method once on bottom. Stripping will be discussed further in Section O.

WELL CONTROL MANUAL




6.0 Bumping the Drillpipe Float

If a drillpipe float is installed, the pressure gauge on the drillpipe will read near zero. In order to obtain an accurate value for the shut -in drillpipe pressure, the float will have to be bumped open by slowly pumping down the drillpipe. The correct procedure for bumping the float is given below.

Float Bumping Procedure

(1) Make sure the well is shut in and that the shut-in casing pressure is recorded.

(2) Slowly pump down the drillpipe while monitoring both the casing and drillpipe pressure.

(3) The drillpipe pressure will increase as pumping is begun. Watch carefully for a

lull in the drillpipe pressure (a hesitation in the rate of increase) which will occur as the float is pumped off of its seat. Record the drillpipe pressure when the lull is first detected.

(4) To verify that the float has been pumped open, continue pumping down the

drillpipe very slowly until an increase in the casing pressure is observed. This should occur very soon after the lull was observed on the drillpipe gauge.

(5) Shut down the pumps as soon as the casing pressure starts to increase and

record the shut -in drillpipe pressure as the previously recorded pressure at the time of the lull in Step 3 above (not the final drillpipe pressure after the pumps are stopped).

(6) Check the shut-in casing pressure again. Any excess pressure may be bled-

off in small increments until equal readings are observed after two consecutive bleed-offs. Do not allow the casing pressure to drop below its original shut-in value while bleeding back.

The float bumping procedure as described above can be difficult if the rig has big duplex pumps which are compounded. It may be necessary to clutch the pumps in short bursts to slowly build up pressure on the drillpipe. A drillpipe lull may never occur before the casing pressure starts to increase when using this procedure. To determine the shut-in drillpipe pressure in these instances, subtract the increase in shut-in casing pressure from the final value of shut-in drillpipe pressure after the pumps have been stopped. Use this value as the official shut-in drillpipe pressure.

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7.0 Understanding SICP and SIDP Shut-in surface pressures depend mostly on the amount of underbalance and the amount and density of the influx of formation fluids. Shut-in drillpipe and casing pressure indicate the difference between formation pressure and the hydrostatic pressures in the drillpipe and annulus respectively. Both shut-in pressures are affected equally by the amount of underbalance. More specifically, the greater the difference between formation pressure and hydrostatic pressure, the larger will be the shut-in pressures. Higher shut-in casing pressures can cause formation breakdown in this instance. In order to decrease the likelihood of excessive downhole pressures and the resultant breakdown at the casing seat, early detection and quick closure of the preventers are essential. Normally, the shut-in casing pressure is greater than the shut-in drillpipe pressure because of the low-density formation fluids in the annulus. In this case, the total hydrostatic pressure in the annulus is less than that in the drillpipe, so it requires a higher shut-in casing pressure to balance formation pressure. The difference in hydrostatic pressures between the annulus and drillpipe depends not only on volume (height) of the influx, but also on its density. The shut-in casing pressure for a gas kick is much higher than for a saltwater and/or oil kick of equal volume. Often, the shut-in drillpipe and casing pressures will read the same when the well is closed in with the bit off bottom and all or most of the formation fluids are below the bit. In this case, the reduction of hydrostatic pressure caused by the influx of low-density formation fluids affects the drillpipe and casing pressures equally. A similar condition will occur with a hole in the drillpipe and with all of the influx trapped below the hole. When considering the effects of underbalance and size of influx on downhole pressure, the position of the influx fluid in relation to the depth of interest must be considered. If the depth of interest is above the kick, the full amount of the shut-in casing pressure must be added to the mud hydrostatic pressure to that depth. If, however, the depth of interest is within the interval of the kick or below, then the total effect of surface pressure on the depth of interest is less. This also applies during the time that the kick fluid is circulated out of the hole. For example, the shoe pressure at a shallow casing seat will normally increase while circulating out a gas kick until the gas reaches the casing seat. At this point, the shoe pressure will drop until the gas is in the casing. From this point, until all the gas is removed from the annulus, the shoe pressure at the casing seat will be constant. The location of the kick fluid in the annulus with respect to the depth of interest will determine the effect of excessive casing pressure on the shoe pressure.

WELL CONTROL MANUAL




8.0 Differential Pressure Sticking The drillstring can become stuck immediately after the well is shut -in on a kick. Sometimes this can be attributed to collapse of the filter cake and/or wellbore caused by the presence of formation fluids. More often, it is due to differential pressure sticking of the drillpipe in lower pressured formations uphole. Large shut-in casing pressures cause an increase in the wellbore pressures above the influx. This serves to increase the pressure differential across permeable zones, which leads to differential sticking. Do not work pipe during the kill operation in an attempt to avoid differential sticking. Kill the well first and then address stuck pipe later, if required. Reducing mud weight to pore pressure equivalent in order to free differentially stuck pipe is against Saudi Aramco Policy. A minimum overbalance shall be maintained during all operations as shown below,

• 100 psi overbalance on water reservoirs • 200 psi overbalance on oil wells • 300 psi overbalance on gas wells

9.0 Failure of Blowout Prevention Equipment

In case of a failure in the upper pipe rams, the bottom master pipe rams shall be closed, repairs made to the upper rams, and well kill continued. Vulnerable rubber parts (as bonnet seals, top seal, and ram packers) can fail under severe well conditions (H2S, C02 and temperature). Replacement OEM parts must be on the rig site.

WELL CONTROL MANUAL

Drilling & Workover October 2002 __ SECTION E – WELL KILLING PROCEDURES

Current Revision: October 2002 E - 1 3rd Edition Previous Revision: October 1998

Table of Contents 1.0 Constant Bottomhole Pressure .................................................. E-2 2.0 The U-Tube Principle ................................................................... E-2

2.1 Basic Well Control Equations (Static Conditions) .............................E-3 2.2 Basic U-Tube Concept ..........................................................................E-4

3.0 The Driller’s Method .................................................................... E-6 4.0 The Engineer’s Method ............................................................... E-6 5.0 Comparison of the Methods ....................................................... E-8 6.0 Other Well Control Methods.......................................................E-10

6.1 The Volumetric Control Method.........................................................E-10 6.2 The Low Choke Pressure Method .....................................................E-10 6.3 Bullheading..........................................................................................E-11

7.0 Underground Blowout ................................................................E-12 7.1 Barite Plugs .........................................................................................E-13

WELL CONTROL MANUAL



1.0 Constant Bottomhole Pressure

Saudi Aramco recommends two well killing methods; the Driller’s Method and the Engineer’s Method. Both of these methods are discussed later in this section. These methods are designed to remove the influx from the wellbore while maintaining a constant bottomhole pressure equal to or slightly greater than the formation pressure. These procedures prevent additional influx from entering the well while the kick is being circulated out. Constant bottomhole pressure is maintained by pumping at a constant kill speed and using the drillpipe and casing pressure gauges to monitor the bottomhole pressure. The surface pressures on both gauges are adjusted by manipulation of the drilling choke orifice size. The constant bottomhole pressure method offers several advantages. It allows the person controlling the kick to observe or to calculate pressures throughout the system. It provides the minimum pressure needed to balance the reservoir pressure, which lessens the chances for a second fluid influx, yet holds surface pressures low enough to prevent formation breakdown and lost circulation. All methods discussed in this guide, except for volumetric control, require circulation to remove the influx and kill the well. In each case, efforts are made to maintain a constant bottomhole pressure by adjusting the combination of surface and hydrostatic pressures. As discussed in Section A 1.6, when circulating through a well, bottomhole pressure is increased due to annular friction and is expressed as equivalent circulating density (ECD). As the value of equivalent circulating density (ECD) is very difficult to calculate and can vary greatly from one situation to another, the effect of equivalent circulating density (ECD) is not taken into account in any of the methods. The point to remember is that equivalent circulating density (ECD) will be in effect when performing these methods, thus holding more back-pressure than required:

• Is not necessary to prevent taking an additional influx • Could result in formation breakdown and lost circulation

2.0 The U-Tube Principle A thorough understanding of the relationship between bottomhole pressure, casing pressure and drillpipe pressure is necessary to effectively use the well control procedures discussed in this volume. Perhaps the best way to illustrate this relationship is through the concept of a U-tube.

WELL CONTROL MANUAL



Figure E.1 shows the cross section of two vertical tubes of the same size connected at the base by a horizontal tube. When a fluid of uniform density is added to the system, the levels will equalize in columns A and B. This assembly is often referred to as a U-tube because its shape resembles the letter U. The U-tube is a convenient way to represent conditions in the wellbore with drillpipe in the hole. The inside of the drillpipe can be represented by column A and the annulus by column B. The opening at the base of the U can be thought of as the opening through the nozzles in the bit. The pressure at the bottom of column A is equal to the pressure at the bottom of column B, which can be thought of as the bottomhole pressure.

Figure E.1 Simple U-Tube Analogy

2.1 Basic Well Control Equations (Static Conditions)

Two equations, provided earlier, are needed to understand and explain the concept of the U-tube. These are shown again below.

Bottomhole Pressure = Hydrostatic Pressure + Surface Pressure

Hydrostatic Pressure = 0.007 x Mud Weight x True Vertical Depth

WELL CONTROL MANUAL



2.2 Basic U-Tube Concept In all U-tubes where the fluid levels are static, the bottomhole pressure generated by column A is equal to the bottomhole pressure generated by column B. This relationship is stated mathematically as:

Basic U-Tube Concept

Hydrostatic Pressure (Column A) + Surface Pressure (Column A)

is equal to

Hydrostatic Pressure (Column B) + Surface Pressure (Column B)

is equal to

Bottomhole Pressure

U-tubes are rather boring when the same density fluid fills both columns. In this instance, the hydrostatic pressure and surface pressure of both columns are equal. Such is the case when a bit is run to the bottom of the hole and the drillpipe and annulus are filled with the same weight drilling mud. The fluid levels remain static at the top of the well, the surface pressure on both the casing and drillpipe side is zero, and the hydrostatic pressure on the drillpipe side is equal to the hydrostatic pressure on the casing side. U-tubes get very interesting when fluids of different densities occupy both columns. In these instances, both the hydrostatic pressure and surface pressure of both columns are likely to be different. Such is the case when a kick is taken with the bit on bottom. The well kicked because the bottomhole pressure was greater than the hydrostatic pressure generated by the mud in the well. When the well is shut in, the well stops flowing, and the amount of pressure under-balance is reflected as a surface pressure on the drillpipe gauge. However, the fluid in the annulus is no longer composed of drilling mud alone; it also includes lighter weight formation fluid, which reduces the total hydrostatic pressure in the annulus. Therefore, the annulus side is more under-balanced than the drillpipe side, so the resultant shut-in casing pressure is higher than the shut-in drillpipe pressure. This effect is shown in Figure E.2.

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In Figure E.2, a 10,000 ft. well with 75 pcf mud has penetrated an over pressured sand with a reservoir pressure of 5,740 psi and taken a 30 bbl kick. Since the hydrostatic head of the 75 pcf mud is only 5,250 psi (10,000' x 75 pcf x 0.007 = 5,250 psi), the drillpipe is under-balanced by 490 psi which is reflected on the shut-in drillpipe gauge and at the top of column A of the U-tube. The hydrostatic pressure on the annulus side is equal to the sum of the hydrostatic pressure of the mud in the annulus and the hydrostatic pressure of the gas in the annulus. Since 30 barrels of annular mud has been displaced by the lighter weight gas, there is less total hydrostatic pressure in the annulus than in the drillpipe. The hydrostatic pressure generated by 30 barrels of mud is 140 psi more than the hydrostatic pressure generated by 30 barrels of gas in this wellbore configuration. Therefore, the shut-in casing pressure and the pressure at the top of column B is 140 psi higher than the value indicated on the drillpipe gauge.

Figure E.2 Example of U-Tube Effect

WELL CONTROL MANUAL



3.0 The Driller’s Method The Driller’s Method of well control requires two complete and separate circulations of the drilling fluid in the well. The first circulation removes the influx from the annulus using the mud density in the hole at the time of the kick. Casing pressure is held constant until the pump is at kill rate. Then drillpipe pressure is held constant to maintain bottomhole pressure equal to, or slightly greater than formation pressure. If the kick contains gas, it will expand in the annulus under controlled conditions as it nears the surface. Therefore an increase in casing pressure and pit volume should be expected. Drillpipe pressure and pump rate must be held constant. At any time during or immediately after this first circulation, the well can be shut in and the drillpipe pressure will read the same as it did originally. After the kick fluid has cleared the choke, the well can be shut in. At this time, shut-in drillpipe and casing pressures will be the same, assuming all of the influx has been removed and mud hydrostatic is the same inside the drillpipe and the annulus. The original shut-in drillpipe pressure is converted to an equivalent density at the bit, and the mud density is increased accordingly. During the second circulation, bottomhole pressure is held constant by first maintaining casing pressure equal to the shut-in value while filling the drillpipe with the kill mud. When the drillpipe is filled, as determined by the number of strokes pumped, the drillpipe pressure is recorded and control shifts to maintaining a constant drillpipe pressure while the annulus is filled with heavy mud. When the kill mud reaches the surface, the pressure on the choke should be minimal. The pumps can be stopped while holding casing pressure constant and the well checked for flow. Any time a well under pressure is circulated, the start-up and shutdown procedures are critical and should be done with exceptional care. Whenever the pump speed is increased or decreased (including start-up and shutdown) the casing pressure must be held constant at the value it had immediately before the pump speed change was initiated. This ensures that bottomhole pressure remains constant. This procedure is valid because casing pressure should be the same whether the well is closed-in or being pumped. However, the drillpipe pressure must vary depending upon the circulating pressure loss in the system, which is a function of the pump speed. The casing pressure cannot be held constant for very long though due to the changing height of the influx caused by the irregular annulus and gas expansion.

4.0 The Engineer’s Method The Engineer’s Method of well control requires only one complete circulation. The kill mud is circulated at the same time the influx is removed from the annulus. After the well has been shut in, the pressures recorded, and pit volume increase recorded, the mud density in the pits is increased and a drillpipe pressure schedule is created. The schedule must be prepared in order that drillpipe pressure can be properly adjusted downward as kill mud fills the drillpipe. A sample drillpipe schedule with an internal drillpipe volume of 800 strokes is provided in Table E.1.

WELL CONTROL MANUAL



Table E.1

Sample Drillpipe Pressure Schedule for the Engineer's Method

Strokes Drillpipe Pumped Pressure Comment

0 540 Well is shut in 100 520 100 strokes of kill mud pumped 200 500 300 480 400 460 Kill mud halfway to the bit 500 440 600 420 600 strokes of kill mud pumped 700 400 800 380 Kill mud reaches the bit

Once the kill mud reaches the bit, the drillpipe pressure should be held constant until kill mud reaches the surface. Bottomhole pressure will be equal to, or slightly greater than formation pressure throughout the procedure as long as pump rate is maintained at the predetermined rate. If the kick contains gas, it will expand in the annulus, under controlled conditions, as it nears the surface. Therefore, an increase in casing pressure and pit volume should be expected. However, the drillpipe pressure and pump rate must be held at the predetermined level. As with the Driller’s Method, any time a well under pressure is circulated, the start-up and shutdown procedures are critical and should be done with exceptional care. A prior paragraph on this topic warrants repeating here. Whenever the pump speed is increased or decreased, (including start-up and shutdown) the casing pressure must be held constant at the value it had immediately before the pump speed change was initiated. This ensures that bottomhole pressure remains constant. This procedure is valid because casing pressure should be the same whether the well is closed-in or being pumped. However, the drillpipe pressure must vary depending upon the circulating pressure loss in the system, which is a function of the pump speed. The casing pressure cannot be held constant for very long though due to the changing height of the influx caused by the irregular annulus and gas expansion.

WELL CONTROL MANUAL



5.0 Comparison of the Methods Both the Driller’s and Engineer’s Methods provide relative advantages and disadvantages, depending on the general conditions of the area of operation or the specific conditions in the subject well. The choice of kill method is determined through discussions between the Drilling Foreman on location and the Drilling Superintendent. Figures E.3 and E.4 illustrate a gas kick being circulated to the surface using both the Driller’s and the Engineer’s Methods. Observing both figures, it is noted that when the gas bubble reaches the casing shoe the Driller’s Method results in a surface casing pressure which is higher than the initial casing pressure, whereas the Engineer’s Method is less. In the Driller’s Method, the hydrostatic pressure in the annulus is reduced as the gas bubble expands while being circulated out of the well. The bottomhole pressure is being held constant; therefore, the surface casing pressure must increase. Since the hydrostatic pressure above the shoe is the same as it was when the well was initially shut in, as long as the bubble is below the shoe, the pressure at the shoe will be increased an amount equal to the increase in the surface casing pressure plus any circulating friction generated in the annulus above the shoe. This increase in pressure could be sufficient to cause a formation breakdown at the shoe. Consequently, the maximum pressure at the casing shoe occurs when the top of the bubble reaches the shoe if the Driller’s Method is used. Conversely, when the Engineer’s Method is used, the maximum pressure at the shoe will generally occur when the kill mud reaches the bit.

Figure E.3 Removing Gas Influx with the Driller's Method

WELL CONTROL MANUAL



Figure E.4 Removing Gas Influx with the Engineer's Method

Three exceptions to this are:

1) When the kick volume fills the well above the shoe. 2) When a small kick volume does not increase the casing pressure as it rises

into a larger annular area at the top of the collars by the time kill mud reaches the bit.

3) Any time the top of the bubble reaches the shoe before the kill mud reaches the bit.

The introduction of kill mud into the annulus through the bit increases the hydrostatic pressure. In order to maintain constant bottomhole pressure, the surface pressure must be reduced; therefore, the pressure at the shoe is reduced. In both methods, once the top of the bubble reaches the shoe, the shoe pressure is decreased until the bottom of the bubble rises above the shoe. Once the bottom portion of the bubble rises above the shoe, the shoe pressure remains constant with the Driller's Method but continues to decline until the kill mud reaches the shoe with the Engineer's Method (provided bottomhole pressure is constant). Therefore, the pressure at the shoe when using the Engineer’s Method will always be less than or equal to the shoe pressure when using the Driller’s Method.

WELL CONTROL MANUAL



A summary of the advantages and disadvantages of both methods is provided in Table E.2. Table E.2 Kill Method Comparison

Method Advantages Disadvantages

Driller’s Simplicity, few calculations Requires two circulations Can be used until barite arrives. Higher surface pressures Circulate quickly, reduce Higher casing shoe pressures sticking and gas migration.

Engineer’s One circulation required More complex calculations Lower surface casing pressures Waiting may stick pipe Lower casing shoe pressures Waiting allows gas to migrate

Mud mixing capabilities 6.0 Other Well Control Methods

6.1 The Volumetric Control Method This method is used when the pumps are inoperative or when the drillpipe is either out of the hole, plugged, or has a hole in it. This is not a kill method but simply a method of controlling bottomhole and surface casing pressures as the gas migrates up the hole. The gas is allowed to expand as it migrates up the hole. A (relatively) constant bottomhole pressure is maintained by bleeding off mud with an equivalent hydrostatic head equal to the rise in pressure caused by the migrating gas. The basis of the method is equating pit volume change and annulus pressure. This procedure is discussed in detail later in this volume.

6.2 The Low Choke Pressure Method

This method is used if pressures threaten to become excessive while a well is being killed. Choke pressure must be reduced sufficiently to prevent casing burst or formation breakdown while circulating out. In kick situations requiring weight increases, the mud weight should be increased as soon as practical. Kicks occurring while drilling tight formations or after trips where tight formations have been drilled may be circulated out using this method without increasing the mud weight. It is important to realize that the formation will continue to flow until the combined effect of the new kill mud, of light weight mud, and low choke pressure all balance the formation pressure. Formations with high permeability cannot be effectively killed by this method; the influx will exceed that controllable by even the maximum rate used to circulate out the kick. The corresponding reduction of hydrostatic pressure will prevent the killing of the well and possibly cause loss of the hole.

WELL CONTROL MANUAL



Numerical analysis of the Darcy Equation indicates that this method is of questionable value where formation permeabilities are greater than 200 millidarcys. This method should not be used when there is uncertainty about formation permeability, and is therefore, not generally recommended.

6.3 Bullheading

If normal well killing techniques with conventional circulation are not possible or will result in critical well control conditions, bullheading may be considered as a useful method to improve the situation. Mud/influx are displaced/squeezed back downhole into the weakest exposed open hole formation. When to consider bullheading:

Bullheading may be considered when the following well control situations occur:

(1) Rig personnel and equipment cannot handle H2S or high-pressure gas influx safely.

(2) Normal circulation is not possible because: - Pipe has been sheared or no pipe in the hole - String is off bottom - String is blocked - String is washed out or parted

(3) A combined kick and losses situation is experienced (downhole annulus bullhead rates must exceed the gas migration rate to ensure the situation does not deteriorate further).

(4) Kick calculations show that casing pressure during conventional kill operations will probably result in a detrimental well control situation. (in this case, only the influx needs to be squeezed back).

(5) The casing is set near the reservoir, avoiding other loss zones, and reservoir permeability is high, enabling lower bullhead pressures, as in Arab-D wells.

Bullheading is not a routine well control method. In many cases, it will be doubtful whether the well can be killed by squeezing back the influx into the formation and lost circulation may be induced by bullheading kill weight fluid immediately below the shoe into the formation. The method should in most cases be considered only as a last resort. In some instances, bullheading will be considered as the prime method; in such case, the choice of bullheading should be made clear in the well plan. Examples of such cases are high pressure/high temperature or H2S wells, wells in populated areas, killing of well after a well test, or before workover operations. Prior to Bullheading

- Consider using the volumetric method to eliminate the complication of migrating gas. If the gas can be largely removed this way, the bullheading operation is likely to be much easier and more effective in killing the well.

WELL CONTROL MANUAL



- Pressure limitations of pumping equipment, wellhead equipment and casing must be kept in mind throughout.

- If a gas influx is suspected (shut in pressures continue to rise indicating

migrating gas), pumping rate for bullheading must be fast enough to exceed the rate of gas migration. If pump pressures increase instead of decreasing, it is an indication that the pumping rate is too low to be successful. This can be a problem in large diameter holes. Note that increasing the viscosity of the kill mud may or may not be helpful in controlling this problem, and could possibly even make it worse.

- There is often a chance, particularly with relatively long open hole

sections beyond the last casing shoe, that bullheading could breakdown the formation at the shoe rather than at the producing formation. In this event, rather than killing the well, this procedure may aggravate the development of an underground blowout, which could pose risks to nearby wells in communication with the formations involved. It could also increase risk of a blowout around casing in place with subsequent obvious risks. Thus, bullheading should be considered when these associated risks are the lesser of the potential evils.

- A check valve is recommended between the pumping unit and the well to

act as a failsafe valve in the event surface equipment should fail during the procedure. If possible, the cementing unit should be used for better control and adequate pressure rating.

- Large mud volume and LCM pills should be available in case major losses

are experienced during the operation. 7.0 UNDERGROUND BLOWOUT

An underground blowout occurs when the formation fluid from one zone flows into another (see Figure E.5). The most common cause is the breakdown of a weak formation during a kick, either at the instant the BOPs are closed or while heavy mud is being circulated to kill the kick. This is common when drilling below uncased, depleted formations. The method of killing an underground blowout depends on many factors. Stuck drill pipe will complicate the situation. If an underground blowout is even suspected, the first thing that should be done is to locate the zones kicking and taking fluid. This can normally be done with a temperature survey inside the drill pipe.

If the drill pipe is free, normally its end is near the zone that is kicking, usually at the bottom of the hole. Sometimes circulating a very heavy mud pill between the two zones can shut off the flow. The pill’s volume should exceed the hole volume between the two zones. It is sometimes desirable to simultaneously pump mud down the annulus.

WELL CONTROL MANUAL



Figure E.5 Underground Blowout

7.1 Barite Plugs

The most successful method of controlling a high rate underground blowout is to spot a barite plug (approx. 150 pcf) just above the flowing zone. Course-ground barite is better suited for this application than finer grind because of faster settling. In extreme cases, several barite pills may be required to shut off the flow. The barite plug consists of barite, water and lignosulfonate, and caustic soda. The lignosulfonate deflocculates the slurry and allows settling of the barite to form a plug in the wellbore. The caustic soda provides a high pH (10-11) environment for the lignosulfonate to be effective.

WELL CONTROL MANUAL



A typical formulation for a 150 pcf barite plug is as follows,

0.54 bbl water 690 lbs/bbl barite 8 lbs/bbl lignosulfonate 1 lbs/bbl caustic soda

Slurry volumes will depend on the open hole interval and severity of the kick. Typical volumes range from 40 bbls to 400 bbls.

The following flow chart summarizes the operations involved in controlling an underground blowout with barite plug(s) and cement. This method involves cementing a section of the drillstring in place.

Figure E.6 Underground Blowout Operation

RUN FREEPOINT LOG. PERFORATE ABOVE FREEPOINT AND CIRCULATE ANNULUS CLEAR

PUMP BARITE SLURRY

1. OVER DISPLACE THRU BIT 2. PUMP ¼ BBL THRU BIT @ 15

MIN. INTERVALS 3. WAIT 6-10 HOURS 4. RUN TEMPERATURE SURVEY 5. WAIT 4 HOURS. RUN SECOND

SURVEY

WELL IS NOT FLOWING 1. SQUEEZE CEMENT SLURRY THRU

THE BIT. LEAVE SOME CEMENT IN THE PIPE OR SET BRIDGE PLUG PUMP IN DP

2. WOC & PRESSURE TEST 3. PERFORATE NEAR THE TOP OF

THE BARITE PLUG. ATTEMPT TO CIRCULATE

WELL IS FLOWING 1. PUMP SECOND

BARITE SLURRY

WELL WILL NOT CIRCULATE 1. SQUEEZE CEMENT SLURRY THRU

PERFORATION. CUT DISPLACEMENT SHORT OR SET BRIDGE PLUG IN DP

2. WOC & PRESSURE TEST

WELL CIRCULATES 1. CIRCULATE CLEAR OF INFLUX 2. SPOT CEMENT SLURRY THRU

PERFORATION CUT DISPLACEMENT SHORT OR SET BRIDGE PLUG IN DP

3. WOC & PRESSURE TEST

WELL CONTROL MANUAL


SECTION F – PRE-RECORDED DATA SHEET

Current Revision: October 2002 F - 1 3rd Edition Previous Revision: October 1998

Table of Contents

1.0 Purpose of the Pre-recorded Data Sheet .......................................F-2 2.0 Using the Pre-recorded Data Sheet.................................................F-2

2.1 Well Data........................................................................................F-2 2.2 Hole Data ......................................................................................F-2

2.2.1 Hole Size Information...........................................................F-2 2.2.2 Hole MD and TVD................................................................F-3 2.2.3 Capacity Factor....................................................................F-3

2.3 Pump Data .....................................................................................F-3 2.3.1 Liners ..................................................................................F-3 2.3.2 Stroke .................................................................................F-3 2.3.3 Rod Size .............................................................................F-3 2.3.4 % Efficiency.........................................................................F-3 2.3.5 Bbl/stk.................................................................................F-3

2.4 Casing Data....................................................................................F-3 2.5 Wellhead or Casing Pressure Limitation........................................F-3 2.6 Liner Casing Data...........................................................................F-4 2.7 Drillstring Data ...............................................................................F-4 2.8 Internal Capacities.........................................................................F-4 2.9 Annulus Capacities........................................................................F-4 2.10 Maximum Initial SICP .....................................................................F-4

3.0 Well Data Sheet must be Current.....................................................F-5 3.1 Sections Fully Completed ............................................................F-5 3.2 Sections Partially Completed.........................................................F-5

3.2.1 Hole Data ............................................................................F-5 3.2.2 Internal Capacities ...............................................................F-5 3.2.3 Annulus Capacities ..............................................................F-5

4.0 Some Complicating Situations .........................................................F-6 4.1 Drilling Liner..................................................................................F-6 4.2 Tapered Drillstring .........................................................................F-6

5.0 Example Pre-recorded Data Sheet...................................................F-7 5.1 Vertical Well ...................................................................................F-7 5.2 Highly Deviated and Horizontal Well..............................................F-8

WELL CONTROL MANUAL




1.0 Purpose of the Pre-recorded Data Sheet The Pre-recorded Data Sheet is an information reference, which lists the actual wellbore capacities and volumes for a particular well. The data sheet is a critical well control document, which must be kept as current and as accurate as possible. The Drilling Foreman will need this information to complete the Engineer’s or Driller’s Method worksheets should a kick occur. The information displayed on the data sheet is used to calculate pumping volumes and strokes and is therefore crucial to the successful completion of most well killing operations. It is the expressed purpose of the data sheet to be filled-out when a gas kick is taken so the information will be readily available in these situations. When the data sheet is filled out ahead of time, the Drilling Foreman does not have to spend time figuring wellbore capacities and volumes after a kick has occurred when time may be critical. Also, this gives the Drilling Foreman extra time to double check the numbers for accuracy.

Note: Therefore, it is strongly recommended that the data sheet be filled-out as completely as possible at all times while drilling.

Much of the data on the data sheet does not change from day-to-day, so it is a simple matter to keep the few changing items current. Many of the capacities and measurements are easily memorized because they are used so frequently for other matters besides well control. Nevertheless, memories can sometimes fail in pressure situations, so it is wise to keep these numbers written down for everyone on the rig to refer to in a critical situation.

2.0 Using the Pre-recorded Data Sheet

The following descriptions relate important information about every entry blank on the data sheet. Drilling Foremen should be guided by these descriptions to aid them in using the form.

2.1 Well Data

The well data section is composed of the well name, field name, and rig name. These items should be filled out completely.

2.2 Hole Data

2.2.1 Hole Size Information

Record the hole size as the diameter of the bit in the hole.

WELL CONTROL MANUAL




2.2.2 Hole MD and TVD

These items are recorded after the well has kicked. It should take only a short while to determine these values from the Driller’s pipe figures and applicable survey data.

2.2.3 Capacity Factor

Record the capacity factor of the hole size listed above in bbls/ft. (Use Table P.4 for reference.) This is an approximation and does not account for hole washout or actual casing diameter. Multiply this number by the Measured Depth to determine the hole capacity (bbls).

2.3 Pump Data

2.3.1 Liners

Record as the pump liner diameter (inches) for duplex or triplex pumps.

2.3.2 Stroke

Record as the pump stroke (inches) for duplex or triplex pumps.

2.3.3 Rod Size

Record as the pump rod diameter (inches) for duplex pumps only.

2.3.4 % Efficiency

Record as the mechanical pump efficiency as determined by top plug displacement during a cement job or by pumping into the trip tank.

2.3.5 Bbl/stk

Use Table P.5 to determine the theoretical pump displacement and multiply by % Efficiency above to determine the actual pump output.

2.4 Casing Data

Record the outside diameter, inside diameter, measured depth, and true vertical depth of the last full string of casing in the ground.

2.5 Wellhead or Casing Pressure Limitation

Record as the lesser of:

a) 100% of wellhead pressure rating b) 100 % of blowout preventer pressure rating c) 80% of last casing string burst rating

WELL CONTROL MANUAL




2.6 Liner Casing Data Record the outside diameter, inside diameter, measured depth to top and vertical depth to shoe of any liner casing in the ground.

2.7 Drillstring Data Record the outside diameter (inches) and weight (lb/ft) of all drillpipe, heavyweight drillpipe and drill collars in the string. This data should be reviewed and updated on every trip in the hole.

2.8 Internal Capacities

Record the length of each drillstring component by its associated internal capacity factor (bbl/ft). (Use Tables P.1 through P.3 for reference.) Treat bottomhole assembly components (stabilizers, crossover subs, etc.) as drill collars for capacity calculations. Calculate the total volume (bbls) for each component section by multiplying the component length by its capacity factor. Since the length of drillpipe will not be known until after the well kicks, the drillpipe capacity and total int ernal capacity will have to be calculated after the kick. Check that the measured depth indicated is equal to the sum of the individual component lengths. Divide the total internal capacity (bbls) by the pump displacement (bbls/stk) to determine these capacities in strokes.

2.9 Annulus Capacities

Record the length of each drillstring component and its associated annular capacity factor in the given hole size. (Use Tables P.1 through P.3 for reference.) Treat bottomhole assembly components (stabilizers, crossover subs, etc.) as drill collars for capacity calculations. Calculate the annular capacity (bbls) opposite each component section by multiplying the component length by the annular capacity factor. Since the length of drillpipe will not be known until after the well kicks, the annular capacity opposite the drillpipe and the total annular capacity will have to be calculated after the kick. Check that the measured depth indicated is equal to the sum of the individual component lengths. Finally, add the Total Internal Capacity to the Total Annular Capacity to determine the Total System Capacity (not including the active pit volume). Divide the Total Annular Capacity (bbls) and the Total System Capacity by the pump output (bbls/stk) to determine these capacities in strokes.

2.10 Maximum Initial SICP

The maximum casing pressure that will fracture the formation at the shoe upon shut in can be determined by subtracting the present mud weight from the shoe test (in pcf) and then multiplying this figure by the true vertical depth of the shoe and by 0.007. This formula is stated in equation form below:

MISICP = (Shoe Test, pcf EMW – Present Mud Weight, pcf) x TVDshoe, ft. x 0.007

WELL CONTROL MANUAL




3.0 Well Data Sheet must be Current The data sheet should be kept as current and as accurate as possible so that time is not wasted looking-up routine capacity numbers after a kick has been taken. The data sheet has been designed so that nearly all of the sections can be completed prior to a kick. These sections include:

3.1 Sections Fully Completed

• Well Data • Pump Data • Casing Data • Wellhead or Casing Pressure Limitation • Liner Casing Data • Drillstring Data • Maximum Initial SICP

However, some of the sections on the data sheet cannot be fully completed until after the well has kicked. These include:

3.2 Sections Partially Completed

3.2.1 Hole Data

All items should be completed except the measured depth and true vertical depth. These depths are recorded after the kick occurs.

3.2.2 Internal Capacities

All items should be completed except the drillpipe length (ft) and volume (bbls). These items are recorded after the kick occurs.

3.2.3 Annulus Capacities

All items should be completed except drillpipe x casing or hole (ft) and volume (bbls). These items are recorded after the kick occurs.

If the Pre-recorded Data Sheet is completed as described above, the only blank entries remaining on the sheet will be those, which require the length of drillpipe in the hole (which is constantly changing as you drill deeper). If a kick is taken, the Drilling Foreman simply needs to determine the length of drillpipe in the hole and the remaining capacities (hole, internal, and annulus) can be easily calculated.

WELL CONTROL MANUAL




4.0 Some Complicating Situations Sometimes, complicated wellbore and drillstring configurations combine to make completion of the data sheet unclear. Some of these special situations (with remedies) are described below.

4.1 Drilling Liner

A drilling liner is a complicating situation because the change in casing diameters at the liner top changes the annular capacity figures. To resolve the situation, you will need to add additional annular capacity figures to the Prerecorded Data Sheet. The drillstring needs to have two separate annular capacity figures (one for the liner, a second for the casing). Therefore, you need to include the annular capacity figures for both the liner and the casing in the annulus capacity section. Make a note in the left hand margin to indicate which capacity figure is for the liner and which is for the casing. Remember, this need only be done for the drillstring component, which is opposite the liner top. If drillpipe is opposite the liner top while drilling, then the length of drillpipe x casing can be determined and recorded on the data sheet. On the other hand, if the heavyweight drillpipe is opposite the liner top while drilling, then the length of heavyweight inside the liner and casing will be constantly changing as you drill deeper. In these instances, it will not be possible to record the correct lengths until after a kick has been taken and the measured depth determined.

4.2 Tapered Drillstring

A tapered drillstring changes both the internal and the external capacity figures at the point of crossover. You need to include the capacity figures (bbl/stk) for both sizes of drillpipe on the Pre-recorded Data Sheet. Compute the internal and annular capacities opposite the smaller diameter drillpipe in the same manner as the drill collars.

5.1 PRE-RECORDED WELL DATA KEEP THIS DATA SHEET CURRENT AT ALL TIMES

(Vertical and Deviated Wells)Well Name Zuluf Well #1005 Field Zuluf Rig Nadrico #1

HOLE DATA Size(actual) 8.5000 Hole MD 8,000 ft. Hole TVD 8,000 ft.*Use

PUMP DATA Liners (in.) Stroke(in.) Rod(in. ) % Eff. bbl./stk For Kill?No. 1 6.25 16 96 0.1458 XNo. 2 6.25 16 96 0.1458

* X if used, empty if notCASING (LAST SET) DATA

9.6250 by 8.5000 Shoe MD 5,500 Shoe TVD 5,500(in. OD) (in. Avg ID) (feet) (feet)

WELLHEAD OR CASING PRESSURE LIMITATIONThe lessor of: 100% BOP Rating 5,000 psi. 100% Wellhead Rating 5,000 psi. Limitation = 3160 80% Casing Burst 3,160 psi. psi.

LINER CASING DATAby Top @ ft. Shoe @

(in. OD) (in. Avg ID) MD(feet) MD(feet) TVD(feet)

DRILL STRING DATA DRILL COLLARSDrill Pipe 1 4.5000 in. (OD) 16.6 lb./ft. OD(in.) ID(in.)Drill Pipe 2 in. (OD) lb./ft. 6.75 by 2.8125HW Drill Pipe 4.5000 in. (OD) 41.5 lb./ft. by

INTERNAL CAPACITIESDrill Pipe 1 7,220 ft. x 0.0141 bbl./ft. = 101.8 bbl.Drill Pipe 2 ft. x bbl./ft. = 0.0 bbl.HW Drill Pipe 330 ft. x 0.0074 bbl./ft. = 2.4 bbl.Drill Collars 450 ft. x 0.0077 bbl./ft. = 3.5 bbl.Drill Collars ft. x 0.0000 bbl./ft. = 0.0 bbl.

Msrd Depth(bit) 8,000 ft. Total Internal = 107.7 bbl. = 739 Strokes

ANNULUS CAPACITIES (Note: Use other side for subsea)DP1 x Csg. 5,500 ft. x 0.0505 bbl./ft. = 277.9 bbl.DP1 x Liner 0 ft. x 0.0000 bbl./ft. = 0.0 bbl.DP1 x Hole 1,720 ft. x 0.0505 bbl./ft. = 86.9 bbl.DP2 x Csg. 0 ft. x 0.0000 bbl./ft. = 0.0 bbl.DP2 x Liner 0 ft. x 0.0000 bbl./ft. = 0.0 bbl.DP2 x Hole 0 ft. x 0.0000 bbl./ft. = 0.0 bbl.HW DP 330 ft. x 0.0505 bbl./ft. = 16.7 bbl.DC x Hole 450 ft. x 0.0259 bbl./ft. = 11.7 bbl.DC x Hole 0 ft. x 0.0000 bbl./ft. = 0.0 bbl.

Msrd Depth(bit) 8,000 ft. Total Annulus = 393.2 bbl. = 2,697 Strokes

System Volume (Internal + Annulus) = 500.9 bbl. = 3,436 Strokes

Volume from Bit to Shoe = 86.9 bbl. = 596 Strokes

Active Pit Volume 500 bbl.MAX INITIAL SICP TO FRACTURE SHOE

[ 127 pcf EMW - 74 pcf MW] x 0.007 x 5,500 ft. = 2041 psi.(Shoe Test) (Present Mud Weight) (Shoe TVD) Version 2.0 (4/15/00)

F - 7

PRERECORDED WELL DATA5.2 KEEP THIS DATA SHEET CURRENT AT ALL TIMES

(Highly Deviated and Horizontal Wells)

Well Name Zuluf Well #1006 Field Zuluf Rig Nadrico #1

HOLE DATASize(avg) 8.5000 Hole MD 8,300 ft. Hole TVD 6,000 ft.

Hole Capacity: No pipe in hole 0.0702 bbls/ft x 8,300 ft. = 582.8 bbl(from BOP to MD) *Use




WELLHEAD OR CASING PRESSURE LIMITATIONThe lessor of: 100% BOP Rating 5,000 psi. 100% Wellhead Rating 5,000 psi. Limitation = 4,600 psi. 80% Casing Burst 4,600 psi.

LINER CASING DATA0.0000 by 0.0000 Top @ 0 Shoe @ 0 0(in. OD) (in. Avg ID) MD(feet) MD(feet) TVD(feet)


INTERNAL CAPACITIES (Section 1 - Surface to Kickoff Point)Drill Pipe 1 3,000 ft. x 0.0141 bbl./ft. = 42.3 bbl.Drill Pipe 2 0 ft. x 0.0000 bbl./ft. = 0.0 bbl.HW Drill Pipe 0 ft. x 0.0074 bbl./ft. = 0.0 bbl.Drill Collars ft. x 0.0077 bbl./ft. = 0.0 bbl.Drill Collars ft. x 0.0000 bbl./ft. = 0.0 bbl.

Section 1 Subtotal Internal Capacities = 42.3 bbl. Kickoff MD 3,000 290 StrokesKickoff TVD 3,000

INTERNAL CAPACITIES (Section 2 - Kickoff Point to Start of Hold)Drill Pipe 1 3,500 ft. x 0.0141 bbl./ft. = 49.4 bbl.Drill Pipe 2 ft. x 0 bbl./ft. = 0.0 bbl.HW Drill Pipe 700 ft. x 0.0074 bbl./ft. = 5.2 bbl.Drill Collars ft. x 0.0077 bbl./ft. = 0.0 bbl.Drill Collars ft. x 0.0000 bbl./ft. = 0.0 bbl.

Section 2 Subtotal Internal Capacities = 54.5 bbl. Start of Hold MD 7,200 374 StrokesStart of Hold TVD 6,000

Kickoff Point

Start of Hold (continued on next page) Version 2.0 (4/15/00)F - 8

PRERECORDED WELL DATA (Highly Deviated and Horizontal Wells)

(page 2)

INTERNAL CAPACITIES (Section 3 - Start of Hold to TD of Bit)Drill Pipe 1 0 ft. x 0.0141 bbl./ft. = 0.0 bbl.Drill Pipe 2 ft. x 0.0000 bbl./ft. = 0.0 bbl.HW Drill Pipe 1000 ft. x 0.0074 bbl./ft. = 7.4 bbl.Drill Collars 100 ft. x 0.0077 bbl./ft. = 0.8 bbl.Drill Collars ft. x 0.0000 bbl./ft. = 0.0 bbl.

Section 3 Subtotal Internal Capacities = 8.2 bbl. Total MD 8,300 56 StrokesTotal TVD 6,000

TOTAL INTERNAL CAPACITYMsrd. Depth(Bit) 8,300 ft. Total Internal = 105.0 bbl. = 720 Strokes

ANNULUS CAPACITIES DP1 x Csg. 7,200 ft. x 0.0505 bbl./ft. = 363.8 bbl.DP1 x Liner ft. x 0.0000 bbl./ft. = 0.0 bbl.DP1 x Hole ft. x 0.0505 bbl./ft. = 0.0 bbl.DP2 x Csg. ft. x 0.0000 bbl./ft. = 0.0 bbl.DP2 x Liner ft. x 0.0000 bbl./ft. = 0.0 bbl.DP2 x Hole ft. x 0.0000 bbl./ft. = 0.0 bbl.HW DP x Csg. ft. x 0.0505 bbl./ft. = 0.0 bbl.HW DP x Liner ft. x 0.0000 bbl./ft. = 0.0 bbl.HW DP x Hole 1,000 ft. x 0.0505 bbl./ft. = 50.5 bbl.DC1 x Csg ft. x 0.0259 bbl./ft. = 0.0 bbl.DC1 x Liner ft. x 0.0000 bbl./ft. = 0.0 bbl.DC1 x Hole 100 ft. x 0.0259 bbl./ft. = 2.6 bbl.DC2 x Csg ft. x 0.0000 bbl./ft. = 0.0 bbl.DC2 x Liner ft. x 0.0000 bbl./ft. = 0.0 bbl.DC2 x Hole ft. x 0.0000 bbl./ft. = 0.0 bbl.


System Volume = 522.0 bbl. = 3,581 Strokes (Internal + Annulus)

Active Pit Volume 500 bbl.

Kickoff Point

Start of Hold

MAX INITIAL SICP TO FRACTURE FORMATION AT SHOE

Max. SICP = (Shoe Test - Present Mud Wt.) x Shoe TVD x 0.007

= [# pcf EMW - 74 pcf MW] x 6,000 ft. x 0.007 = 2226 psi

F - 9

WELL CONTROL MANUAL


SECTION G – DRILLER’S METHOD

Current Revision: October 2002 G - 1 3rd Edition Previous Revision: October 1998

Table of Contents

1.0 Description of the Method.................................................................G-2 Step1 The Kick Is Detected – Shut the Well In......................................G-2

Shut-In Procedure while Drilling ...................................................G-2 Shut-In Procedure while Tripping .................................................G-2

Step 2a Allow the Well to Stabilize .........................................................G-3 Step 2b Bumping the Drillpipe Float.......................................................G-3 Step 3 Perform the Kick Control Calculations ......................................G-4 Step 4 Establish Circulation .................................................................G-5 Step 5 Circulate Out the Influx Holding Drillpipe Pressure Constant….G-5 Step 6 Shut Down the Pumps – Weight Up the Mud Pits ................. …G-6 Step 7 Re-Establish Circulation and Circulate Kill Mud.................... …G-7 Step 8 Shut Down and Check for Flow ............................................. …G-7 Step 9 Circulate and Condition the mud ........................................... …G-8

2.0 Using the Driller’s Method Worksheet ...........................................G-8 Step 1 Pre-recorded Information ...................................................... …G-9 Step 2 Information to be Recorded when Well Kicks........................ …G-9 Step 3 Determining Pressures for the First Circulation .......................G-9 Step 4 Determining Mud Weight to Balance the Kick..........................G-10

Rounding-Up Rule ...................................................................G-10 Step 5 Total Volume to Weight-Up ......................................................G-10 Step 6 Barite Required to Weight-Up ..................................................G-11 Step 7 Determining Pressures for the Second Circulation .................G-11 Step 8 Determining Reservoir Pressure..............................................G-12 Step 9 Determining Equivalent Bottomhole Gas Bubble Height .........G-12 Step 10 Determining Maximum Casing Pressure..................................G-12

Pc Max (Part 1) .........................................................................G-13 Pc Max (Part 2) .........................................................................G-13

Step 11 Determining Volume Gain for a Gas Kick - Figure P.3 .............G-14 Step 12 Determining Maximum Casing Pressure & Excess Volume.... G-14 Pre-recorded Well Data Sheet (Vertical Well) ..........................................G-15 Driller's Method Worksheet (Vertical Well)..............................................G-16 Figure P.1 ...............................................................................................G-18 Figure P.3................................................................................................G-19 Pre-recorded Well Data Sheet (Highly Deviated or Horizontal Well)........G-20 Driller’s Method Worksheet (Highly Deviated or Horizontal Well)............G-22

WELL CONTROL MANUAL




1.0 Description of the Method The Driller's Method of well control is a well killing method that requires two complete circulations. During the first circulation, mud is pumped to displace the influx from the well; in the second circulation, weighted kill mud is pumped around to kill the well. While circulating, the bottomhole pressure is maintained equal to or slightly greater than the formation pressure. The following discussion describes the Driller's Method in detail from kick to kill.

STEP 1 - The Kick Is Detected (Shut the Well In)

As always, it is extremely important to shut-in the well as quickly as possible in order to minimize the size of the infl ux. The best way to achieve this is by using the “Three S” Shut-In Procedure While Drilling or the “Three S” Shut -In Procedure While Tripping.

Shut-In Procedure While Drilling



(3) SHUT-IN Close the annular preventer or uppermost pipe ram preventer. Confirm that the well is shut-in and flow

has stopped. Open HCR valve.

Shut-In Procedure While Tripping

(1) STAB VALVE Install Full Open Safety Valve (open position) in drill string. Close Safety Valve.

(2) SPACE OUT Spot tool joint.

(3) SHUT-IN Close the annular preventer or uppermost pipe ram


It should be emphasized that in nearly all well kicks, the Driller will be the responsible for closing the preventers and shutting the well in. The Driller must have the initiative and experience to do this by himself if he is alone. It is the responsibility of the Saudi Aramco Drilling Foreman to make sure the Driller knows the proper shut-in procedure. The Driller will have plenty of time after the well is shut-in to retrieve his crews from the mud pits and notify the Toolpusher. The Driller must not delay when shutting in the well.

WELL CONTROL MANUAL




Step 2a - Allow the Well to Stabilize, Record Pressure and Volume Gained

After the well is shut-in, it may take a few minutes for the shut-in pressures to stabilize. If the pipe is reciprocated through the annular preventer during the kill, it may be advisable to reduce the annular closing pressure to lessen element wear. The crew should ensure that the bag does not leak at the reduced pressure!

If the choke manifold is lined-up properly, you should be possible to open the choke line valve at the preventer stack and read the shut-in casing at the choke manifold. If no drillpipe float is installed, read and record the shut-in drillpipe pressure as well. Finally examine the pit volume gained during the kick and verify this number with the Derrickman.

Step 2b - Bumping the Drillpipe Float

If a drillpipe float is installed, the pressure gauge on the drillpipe will probably read near zero. In order to get an accurate value for the shut-in drillpipe pressure, the float will have to be “bumped” open by slowly pumping down the drillpipe. The correct procedure for bumping the float is given below.


(1) Make sure the well is shut-in and that the shut-in casing pressure is

recorded. (2) Slowly pump down the drillpipe while monitoring both the casing and

drillpipe pressure. (3) The drillpipe pressure will increase as you begun. Watch carefully for a “lull”

in the drillpipe pressure (a hesitation in the rate of increase), which will occur as the float is pumped off of its seat. Record the drillpipe pressure when the lull is first seen.

(4) To verify that the float has been pumped open, continue pumping down the drillpipe very slowly until an increase in the casing pressure is observed. This should occur very soon after the lull was observed on the drillpipe gauge.

(5) Shut down the pump as soon as you see the casing pressure start to increase and record the shut-in drillpipe pressure as the pressure at which the lull was first seen in Step 3 above (not the final drillpipe pressure after the pumps are stopped).

(6) Check the shut-in casing pressure again. Any excess pressure may be bled-off in small increments until equal readings of casing pressure are observed after two consecutive bleed-offs.

WELL CONTROL MANUAL




The float bumping procedure, as described above, can be difficult at times if the rig has big duplex pumps, which are compounded. Clutch the pumps in short burst to slowly build up pressure on the drillpipe. It is most likely that a drillpipe ‘lull’ won’t occur before the casing pressure starts to increase. To determine the shut-in drillpipe pressure in these instances, subtract the increase in shut-in casing pressure from the final value of shut-in drillpipe pressure after the pumps have been stopped. Use this value as the official shut-in drillpipe pressure. If excess pressure is trapped on the drillpipe when bumping the float…. Shut-in Shut-in drillpipe Increase in shut-in Drillpipe = pressure after - casing pressure while Pressure bumping float bumping float

Step 3 - Perform the Kick Control Calculations Calculations should be performed using the Driller's Method worksheet before the influx is displaced from the well on the first circulation. Several critical items will be determined including:

• Bottomhole reservoir pressure • Mud weight necessary to balance the kick • Maximum surface casing pressure during the first circulation • Maximum excess mud volume gained during the first circulation

An example problem illustrating the use of the Driller's Method Worksheet is provided later in this section.

One thing to keep in mind while performing your calculations is that the formation fluids in the annulus, especially gas, may migrate up the hole and cause an increase in the shut-in casing pressure. If the shut-in casing pressure starts increasing substantially (i.e., to the point of risking shoe breakdown or exceeding the wellhead or casing pressure limitation), you may have to bleed-off some of the excess pressure through the choke. It is better to bleed the pressure off in small increments rather than one large slug. Any excess pressure that appears on the annulus due to the migrating bubble may be bled-off in small increments until equal readings are observed after two consecutive bleed-offs. There is more likelihood of pipe sticking if formation fluids are kept longer in the annulus and it’s important to proceed as quickly as possible.

WELL CONTROL MANUAL




Step 4 - Establish Circulation After the kick control calculations have been performed, you should use the information recorded on the Driller's Method Worksheet to circulate the influx from the well. Before breaking circulation, be sure to check the following items.

1) Be sure that every member of the crew knows exactly what his duties are

before the kill operation begins. (See Section M in this volume for more details.)

2) Eliminate all sources of ignition in the immediate vicinity of the rig and vent lines. See that the vent lines on the mud-gas separator and mud degasser are secured properly and, if possible, are downwind from the rig.

3) Make sure your circulating system (including manifolds and pits) is lined-up correctly.

4) Zero the stroke counter and make a note of the time.

When establishing circulation in a well closed in under pressure, backpressure on the well is very difficult to control. The procedure is critical, since additional influx will result if too little backpressure is held, or the formation can breakdown if too much backpressure is held.

The procedure requires simultaneous manipulation of the choke and the pump speed. While the pumps are being brought up to speed, the choke is opened in such a way that casing pressure is maintained constant at its shut-in value just prior to beginning pumping. As the pumps speed is increased up to the desired kill rate, drillpipe pressure will increase but casing pressure must be held constant. Successful manipulation of the choke while establishing circulation in this manner will maintain constant bottomhole pressure.

The predetermined pump rate must be held constant throughout the killing of the well. If the pump rate is allowed to vary without adjusting the drillpipe pressure, constant bottomhole pressure will not be maintained. If the pump rate is increased, additional frictional pressure will be reflected in the drill pipe pressure. If the choke is adjusted to bring the drill pipe pressure down to the value predetermined using a constant rate, then the bottom hole pressure is reduced possibly allowing additional influx. Conversely, if the pump rate is reduced, the reduction in frictional pressure will be noted and the choke adjusted to increase the drill pipe pressure, possibly creating sufficient overpressure at the casing shoe to cause a break down. Therefore, any change in pump rate should be made known to the choke operator and the pump returned to the original rate.

Step 5 - Circulate Out the Influx Holding Drillpipe Pressure Constant As soon as the pumps are operating at the desired kill rate, the drillpipe pressure should be observed and recorded. Hold the observed drillpipe pressure constant for the entire first circulation by manipulating the choke as the contaminant is circulated from the well.

WELL CONTROL MANUAL




Note: In all probability, the observed initial circulating pressure on the drillpipe will be equal to the sum of the initial shut-in drillpipe pressure and the pre-recorded slow pump rate pressure at the same kill rate.

As the gas and contaminated mud are circulated to the surface, the gas will begin to expand, increasing both the casing pressure and pit volume. A pure gas contaminant will increase the casing pressure to the value shown at “R” on the worksheet, but will be less if the contaminant includes water and/or oil. This is probably the most critical stage of the killing operation, where panicking could very easily turn a good job into a disaster.

It can sometimes be difficult to bleed the gas off fast enough to keep the drill pipe pressure within limits, but excessive pressure could cause formation breakdown. If the gas cannot be released fast enough from the annulus to prevent an increase in drill pipe pressure, the pumps may have to be slowed or even stopped until the casing pressure can be bled down. For this reason it is a good idea to take several slow pump rates, including one at the slowest pump rate possible, so that the drillpipe pressure can be determined at the reduced pumping rate. If the pumps must be stopped while bleeding down the casing pressure attempt to hold the drillpipe pressure at or above the original shut-in pressure while bleeding. If the drillpipe pressure drops below this value, another kick may be taken. The pumps should be returned to the original rate as soon as possible. This method is not ideal, but is necessary when the surface facilities cannot safely handle the high flow rates.

Step 6 - Shut Down the Pumps - Weight Up the Mud Pits

After the contaminant has been circulated out of the well, the pumps can be shut down and the well shut-in. When shutting down the pumps, the choke should be closed gradually as the pump speed is reduced. The choke should be closed in a way that holds the casing pressure constant as the pumps are slowed down. As the pump speed decreases, the drillpipe pressure will decrease but casing pressure must be held constant at its value just prior to slowing down. This procedure insures that constant bottomhole pressure is maintained during the shutdown. When the well is shut-in after the first circulation, the shut-in casing pressure and the shut -in drillpipe pressure should be equal. A casing pressure is higher than the drillpipe pressure indicates that there is still some contaminant in the annulus or that another kick was taken during the first circulation. Such a situation will warrant an additional circulation of the well with existing mud before kill weight fluid is mixed and pumped.

Note: After shutdown, the SICP and the SIDP should be equal to the initial shut-in drillpipe pressure that was observed when the well was first shut-in.

WELL CONTROL MANUAL




If the shut-in casing pressure is equal to the shut-in drillpipe pressure at the completion of the first circulation, weight-up the mud in the pits. The first step is to reduce the mud volume in the active pits to make room for weighting material. The mud mixing facilities and pit volumes on the particular rig will dictate to some extent just how the mud should be handled. The ideal situation is to maintain a reasonably low-volume active system such that the mud circulated out of the hole can be weighted up without having to stop circulating. It may be desirable to weight up enough mud to displace the entire hole before the killing operation is started. Many variables will enter into this decision (as described in Step 3) and every situation is different. It is important to remember that the mud weight can be raised while the well is being circulated.

Step 7 - Re-Establish Circulation and Circulate Kill Mud

After the mud has been properly weighted-up, the second circulation should be started. First, establish the desired pump rate by holding the shut-in casing pressure constant while bringing the pump up to the kill rate (as described Step 3). Make sure to hold this pump rate constant throughout the killing of the well.

As the kill mud goes down the drillpipe, adjust the choke so that the casing pressure remains constant at the shut-in value it had before the start of the second circulation. Hold the casing pressure constant until the kill mud reaches the bit (as determined by the drillpipe capacity in strokes).

When the kill mud reaches the bit, the pressure on the drill pipe should be observed and recorded on your Driller's Method Worksheet. Adjust the choke to hold this drill pipe pressure constant throughout the remainder of the kill operation. Continue circulation until the hole is full of kill mud. The approximate strokes and volume required are indicated on your Prerecorded Well Data sheet. The casing pressure should drop to zero as the lightweight mud is displaced from the annulus.

Step 8 - Shut Down and Check for Flow

After the entire hole volume has been displaced with kill mud, the pumps can be shut down and the well shut -in. When shutting down the pumps, the choke should be closed (holding casing pressure constant) gradually as the pump speed is reduced. As the pump speed decreases, the drillpipe pressure will slowly decrease to zero.

Note: The casing pressure may already be reading zero before the pumps

are shut down. This is normal and may be expected.

After the well is shut-in, the casing and drillpipe pressures should be zero. Confirm that the well is dead by cracking open the choke; the well should not flow. If the well is dead, the BOPs can be opened. Keep in mind that a small volume of gas may be trapped between the preventer and the choke line. Exercise caution on the rig floor when opening the preventers.

WELL CONTROL MANUAL




Step 9 - Circulate and Condition the Mud

After the BOP's are opened, circulate the mud and condition it to the desired properties. Usually the yield point is too high. Therefore, running or pulling pipe can cause excessive pressure on the formation or swabbing and either could lead to another kick.

2.0 Using the Driller’s Method Worksheet

The Driller's Method worksheet is a step-by-step instruction sheet to help the Drilling Foreman calculate the critical well control parameters, which are necessary to successfully kill a well using the Driller's Method. Use of the worksheet is demonstrated here with an example problem.

EXAMPLE PROBLEM A well is being drilled, and the following data are known prior to kick:

Triplex Pumps: 16” stroke, 96% vol. eff. (6-1/4” liner) Casing Size: 9-5/8” set at 5,500 ft MD/TVD Hole Size: 8-1/2” Csg Pressure Limitation: 3,160 psi @ 80% burst Shoe Test: 2,040 psi with 74 pcf mud Drill Pipe Size: 4-1/2”, 16.60 lb/ft Drill Collar Size: 6-3/4” OD x 2-13/16” ID (450 ft long) Mud Weight: 74 pcf Active Surface System: 750 bbls before kick 500 bbls at start of kill operation Slow Pump Rate Data: SPM PSI 30 350 40 550 While drilling at 8,000' TVD, the well kicked and the BOP's were closed. The following data were observed:

Initial Drill Pipe Pressure = 200 psi Initial Casing Pressure = 300 psi

Pit Volume Gain = 15 bbl

The following pages describe a step-by-step procedure for determining the well control parameters, which are necessary to kill the example problem well using the Driller's Method.

WELL CONTROL MANUAL




Step 1 – Pre-recorded Information

Prior to the kick, and at all times, your prerecorded data sheet should be completely filled out except for the measured depth and the length of drillpipe in the hole. Enter these items and calculate the internal drillstring capacity and the system totals. Transfer the slow pump rate data from the prerecorded data sheet to line A of the Driller's Method worksheet.

Step 2 - Information to be Recorded when Well Kicks

Many items of information need to be gathered when a well kicks. These include:

• Old Mud Weight • Pit Volume Increase • Initial Shut-in Drill Pipe Pressure • True Vertical Depth Of Hole • Initial Shut-in Casing Pressure • Measured Depth Of Hole

This information should be recorded in lines B through F on the Driller's Method worksheet.

Step 3 - Determining Pressures for the First Circulation

One of the biggest advantages of the Driller's Method is that it is not necessary to calculate any circulating drillpipe pressures before the first circulation can begin. However, while circulating, it is very important to record and maintain a constant drillpipe pressure once you have it established. Space is provided on the Driller's Method worksheet to record your circulating drillpipe pressure, which is observed after the pumps are operating at the predetermined kill rate. The kill rate should be between 2-5 barrels per minute for most cases. Space is also provided to record the kill rate (in strokes per minute) before the circulation begins. Remember to keep the kill rate constant for the entire circulation and to maintain constant drillpipe pressure by making choke adjustments until the influx is circulated out.

Note: For added peace of mind during the kill operation, it is possible to make a quick estimation of what your initial circulating drillpipe pressure should be after circulation is established. Simply add the prerecorded slow pump rate pressure at the desired circulating rate to the initial shut-in drill pipe pressure. In this example 30 SPM is the kill rate, so use the slow pump rate pressure at 30 SPM. Therefore, the initial circulating pressure should be approximately 350 + 200 = 500 psi. You may wish to jot down this value in the margin for comparison purposes when the circulation begins. However, the actual value that is observed on the drillpipe pressure gauge when circulation is established is the value that should be held constant for the entire circulation (not your estimated value).

WELL CONTROL MANUAL




Step 4 - Determining Mud Weight to Balance the Kick

Using the equation below, calculate the increase in mud weight necessary to balance the kick.

Increase in Initial Shut-in Drillpipe Pressure (SIDP)

Mud Weight = ------------------------------------------ 0.007 X TVD

200 = ------------------- 0.007 X 8,000

= 3.6 pcf

Rounding-Up Rule: The increase in mud weight should be calculated to the tenths

place. If the number in the tenths place is greater than zero, then roundup the number one full pcf. In this example, the number in the tenths place is six, so the weight is rounded-up to 4 pcf.

Record an 4 pcf increase on line G of the Driller's Method worksheet. Adding the mud weight increase G to the old mud weight B yields the new mud weight required to balance the kick.

New Mud Weight To Balance The Kick = Old Mud Weight + Increase In Mud Weight

= 74 + 4 = 78 pcf

Enter the new mud weight in part H of the worksheet.

Step 5 - Total Volume to Weight-Up

There are several reasons why the volume of mud in the surface pits should be reduced after the first circulation, but before weighting-up. Some of these reasons include:

• It takes less time to weight-up less volume • It requires less barite to weight-up less volume • It may overflow the pits if barite is added without reducing first

WELL CONTROL MANUAL




Whatever the reasons, decide on an appropriate pit volume and add it to the total system volume (from your Prerecorded Data Sheet) to determine the total volume to weight-up. In our example, we decided on 500 bbls of active pit volume with 501 bbls of system volume for a total volume of 1001 bbls. to weight-up. Record this value on part I of the worksheet.

Step 6 - Barite Required to Weight-Up

It's an easy matter to determine the amount of barite, which will be required once the total volume to weight-up is known. Use the following formula and record the value at J.

Barite Required = Total Volume 30.0 x Increase In Mud Weight to Weight-up x ________________________________

262.0 - New Mud Weight 30.0 x 4

= 1,001 x __________ 262.0 – 78

= 653 (50# sacks of barite)

Note that this equation assumes you are using 50 pound sacks of barite.

Step 7 - Determining Pressures for the Second Circulation

Remember, when using the Driller's Method we don't calculate circulating pressures. In the Driller's Method, circulating pressures are self-determined. This means that the pressures, which we observe on the gauges, are the pressures that we hold constant while circulating. The values that we record on the Driller's Method worksheet for the casing and drillpipe pressures should be observed values, not calculated values.

On the Driller's Method worksheet, you should record the casing pressure as observed immediately before the start of the second circulation. It should not be much higher than the observed shut-in drillpipe pressure. If it is, you may have another kick in the hole and you should circulate the well as before using the first circulation techniques in order to clear the well of the additional influx. Otherwise, begin the second circulation by holding the observed casing pressure constant while establishing circulation and until the kill mud reaches the bit. You should record the drill string internal capacity (in strokes) on the worksheet to determine when kill mud will reach the bit.

As soon as the kill mud reaches the bit, our focus should turn to the drillpipe gauge. The observed drillpipe pressure at this point should be recorded on the worksheet and held constant for the remainder of the kill. The total system capacity should be written in the appropriate space on the Driller's Method worksheet.

WELL CONTROL MANUAL




Step 8 - Determining Reservoir Pressure

We need to calculate the reservoir pressure as an intermediate step in determining the more critical well control parameters such as maximum casing pressure and excess volume. To determine the reservoir pressure, simply multiply the following:

Reservoir Pressure

= New Mud Weight x 0.007 x True Vertical Depth = 78 X 0.007 x 8000 = 4368 psi

Record this value on the back of the worksheet at K.

Step 9 - Determining Equivalent Bottomhole Gas Bubble Height This is the height of the gas bubble at the bottom of the hole assuming an annulus equal to that at the top of the hole. It is used to determine the maximum surface pressure when the gas bubble reaches the surface. Use the following equation and record on the worksheet.

Initial Pit Volume Increase

Gas Bubble Height = _____________________________________ Annulus Capacity Factor (D.P. x Hole) 15 bbl = ____________ 0.0505 bbl/ft = 297 feet

Step 10 - Determine Maximum Casing Pressure

If the kick is gas, then the maximum casing pressure will occur when the gas first reaches the surface. We must calculate this value before its arrival to determine if our wellhead and casing can withstand the pressure. Unfortunately, the mathematical formula used to determine the maximum casing pressure is somewhat complex. To simplify the calculation of maximum casing pressure, charts have been developed which are included in Section P. The maximum casing pressure (Pc Max) is calculated in two

steps. An equation is used to calculate Part 1, and a chart is used to calculate Part 2.

WELL CONTROL MANUAL




Pc Max (Part 1)

The first part of Pc Max is determined with the following simple formula:

Pc Max – Part 1 (Driller's Method)

Shut-in Drillpipe Pressure = _________________________ 2 For our example, Pc Max Part 1 is therefore equal to:

Pc Max – Part 1 (Driller's Method)

200

= ____ = 100 psi 2

Note: In the past, Pc Max (Part 1) was determined through the use of a

chart, which has since been replaced by the previous equation.

Pc Max (Part 2)

Using Figure P.1, enter the upper left vertical axis at the original mud weight (74 pcf). Read across to an imaginary line for the reservoir pressure (4368 psi); then drop vertically to the line matching the equivalent bottomhole gas bubble height (297 ft). Run a horizontal line to the curve for the PcMax -I value calculated earlier; then run a vertical line up to the PcMax-II axis and

read approximately 760 psi. Record this value at Q on the worksheet. Add O and Q to determine R, the maximum surface casing pressure (860 psi). As an alternative to the charts, equations are provided on the kill sheet.

Generally speaking, the casing pressure is significant only if it should exceed the pressure rating of the casing, well head or BOP's. It is seldom possible to calculate with accuracy whether oil, gas, or water has entered the hole, but with rare exceptions gas is always present. The method described above will indicate the maximum possible casing pressure and pit volume gain if pure gas has entered the wellbore. Water or oil will decrease the casing pressure and volume gain somewhat from those shown on the worksheet, and can be handled satisfactorily.

WELL CONTROL MANUAL




At this point the maximum permissible casing pressure should have been determined and a decision made as to whether to circulate the formation fluid out of the hole.

Note: The method used here to graphically determine the maximum surface pressure is in error by the hydrostatic pressure of the gas column.

Step 11 - Determining Volume Gain for a Gas Kick - Figure P.3

A convenient chart, Figure P.3, is also provided to determine the maximum pit volume gain, which will occur if the kick is completely gas. Enter at the maximum surface casing pressure (860 psi). Read down to the reservoir pressure (4368 psi), then across to the original kick volume (15 bbl). Read down to the horizontal axis to obtain the volume of gas at the surface (64 bbl). Record this volume at T on the worksheet. Subtract the initial pit volume increase E from T to determine the pit volume gain when the gas bubble is circulated to the surface (49 bbl). Record this value.

Step 12 - Determining Maximum Casing Pressure and Excess Volume

Subtract the volume of gas at the surface S from the annulus capacity on the prerecorded well data sheet. This will show approximately when the maximum casing pressure and excess volume will occur (393 – 64 = 329 bbl, 2256 strokes). Record these values in the proper spaces provided. The following pages provide completed samples of the worksheet and Figures used in the previous example problem, including:

• Pre-recorded Data Sheet (Vertical Well) • Driller’s Method Worksheet (Vertical Well) • Figure P.1 (Pc Max Part 2) • Figure P.3 (Volume Gain) • Pre-recorded Data Sheet (Highly Deviated or Horizontal Well) • Driller’s Method Worksheet (Highly Deviated or Horizontal Well)

The Pre-recorded Data Sheets and Worksheets (for both vertical and highly deviated/horizontal wells) are also developed in Excel spreadsheets, which perform all required calculations.

PRE-RECORDED WELL DATA KEEP THIS DATA SHEET CURRENT AT ALL TIMES


















G-15

DRILLER'S METHOD WORKSHEET (Vertical and Deviated Wells)

PRERECORDED INFORMATION SPM psi bbl/stk bbl/minA. Slow Pump Rate Data Pump #1 30 350 0.1458 4.37 ( Use SPR Pressure through Riser for Subsea )Pump #2 40 550 0.1458 5.83

INFORMATION RECORDED WHEN WELL KICKS Time of Kick: 13:35

B. Old Mud Weight B 74 pcfC. Initial Shut-In Drill Pipe Pressure (SIDP) C 200 psiD. Initial Shut-In Casing Pressure (SICP) D 300 psiE. Initial Pit Volume Increase E 15 bblF. True Vertical Depth of Hole F 8,000 ft (TVD) Measured Depth of Hole (for Capacity Calculations ONLY) 8,000 ft (MD)

FIRST CIRCULATION TO CLEAR WELL OF INFLUX

Bring Pumps up to Speed While Holding Casing Pressure Constant 30 SPM{Account for Choke Line Friction if Subsea}

Read and Record Initial Circulating Pressure on Drill Pipe 550 psi[Should Approximately = Slow Pump Rate Pressure (A) + SIDP (C)]

Maintain Constant DP Pressure Until Influx is Circulated Out. Then Shut Down

Pumps While Holding Casing Pressure Constant. {Remember CLF for Subsea}. If DrillPipe and Casing Shut-In Pressures are not Equal, Continue to Circulate Out Influx.

G. Increase in Mud Weight required to Balance Kick

G 4 pcf

H. New Mud Weight H = B + G = H 78 pcf

I. Total Volume to Weight up I = Active Pit Vol + System Vol = I 1,001 bbl

J. Barite RequiredJ 653 50#

sacks

SECOND CIRCULATION TO BALANCE WELL

Bring Pumps up to Speed While Holding Casing Pressure Constant. {Account for Casing Pressure 200 psiCLF if Subsea} Maintain Constant CasingPressure Until New Mud Reaches the Bit. Drill String Internal Capacity 739 strokes

Read and Record Drill Pipe PressureWhen New Mud Reaches the Bit Final Circulating Pressure 369 psiMaintain Constant Drill Pipe PressureUntil the System is Displaced. System Volume 3,436 strokes

Version 2.0 (4/15/00)G-16

DRILLER'S METHOD WORKSHEET (page 2)

RESERVOIR PRESSURE (Pr)K 4368 psi

HEIGHT OF GAS BUBBLE AROUND DRILL PIPE (Kick Height(KH))L. Annulus Capacity Factor (DP x Casing) Right Below Wellhead L 0.0505 bbls/ft

M 297 ft.

MAXIMUM CASING PRESSURE (Pcmax) WHEN GAS GETS TO SURFACEN. Mud Weight Gradient, psi/ft N 0.52 psi/ft.

O. (Surface) O 100 psi

(Optional Correction for Subsea Wells)O. (Subsea) A correction must be added to PCmax, Part 1 calculated above to

account for the choke line.0 psi

(Subsea) O = Subsea Correction + (Surface) O = (Subsea) O 100 psi

(Use this new O in Part Q and Part R below)

P. TZ= Compressibility and Temperature Effects (Figure 11P.5) P 0.84

Q. Pcmax, Part2 (Figure 11P.1)

Q 760 psi

R. Maximum Casing Pressure,R 860 psi

S. Does Pcmax Exceed the Wellhead or Casing Pressure Limitation?YES NO X

VOLUME GAIN WHILE CIRCULATING OUT GAS BUBBLET. Volume of Gas at Surface (from Fig. 11P.4 or Formula below)

T 64.4 bbl

U. Volume Gain While Circulating Out Gas Kick U 49.4 bbl

STROKES TO MAXIMUM CASING PRESSURE AND VOLUMEMaximum Casing Pressure and Excess Volume Occur When the Pumped Volume Equals Total Annulus Capacity - Volume of Gas at Surface bbl strokes

328.8 2256

G-17

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Drilling & Workover October 2002 __ SECTION G – DRILLER’S METHOD

















(continued on next page) Version 2.0 (4/15/00)G - 20

PRERECORDED WELL DATA (Highly Deviated and Horizontal Wells)

(page 2)











G - 21

DRILLER'S METHOD WORKSHEET(Highly Deviated and Horizontal Wells)

PRERECORDED INFORMATION SPM psi bbl/stk bbl/minA. Slow Pump Rate Data Pump #1 30 350 0.1458 4.4 ( Use SPR Pressure through Riser for Subsea )Pump #2 40 550 0.1458 5.8

INFORMATION RECORDED WHEN WELL KICKS Time of Kick: 13:35

B. Old Mud Weight B 74 pcfC. Initial Shut-In Drill Pipe Pressure (SIDP) C 200 psiD. Initial Shut-In Casing Pressure (SICP) D 300 psiE. Initial Pit Volume Increase E 15 bblF. True Vertical Depth of Hole F 6,000 ft (TVD) Measured Depth of Hole (for Capacity Calculations ONLY) 8,300 ft (MD)

FIRST CIRCULATION TO CLEAR WELL OF INFLUX

Bring Pumps up to Speed While Holding Casing Pressure Constant 30 SPM{Account for Choke Line Friction if Subsea}

Read and Record Initial Circulating Pressure on Drill Pipe 550 psi[Should Approximately = Slow Pump Rate Pressure (A) + SIDP (C)]

Maintain Constant DP Pressure Until Influx is Circulated Out. Then Shut Down

Pumps While Holding Casing Pressure Constant. {Remember CLF for Subsea}. If DrillPipe and Casing Shut-In Pressures are not Equal, Continue to Circulate Out Influx.


G 5 pcf



J. Barite RequiredJ 838 50#

sacks

SECOND CIRCULATION TO BALANCE WELL

Bring Pumps up to Speed While Holding Casing Pressure Constant. {Account for Casing Pressure 200 psiCLF if Subsea} Maintain Constant CasingPressure Until New Mud Reaches the Bit. Drill String Internal Capacity 720 strokes

Read and Record Drill Pipe PressureWhen New Mud Reaches the Bit Final Circulating Pressure 374 psiMaintain Constant Drill Pipe PressureUntil the System is Displaced. System Volume 3,581 strokes

Version 2.0 (4/15/00)

G-22

DRILLER'S METHOD WORKSHEET (page 2)

RESERVOIR PRESSURE (Pr)K 3318 psi

HEIGHT OF GAS BUBBLE AROUND DRILL PIPE (KH) L. Annulus Capacity Factor (DP x Casing) Right Below Wellhead L 0.0505 bbls/ft

M 297 ft.

MAXIMUM CASING PRESSURE (Pcmax) WHEN GAS GETS TO SURFACEN.

N 0.52 psi/ft.

O. O 100 psi

P. TZ= Compressibility and Temperature Effects (Fig 11P.5) P 0.95

Q. Pcmax, Part2 (Figure 11P.1)

Q 703 psi

R. Maximum Casing Pressure,R 803 psi

S. Does Pcmax Exceed the Wellhead or Casing Pressure Limitation?

YES NO X

VOLUME GAIN WHILE CIRCULATING OUT GAS BUBBLET. Volume of Gas at Surface (from Fig. 11P.4 or Formula below)

T 59 bbl

U. Volume Gain While Circulating Out Gas Kick U 44 bbl

STROKES TO MAXIMUM CASING PRESSURE AND VOLUMEMaximum Casing Pressure and Excess Volume Occur When the Pumped Volume Equals Total Annulus Capacity - Volume of Gas at Surface

bbl strokes358.1 2457

G-23

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SECTION H – ENGINEER’S METHOD

Current Revision: October 2002 H - 1 3rd Edition Previous Revision: October 1998

Table of Contents

1. 0 Description of the Method................................................................. H-2 Step 1 The Kick Is Detected - Shut The Well In....................................... H-2

Shut-In Procedure while Drilling .................................................... H-2 Shut-In Procedure while Tripping ................................................... H-2

Step 2a Allow the Well to Stabilize ........................................................... H-3 Step 2b Bumping the Drillpipe Float ........................................................ H-3 Step 3 Perform the Kick Control Calculations........................................ H-4 Step 4 Raise the Mud Weight in the Pits................................................. H-4 Step 5 Establish Circulation .................................................................. H-5 Step 6 Pumping Kill Mud from Bit .......................................................... H-6 Step 7 Pumping Kill Mud from Bit to Surface ......................................... H-6 Step 8 Shut Down and Check for Flow ................................................... H-7 Step 9 Circulate and Condition the Mud................................................. H-7

2.0 Using the Engineer’s Method Worksheet ..................................... H-8 Step 1 Pre-recorded Information............................................................ H-8 Step 2 Information to be Recorded when Well Kicks ............................. H-9 Step 3 Determining Mud Weight to Balance the Kick ............................. H-9

Rounding-Up Rule......................................................................... H-9 Step 4 Total Volume to Weight-Up........................................................ H-10 Step 5 Barite Required to Weight-Up.................................................... H-10 Step 6 Determining Initial Circulating Pressure ................................... H-10 Step 7 Determining Final Circulating Pressure .................................... H-11 Step 8 Drillpipe Pressure Schedule...................................................... H-11 Step 9 Determining Reservoir Pressure ............................................... H-13 Step 10 Determining Maximum Casing Pressure ................................... H-13

Pc Max (Part 1)........................................................................... H-13 Pc Max (Part 2)........................................................................... H-13

Step 11 Determining Pit Volume Gain for a Gas Kick ............................. H-14 Step 12 Maximum Casing Pressure & Excess Volume Occurrence ....... H-14

Pre-recorded Well Data Sheet (Vertical Well).......................................... H-16 Engineer's Method Worksheet (Vertical Well)......................................... H-17

Figure P.2a (Pc Max - Part 1) ................................................................... H-19 Figure P.2b (Pc Max - Part 2) .................................................................. H-20 Figure P.3 (Volume Gain) ...................................................................... H-21 Pre-recorded Well Data Sheet (Highly Deviated or Horizontal Well)........ H-22 Engineer’s Method Worksheet (Highly Deviated or Horizontal Well)....... H-24

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1.0 Description of the Method

The Engineer's Method (also called the wait and weight method) is a well killing method that requires only one complete circulation. The kill mud is circulated into the well at the same time the kick is being removed from the annulus. During the circulation, the bottomhole pressure is maintained at level equal to or slightly greater than the formation pressure. The following information describes the Engineer's Method in detail from kick to kill.

Step 1 - The Kick Is Detected (Shut the Well In)

As always, it is extremely important to get the well shut -in as quickly as possible in order to minimize the size of the influx. The best way to achieve this is by using the “Three S” Shut-In Procedure while Drilling or the “Three S” Shut -In Procedure while Tripping.

Shut-In Procedure While Drilling





Shut-In Procedure While Tripping

(1) STAB VALVE Install Full Open Safety Valve (open position) in drill string. Close the safety valve.

(2) SPACE OUT Spot tool joint.



It should be stressed that in nearly all well kicks, the Driller will be responsible for actually closing the preventers and shutting the well in. It is the duty of the Saudi Aramco Drilling Foreman to make sure the Driller can execute the proper shut-in procedure. The Driller must have the initiative and experience to do this alone if required. There will be plenty of time after the well is shut-in to retrieve crews from the mud pits and notify the Toolpusher. The Driller must not delay when shutting in the well.

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Step 2a - Allow the Well to Stabilize, Record Pressure and Volume Gained After the well is shut-in, it may take a few minutes for the shut-in pressures to stabilize. If the pipe is reciprocated through the annular preventer during the kill, use this time to reduce the annular closing pressure to reduce element wear. Make sure the bag does not leak at the reduced pressure!

With your choke manifold lined-up properly, open the choke line valve at the preventer stack and read the shut-in casing pressure at the choke manifold. If no drillpipe float is installed, read and record the shut-in drillpipe pressure as well. Finally, examine the pit volume charts to determine the volume gained during the kick and verify this number with the Derrickman.

Step 2b - Bumping the Drillpipe Float If a drillpipe float is installed, the pressure gauge on the drillpipe will probably read near zero. In order to get an accurate value for the shut-in drillpipe pressure, “bump” the float open by slowly pumping down the drillpipe. The correct procedure for bumping the float is given below.


(1) Make sure the well is shut-in and that the shut-in casing pressure is

recorded. (2) Slowly pump down the drillpipe while monitoring both the casing and

drillpipe pressure. (3) The drillpipe pressure will increase as pumping is begun. Watch carefully

for a “lull” in the drillpipe pressure (a hesitation in the rate of increase), which will occur as the float is pumped off of its seat. Record the drillpipe pressure when the lull is first seen.

(4) To verify that the float has been pumped open, continue pumping down the drillpipe very slowly until an increase in the casing pressure is observed. This should occur very soon after the lull is detected on the drillpipe gauge.

(5) Shut down the pump as soon as you see the casing pressure begin to increase and record the shut-in drillpipe pressure as the pressure at which the lull was first seen, in Step 3 above (not the final drillpipe pressure after the pumps are stopped).

(6) Check the shut-in casing pressure again. Any excess pressure may be bled-off in small increments until equal casing pressure readings are observed after two consecutive bleed-offs.

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Sometimes the float bumping procedure can be difficult to perform if the rig has big duplex pumps, which are compounded. Clutch the pumps in short burst to slowly build up pressure on the drillpipe. It’s more likely that a drillpipe “lull” won’t take place before the casing pressure starts to increase when using this procedure. To determine the shut-in drillpipe pressure in these instances, subtract the increase in shut-in casing pressure from the final value of shut-in drillpipe pressure after the pumps have been stopped. The equation for this calculation is given below. Use this value as the official shut-in drillpipe pressure.

If excess pressure is trapped on the drillpipe when bumping the float… Shut-in Shut-in drillpipe Increase in shut-in Drillpipe = pressure after - casing pressure while Pressure bumping float bumping float.

Step 3 - Perform the Kick Control Calculations

Calculations should be performed using the Engineer's Method Worksheet before the kill mud is circulated into the well. Several critical items will be determined including:

• Drillpipe pressure schedule • Bottomhole reservoir pressure • Mud weight necessary to balance the kick • Maximum surface casing pressure during the kill circulation • Maximum excess mud volume gained during the kill circulation

An example problem illustrating the use of the Engineer's Method Worksheet is provided later in this section.

One thing to keep in mind while performing your calculations is that the formation fluids in the annulus, especially gas, may migrate up the hole and cause an increase in the shut-in casing pressure. If the shut-in casing pressure starts increasing substantially to the point of risking an underground blowout or exceeding the wellhead or casing pressure limitation, bleed-off some of the excess pressure through the choke. It is better to bleed the pressure off in small increments rather than one large slug. Any excess pressure, which appears on the annulus due to the migrating gas bubble, may be bled-off in small increments until equal readings are observed after two consecutive bleed-offs.

Step 4 - Raise the Mud Weight in the Pits

As soon as the required mud weight has been calculated, raising the mud weight in the pits should begin. The first step is to reduce the mud volume in the active pits to make room for weighting material. The amount of barite required to increase the mud weight is determined in part ‘J’ of the Engineer's Method Worksheet. If barite required

WELL CONTROL MANUAL




exceeds barite on hand, either further reduce the volume in the active system or proceed with the Drillers Method. The mud mixing facilities and pit volumes on the particular rig will dictate to some extent just how the mud should be handled. The ideal situation is to maintain a reasonably low-volume active system so that the mud circulated out of the hole can be weighted up without having to stop circulating. It may be desirable to weight up enough mud to displace the entire hole before the killing operation is started. Many variables will enter into this decision, so each situation must be handled on its own merits. The important thing is that the mud weight can be raised while the well is being circulated.

Meanwhile, formation fluids in the annulus, especially gas, will migrate, causing an increase in casing pressures. Also, the longer formation fluids are in the annulus, the more likely pipe sticking becomes. Therefore, it is important to proceed as quickly as possible.

Step 5 - Establish Circulation

After the kick control calculations have been performed and the mud has been weighted-up properly, the well should be circulated through the choke using the information recorded on the Engineer's Method Worksheet. Before breaking circulation, be sure to check the following items.

(1) Be sure that all members of the crew knows exactly what his duties are

before the kill operation begins. (See Section M in this volume for more details.)

(2) Eliminate all sources of ignition in the immediate vicinity of the rig and vent lines. See that the vent lines on the mud-gas separator and mud degasser are secured properly and, if possible, are downwind from the rig.

(3) Make sure your circulating system (including manifolds and pits) are lined-up correctly.

(4) Zero the stroke counter and make a note of the time.

When establishing circulation in a well closed in under pressure, backpressure on the well is very difficult to control. The procedure is critical, since additional influx will result if too little backpressure is held, and the formation can breakdown if too much backpressure is held.

The procedure requires simultaneous manipulation of the choke and the pump speed. While the pumps are being brought up to speed, the choke is opened in such a way that casing pressure is maintained constant at its shut-in value just prior to the start of pumping. As the pump speed is increased up to the desired kill rate, drillpipe pressure will increase, but casing pressure must be held constant. Successful manipulation of the choke while establishing circulation in this manner will maintain constant bottomhole pressure.

WELL CONTROL MANUAL




The chosen pump rate must be held constant throughout the killing of the well. If the pump rate is allowed to vary without adjusting the choke size, constant bottomhole pressure will not be maintained. If the pump rate is increased, additional friction pressure will cause the drillpipe pressure to increase. If the choke is adjusted to lower the drill pipe pressure to its assumed correct value, then the bottomhole pressure is reduced, possibly allowing another influx. Conversely, if the pump rate is reduced, the reduction in friction pressure will be noted and the choke adjusted to increase the drill pipe pressure, possibly creating sufficient overpressure at the casing shoe to cause a breakdown. Therefore, any change in pump rate should be made known to the choke operator and the pump returned to the original rate.

Step 6 - Follow the Drillpipe Pressure Schedule While Pumping Kill Mud

After circulation has been established and the pumps are operating at the desired kill rate, the previously calculated initial circulating pressure should be observed on the drillpipe pressure gauge. As the kill mud goes down the drillpipe, gradually adjust the choke so that the drillpipe pressure closely tracks the drillpipe pressure schedule calculated earlier. At this point in the kill procedure, constant bottom-hole pressure is being maintained by following the drillpipe pressure schedule and by making slight choke adjustments. Do not change the pump rate to accomplish this. Also, do not make choke adjustments in order to keep the casing pressure constant while the drillpipe is being displaced with kill mud. When an influx rises above the drill collars to around the drillpipe, the influx column height is reduced as a result of the larger annular capacity around the drillpipe as compared to around the drill collars. This reduction increases the hydrostatic head in the annulus. Therefore, as constant bottomhole hold pressure is being maintained by following the drillpipe profile, it is possible to see a drop in casing pressure as the influx height shortens.

When the kill weight mud gets to the bottom of the drill string, the pressure on the drillpipe should be the final circulating pressure, as recorded at ‘L’ on the worksheet.

Step 7 - Hold the Drillpipe Pressure Constant for the Remainder of the Kill

When kill mud starts to be circulated up the annulus, the choke must be manipulated so that drillpipe pressure is maintained constant at the final circulating pressure.

As the gas and contaminated mud are circulated to the surface, the gas will begin to expand, increasing both the casing pressure and pit volume. A pure gas contaminant will increase the casing pressure to the value shown at ‘W’ on the worksheet. It will be less if the kick also includes water and/or oil. Probably the most critical stage of the killing operation takes place at this time, and panicking can very turn a good job into a disaster.

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It can sometimes be difficult to bleed the gas off fast enough to keep the drill pipe pressure within limits, but excessive pressure could cause formation breakdown. If the gas cannot be released fast enough from the annulus to prevent an increase in drill pipe pressure, the pumps may have to be slowed or even stopped until the casing pressure is bled down. For this reason, it is a good idea to take several slow pump rates (including one at the slowest pump rate possible) so that the new drillpipe pressure at the reduced pumping rate can be determined. If the pumps must be stopped while bleeding down the casing pressure, attempt to hold the drillpipe pressure at or above the original shut-in pressure while bleeding. If the drillpipe pressure drops below this value, another kick may occur. The pumps should be returned to the original rate as soon as possible. This method is not ideal, but is necessary when the surface facilities cannot safely handle the high flow rates.

Continue circulation until the entire system is full of the kill weight mud. The approximate strokes required are indicated on the pre-recorded data sheet.

Step 8 - Shut Down and Check for Flow

After the entire hole volume has been displaced with kill mud, the pumps can be shut down and the well shut-in. When shutting down the pumps, the choke should be closed (holding casing pressure constant) gradually as the pump speed is reduced.

Note: The casing pressure may already be reading zero before the pumps are

shut down. This is normal and may be expected.

As the pump speed decreases, the drillpipe pressure will slowly decrease to zero. After the well is shut-in, both the casing and drillpipe pressures should be zero. Confirm that the well is dead by cracking open the choke; the well should not flow. If the well is dead, the BOP's can be opened. Keep in mind that a small volume of gas may be trapped between the annular preventer and the choke line. Exercise caution on the rig floor when opening the preventers.

Step 9 - Circulate and Condition the Mud

After the BOP’s are opened, the mud should be circulated and conditioned to the desired properties. Usually, the yield point is too high. Thus, running or pulling pipe can cause excessive pressure on the formation or swabbing, and either could lead to another kick.

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2.0 Using the Engineer’s Method Worksheet The Engineer's Method Worksheet is a step-by-step instruction sheet to help the Drilling Foreman calculate the critical well control parameters that are necessary to successfully kill a well using the Engineer's Method. Use of the Worksheet is demonstrated here through the use of an example problem described below:

EXAMPLE PROBLEM A well is being drilled, and the following data are known prior to kick:

Triplex Pumps: 16” stroke, 96% vol. eff. (6-1/4” liner) Casing Size: 9-5/8” set at 5,500 ft MD/TVD Hole Size: 8-1/2” Csg Pressure Limitation: 3,160 psi @ 80% burst Shoe Test: 2,040 psi with 74 pcf mud Drill Pipe Size: 4-1/2”, 16.60 lb/ft Drill Collar Size: 6-3/4” OD x 2-13/16” ID (450 ft long) Mud Weight: 74 pcf Active Surface System: 750 bbls before kick 500 bbls at start of kill operation Slow Pump Rate Data: SPM PSI 30 350 40 550 While drilling at 8,000' TVD, the well kicked and the BOP's were closed. The following data were observed:

Initial Drill Pipe Pressure = 200 psi Initial Casing Pressure = 300 psi

Pit Volume Gain = 15 bbl

The following pages describe a step-by-step procedure for determining the well control parameters, which are necessary to kill the example problem well using the Engineer's Method.

Step 1 - Pre-recorded Information

Prior to the kick, and at all times, your pre-recorded data sheet should be completely filled-out except for the measured depth and the length of drillpipe in the hole. Enter these items and calculate the internal drillstring capacity and the system totals. Transfer the slow pump rate data from the pre-recorded data sheet to line A of the Engineer's Method worksheet.

WELL CONTROL MANUAL




Step 2 - Information to be Recorded when Well Kicks

Many items of information need to be gathered when a well kicks. These include:

• Old Mud Weight • Pit Volume Increase • Initial Shut-in Drill Pipe Pressure • True Vertical Depth Of Hole • Initial Shut-in Casing Pressure • Measured Depth Of Hole

This information should be recorded in lines B through F on the Engineer's Method worksheet.

Step 3 - Determining Mud Weight to Balance the Kick

Using the equation below, calculate the increase in mud weight necessary to balance the kick.

Increase in Initial Shut-in Drillpipe Pressure (SIDP)

Mud Weight = ------------------------------------------ 0.007 X TVD

200 = ------------------- 0.007 X 8,000

= 3.6 pcf

Rounding-Up Rule: The increase in mud weight should be calculated to the tenths

place. If the number in the tenths place is greater than zero, then roundup the number one full pcf. In this example, the number in the tenths place is six, so the weight is rounded-up to 4 pcf.

Record an 4 pcf increase on line G of the Engineer's Method worksheet. Adding the mud weight increase G to the old mud weight B yields the new mud weight required to balance the kick.

New Mud Weight To Balance The Kick = Old Mud Weight + Increase In Mud Weight

= 74 + 4 = 78 pcf

Enter the new mud weight in part H of the worksheet.

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The mud weight determined by this procedure will provide a hydrostatic pressure equal to the BHP and sufficient to kill the well, but perhaps not high enough for making a trip. Weighting up a mud increases its yield point, causing increased pressure on the formation during circulation (the equivalent circulating density). As extra mud weight and a higher yield point could fracture the formation, it is best to adjust the yield point and add a trip margin after the well is killed.

Step 4 - Total Volume to Weight-Up

As discussed in the Driller's Method, there are several reasons why you should reduce the volume of mud in your surface pits before weighting up. Again some of these reasons are:

• It takes less time to weight up less volume. • It requires less barite to weight up less volume. • It may overflow your pits while you are circulating the influx out.

Whatever the reason, decide on the volume that you are going to use and add it to your system volume (from the pre-recorded data sheet) to determine the total volume to weight up. In our example we again used 500 barrels to arrive at a total volume to weight up of 1,001 bbls. Record this value at I on the worksheet.

Step 5 - Barite Required to Weight-Up

Again, the same formula used to determine barite requirements for the Driller's Method will be used to calculate the volume required for the Engineer's Method. The equation is shown below:

Barite Required = Total Volume 30.0 x Increase in Mud Weight

to Weight Up x ___________________________

262.0 – New Mud Weight

Note that this equation assumes you are using 50 pound sacks of barite.

Step 6 - Determining Initial Circulating Pressure

Immediately after the pumps are operating at the desired kill rate and kill mud is going down the hole, the initial circulating pressure should be observed on the drillpipe gauge. The initial circulating pressure can be calculated by adding the slow pump rate pressure at the desired kill rate A to the initial shut-in drill pipe pressure C. This is expressed mathematically by:

Initial Circulating Pressure = Slow Pump Rate Pressure + Shut-in Drillpipe Pressure

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In this example 30 SPM was selected; therefore the initial circulating pressure will be 200 + 350 = 550 psi; record this value at K.

Note: If for some reason the pre-recorded circulating pressures at various rates are unavailable, the initial drill pipe circulating pressure can be determined by proceeding as follows:

a) Hold casing pressure constant until the pump is at the desired speed.

b) Read the drill pipe pressure at that time. This pressure minus the

initial shut-in drill pipe pressure will be the reduced circulating pressure at the desired speed and would be used to calculate the final circulating drill pipe pressure.

This procedure is enumerated in step form on the back of the Engineer’s Method worksheet.

Step 7 - Determining Final Circulating Pressure

The final circulating pressure is the pressure the drillpipe gauge should read when kill mud reaches the bit. The final circulating pressure can be calculated by the formula:

Final Circulating Pressure = Slow Pump x New Mud Weight Rate Pressure Old Mud Weight

= 200 x 78 74 = 369 psi

Step 8 - Drillpipe Pressure Schedule

Successful well killing with the Engineer's Method requires that the drillpipe pressure decrease from a higher value (initial circulating pressure) to a lower value (final circulating pressure) as kill mud is pumped down the drillstring. It is very important that the drillpipe pressure be reduced smoothly in small increments as the drillpipe is filled with kill mud. The drillpipe pressure should not be reduced all at once when the kill mud reaches the bit.

In order to accomplish the smooth transition from initial circulating pressure to the final circulating pressure, create a drillpipe pressure schedule which displays the correct circulating drillpipe pressure at 50 or 100 stroke increments as kill mud is pumped down the drillstring. The Drilling Foreman can track the drillpipe pressure and the pump strokes and make small choke adjustments so that the observed drillpipe pressures are equal to the calculated values displayed on the schedule at all

WELL CONTROL MANUAL




points during the circulation. It is important to realize that this drillpipe pressure drop should require minimal choke adjustments since the hydrostatic pressure in the drillpipe will be increasing automatically as the kill mud is pumped down.

The first step in creating the drillpipe pressure schedule is to transfer the internal, annulus and system capacity values from the pre-recorded data sheet to lines N and O on the Engineer's Method worksheet. Next, record your calculated initial circulating pressure K on the top/right side of the schedule table and record zero strokes on the left side. Next, record your calculated final circulating pressure L on the bottom line of the schedule table [on the right] opposite the total internal stroke capacity [on the left]. We now need to fill-in the lines between the initial circulating pressure and the final circulating pressure on the drillpipe pressure schedule table. The drillpipe pressure drop per stroke can be calculated with the following formula:

Drillpipe Pressure Initial Circulating Pressure – Final Circulating Pressure

Drop (per stroke) = ________________________________________________

Total Internal Stroke Capacity

550 - 369 = _________ 744 = 0.24 psi/stroke

This equation will normally yield a fraction of a psi reduction per pump stroke, which is too small for us to accurately measure on the rig. Therefore, arbitrarily choose a stroke increment (100 strokes), which becomes the point of reference as kill mud is pumped down the drillpipe. Instead of reducing the drillpipe pressure 0.24 psi per stroke, we reduce it 24 psi per 100 strokes (which is essentially the same thing). Then, subtract this pressure decline (24 psi per 100 strokes) from the initial circulating pressure at each increment until the final circulating pressure at the total internal capacity is reached. The schedule is completed by adding stroke increments on the left side and subtracting pressure increments from the right side.

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Step 9 - Determining Reservoir Pressure

Calculate the reservoir pressure as an intermediate step in determining the more critical well control parameters such as maximum casing pressure and excess volume. To determine the reservoir pressure, simply multiply the following:

Reservoir Pressure = New Mud Weight x 0.007 x True Vertical Depth

= 78 x 0.007 x 8000 = 4368 psi

Record this value on the back of the worksheet at P.

Step 10 - Determining Maximum Casing Pressure

If the kick is gas, then the maximum casing pressure will occur when the gas first reaches the surface. We must calculate this value before its arrival to determine if our wellhead and casing can withstand the pressure. Unfortunately, the mathematical formula used to determine the maximum casing pressure is complex. To simplify the calculation of maximum casing pressure, charts have been developed and are included in the back of this section and Section P. The maximum casing pressure (Pc

Max) is calculated in two steps so two charts are required.

Pc Max (Part 1) On Figure P.2a, enter the left vertical axis at the true vertical depth (8,000 ft), and read across to the line for the drillpipe by hole annulus capacity factor (use line B: 8-5/8" hole, 4-1/2" drillpipe). Drop a vertical line to the increase in mud weight (4 pcf), and then read across to the right vertical axis to find Pc max Part 1 (30 psi). Record this value at U.

Pc Max (Part 2) On Figure P.2b, begin at the upper horizontal axis at the new mud weight (78 pcf). Drop a vertical line to the reservoir pressure (4368 psi), and then run a horizontal line to the curve corresponding to the original kick volume (15 bbl). Drop another vertical line to the drillpipe by hole annulus capacity factor (8-5/8" hole, 4-1/2" drillpipe), then run a horizontal line to the right vertical axis and read Pc Max (Part 2). Record this value (774 psi) at V on

the worksheet.

To determine the maximum surface casing pressure while properly circulating out a pure gas kick (Pc Max) simply add U to V; record this value at W. As an alternative to the charts, the killsheet provides equations to calculate Pc Max.

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The next question is very important and its answer may determine the course of action, which is taken for the kill. In most cases, it will be allowed to go to 100% of the wellhead pressure or BOP ratings, but only 80% of the casing burst pressure. Generally speaking, the casing pressure is significant only if it should exceed the pressure rating of the casing, well head or BOPs. It is seldom possible to calculate with accuracy whether oil, gas, or water has entered the hole, but with rare exceptions gas is always present. The method described above will indicate the maximum possible casing pressure and pit volume gain if pure gas has entered. Water or oil will decrease the casing pressure and volume gain somewhat from those shown on the worksheet, and can be handled satisfactorily.

At this point the maximum permissible casing pressure should have been determined and a decision made as to whether to circulate the formation fluid out of the hole.

Note: The method used here to graphically determine the maximum surface pressure is in error by the hydrostatic pressure of the gas column.

Step 11 - Determining Pit Volume Gain for a Gas Kick

A convenient chart is also provided to determine the maximum pit volume gain, which will occur if the kick is completely gas. Use Figure P.3 to calculate the volume gained. Enter the top right horizontal axis at the maximum surface casing pressure (804 psi). Read down to the reservoir pressure (4368 psi) then across to the original kick volume (15 bbl). Read down to the horizontal axis to obtain the volume of gas at the surface (69 bbl); record this volume at X. Subtract the initial pit volume increase E from X to determine the pit volume gain due to gas expansion while the bubble is being circulated to the surface (54 bbl); record this value at Y. The volume gained due to barite addition is simplified by the equation shown in part Z. It is approximated by dividing the barite required to weight up J by 30 sacks of barite per bbl of additional volume increase; record this value at Z. The total volume gain while circulating out a gas kick is calculated by adding part Y to part Z; record this value on the back of the worksheet.

Step 12 - Determining when Maximum Casing Pressure & Excess Volume Occur

Subtract the volume of gas at the surface X from the annulus capacity N to determine when the maximum casing pressure and excess volume will occur (393 - 69 = 324 bbl, or 2225 strokes). Record these values in the proper spaces provided.

WELL CONTROL MANUAL




Note: The maximum casing pressure and excess volume may not occur exactly at the number of strokes calculated due to gas migration or hole washout.

The following pages provide completed samples of the worksheet and Figures used in the previous example problem, including:

• Pre-recorded Data Sheet (Vertical Well) • Engineer’s Method Worksheet (Vertical Well) • Figure P.2a (Pc Max - Part 1) • Figure P.2b (Pc Max - Part 2) • Figure P.3 (Volume Gain) • Pre-recorded Data Sheet (Highly Deviated or Horizontal Well) • Engineer’s Method Worksheet (Highly Deviated or Horizontal Well)

The Pre-recorded Data Sheets and Worksheets (for both vertical and highly deviated/horizontal wells) are also developed in Excel spreadsheets, which perform all required calculations.



















H-16

ENGINEER'S METHOD WORKSHEET (Vertical and Deviated Wells)

SPM psi bbl/stk bbl/minA. Slow Pump Rate Data Pump #1 30 350 0.1458 4.37 ( Use SPR Pressure thru Riser for Subsea ) Pump #2 40 550 0.1458 5.83

Time of Kick: 13:35B. Old Mud Weight B 74.0 pcfC. Initial Shut-In Drill Pipe Pressure (SIDP) C 200 psiD. Initial Shut-In Casing Pressure (SICP) D 300 psiE. Initial Pit Volume Increase E 15 bblF. True Vertical Depth of Hole F 8000 ft (TVD) Measured Depth of Hole (for Capacity Calculations ONLY) 8000 ft (MD)


G 4.0 pcf

H. New Mud Weight H = B + G = H 78.0 pcf

I. Total Volume to Weight up I = Active Pit Vol + System Vol = I 1001 bbl

J. Barite RequiredJ 653 50# sacks

K. Slow Pump Rate Pressure + SIDP K = A + C = K 550 psi

L. Slow Pump Rate Pressure X (New Mud Wt / Old Mud Wt) L 369 psi

strokesM. Total Internal Capacity (from Prerecorded Well Data) M 739 107.7 bblN. Total Annulus Capacity (from Prerecorded Well Data) N 2697 393.2 bblO. System Volume (from Prerecorded Well Data) O 3436 500.9 bbl

24.5 psi/strk incr

Strokes Pressure (psi)0 550 = Initial Circ. Press. (K)

100 525200 501300 476400 452500 427600 403700 3780 0 0

Total Internal Cap (M) = 739 369 = Final Circ. Press. (L)

H-17 Version 2.0 (4/15/00)

ENGINEER'S METHOD WORKSHEET (page 2)

RESERVOIR PRESSURE (Pr)P 4368 psi

MAXIMUM CASING PRESSURE (Pcmax) WHEN GAS GETS TO SURFACEQ. Drill String Capacity from Prerecorded Data Q 108 bbl

R. Annulus Capacity Factor (DP x Casing) Right Below Wellhead = R 0.0505 bbl/ft

S. Temperature and Compression Effects. (From Fig. 11P.5 or Formula Below)S 0.84

T. New Mud Weight GradientT 0.55 psi/ft

(Surface) U 30 psi

(Optional Correction for Subsea Wells)U. (Subsea) A correction must be added to PCmax, Part 1 calculated above to

account for the choke line.

0 psi

(Subsea) U = Subsea Correction + (Surface) U = (Subsea) U 30 psi

(use this new U in Part V. and Part W. below)

V 774 psi

W. Maximum Casing Pressure,W 804 psi

Does Pcmax Exceed the Wellhead or Casing Pressure Limitation?YES NO X

VOLUME GAIN WHILE CIRCULATING OUT GAS BUBBLEX. Volume of Gas at Surface (From Formula Below)

X 69 bbl

Y. Volume Gain While Circulating Out Gas Kick Y = X - E Y 54 bbl

Z. Volume Gain due to Barite Addition Z 22 bbl

Total Volume Gain While Circulating Out Gas Kick = Y + Z 76 bbl

STROKES TO MAXIMUM CASING PRESSURE AND VOLUMEMaximum Casing Pressure and Excess Volume Occur When the Pumped Volume Equals

bbl strokesTotal Annulus Capacity - Volume of Gas at Surface =N - X 324 2225

H-18

WELL CONTROL MANUAL



















(continued on next page) Version 2.0 (4/15/00)H-22

PRE-RECORDED WELL DATA (Highly Deviated and Horizontal Wells)

(page 2)











H-23

ENGINEER'S METHOD WORKSHEET(Highly Deviated and Horizontal Wells)

PRERECORDED INFORMATION SPM psi bbl/stk bbl/minA. Slow Pump Rate Data Pump #1 30 350 0.1458 4.4 ( Use SPR Pressure thru Riser for Subsea ) Pump #2 40 550 0.1458 5.8

INFORMATION RECORDED WHEN WELL KICKS Time of Kick: 13:35B. Old Mud Weight B 74 pcfC. Initial Shut-In Drill Pipe Pressure (SIDP) C 200 psiD. Initial Shut-In Casing Pressure (SICP) D 300 psiE. Initial Pit Volume Increase E 15 bblF. True Vertical Depth of Hole F 6,000 ft (TVD) Measured Depth of Hole (for Capacity Calculations ONLY) 8,300 ft (MD)

MUD WEIGHT TO BALANCE KICKG. Increase in Mud Weight required to Balance Kick

G 5 pcf



J. Barite RequiredJ 838 50# sacks

INITIAL CIRCULATING PRESSUREK. Slow Pump Rate Pressure + SIDP K = A + C = K 550 psi

FINAL CIRCULATING PRESSUREL. Slow Pump Rate Pressure X (New Mud Wt / Old Mud Wt) L 374 psi

CIRCULATING PRESSURE AT KICKOFF POINTM. Total Internal Capacity (from Prerecorded Well Data) M 720 strokes

N. Surface to Kickoff Point Strokes (from Prerecorded Data) N 290 strokes

O. Hydrostatic Pressure Increase Due to KWM at Kickoff Pt.O 105 psi

P. Friction Pressure Increase Due to KWM at Kickoff Pt.P 10 psi

Q. Circulating Pressure at Kickoff PointQ = K - O + P Q 455 psi

CIRCULATING PRESSURE AT START OF HOLD

R. Strokes from Kickoff Point to Start of Hold (from Prerecorded Well Data) R 374 strokes

S. Hydrostatic Pressure Increase Due to KWM at Start of Hold S 210 psi

T. Friction Pressure Increase Due to KWM at Start of Hold T 22 psi

Version 2.0 (4/15/00)

H-24


U. Circulating Pressure at Start of Hold

U = K - S + T = U 362 psi

V. Strokes from Hold Point to TD (from Prerecorded Well Data) V 56 strokes

DRILL PIPE PRESSURE PROFILE

W. Pressure Drop Per Stroke to Kickoff Point

W 0.3290 psi per stroke

X. Pressure Drop Per Stroke from Kickoff to Start of Hold

X 0.2479 psi per stroke

Y. Pressure Drop Per Stroke from Hold Point to TD(note: for a horizontal well this will be negative, meaning the pressure will increase each stroke increment)

Y -0.2113 psi per stroke

Strokes Pressure (psi)0 550 = Initial Circ. Press. (K)40 53780 524120 511160 497200 484240 471280 4580 00 0

Kickoff Pt. (N) 290 455 = Kickoff Pt. Circ. Press. (Q)390 430490 405590 3800 00 00 00 00 0

Start of Hold (R+N) 664 362 =Circ Press. @ Start of Hold(U)670 363680 365690 367700 369710 3710 00 00 00 0

Total Int. Cap. (M) 720 374 =Final Circ. Press. (L)

H-25


RESERVOIR PRESSURE (Pr)Z 3318 psi

MAXIMUM CASING PRESSURE (Pcmax) WHEN GAS GETS TO SURFACEAA. Drill String Capacity from Prerecorded Data AA 105 bbl

BB. Annulus Capacity Factor DP x Casing Right Below Wellhead BB 0.0505 bbl/ft

CC. Temperature and Compression Effects. (TZ from Figure 11P.5 or Formula below)CC 0.95

DD 0.553 psi/ft

EE 36 psi

FF 720 psi

GG. Maximum Casing Pressure,PCmax=(Part1) + (Part2) = EE + FF = GG 756 psi

Does Pcmax Exceed the Wellhead or Casing Pressure Limitation?

YES NO X

VOLUME GAIN WHILE CIRCULATING OUT GAS BUBBLEHH. Volume of Gas at Surface (From Fig 11P.4 or From Formula Below)

HH 62 bbl

II. Volume Gain While Circulating Out Gas Kick II = HH - E II 47 bbl

JJ. Volume Gain due to Barite Addition JJ 28 bbl

Total Volume Gain While Circulating Out Gas = II + JJ 75 bbl

STROKES TO MAXIMUM CASING PRESSURE AND VOLUMEMaximum Casing Pressure and Excess Volume Occur When the Pumped Volume Equals

Total Annulus Capacity - Volume of Gas at Surface bbl strokes= Annulus Capacity (from Prerecorded) - HH 355 2432

H-26

WELL CONTROL MANUAL


SECTION I – VOLUMETRIC CONTROL

Current Revision: October 2002 I - 1 3rd Edition Previous Revision: October 1998

Table of Contents

Introduction.........................................................................................................I-2 1.0 Basic Volumetric Control Principles ................................................I-2

1.1 First Basic Principle - Boyle's Law..................................................I-2 1.2 Second Basic Principle - Hydrostatic Pressure ..............................I-3 1.3 Third Basic Principle - Volume and Height......................................I-4

2.0 Description of the Method...................................................................I-4 2.1 Volumetric Control ..........................................................................I-5

Step 1 Calculations .......................................................................I-5 Safety Factor......................................................................I-5 Pressure Increment............................................................I-6 Mud Increment ...................................................................I-6 Step 2 Establish Safety Factor ......................................................I-7 Step 3 Bleed Off the Mud Increment..............................................I-7 Step 4 Wait for Gas Bubble to Migrate ..........................................I-8 Step 5 Bleed Mud from the Annulus..............................................I-8 Step 6 Wait for Gas Bubble to Migrate ..........................................I-8 Step 7 Alternate Bleeding and Migrating.......................................I-8 Step 8 Lubricate Mud into the Well ...............................................I-9

3.0 Lubricant and Bleed .............................................................................I-9 Step 1 Calculate ........................................................................... I-9 Step 2 Lubricate ........................................................................... I-9 Step 3 Wait....................................................................................I-9 Step 4 Bleed................................................................................ I-10 Step 5 Repeat Previous Steps.................................................... I-10

4.0 Volumetric Control Example ............................................................I-10 5.0 Other Things to Consider..................................................................I-13

5.1 Annulus Capacity Factor............................................................... I-13 5.2 Directional Wells........................................................................... I-14 5.3 Similarity to Driller’s Method......................................................... I-14 5.4 Casing Pressure Continues to Rise with Gas at the Surface ........ I-14

WELL CONTROL MANUAL




Introduction In controlling a threatened blowout, special problems may arise that complicate the application of routine methods of well control. One of these problems is not being able to circulate an influx out of the wellbore. This may be due to several things, such as inoperative pumps, plugged bit or drill pipe, drill pipe being well above the influx, as in a kick taken while tripping, or pipe being out of the hole completely. When one of these problems occurs, the well cannot be circulated with kill mud until corrective measures have been taken and the ability to circulate out the influx is regained which could require quite some time. In the case of a plugged bit, it would be necessary to perforate the drill pipe, or, if the drill pipe was off bottom, it would be necessary to strip back to bottom. Monitoring the casing pressure while initiating corrective procedures will dictate the method of controlling the well. If the casing pressure does not increase above the original shut-in pressure, a saltwater kick is indicated. Since there is less density differential between salt water and mud than between gas and mud, the salt water will migrate much slower than gas. Thus, the shut-in casing pressure will remain relatively constant and the only consideration is to leave the well shut in until it can be killed. However, if the casing pressure increases above the original shut-in pressure, a gas kick is indicated. The expansion characteristics of gas coupled with the density differential between gas and mud which cause the gas to migrate up the hole, dictate the use of the volumetric control method. Successful use of the volumetric control method requires a thorough understanding of three basic principles. The first principle is Boyle's Law, which states that the pressure of a gas is directly related to its volume. The second principle is hydrostatic pressure and how it is calculated. The third principle involves fluid volume and height as determined by annular capacities. 1.0 Basic Volumetric Control Principles

1.1 First Basic Principle - Boyle's Law Boyle's Law states that the pressure of a gas is directly related to its volume. If a volume of gas is compressed, the pressure in the gas will increase. Conversely, if a gas is allowed to expand, the pressure in the gas will decrease. Stated mathematically, Boyle's Law is written as:

Equation I.1 - Boyle's Law

P1V1 = P2V2

where: P1 = Pressure in gas at condition 1 V1 = Volume of gas at condition 1 P2 = Pressure in gas at condition 2 V2 = Volume of gas at condition 2

WELL CONTROL MANUAL




This equation is a simplification of the gas law equation, PV = ZnRT, which neglects the effect of the temperature and gas compressibility factors. Relating this phenomenon to well control, if a gas kick migrates up the annulus without expansion, the pressure of the gas bubble will remain constant. If the gas bubble is allowed to expand as it migrates up the annulus, then the pressure in the gas bubble will decrease. Allowing the gas bubble to migrate to the surface without expansion will usually result in disastrous consequences. This is because the pressure in the bubble as it enters at the bottom of the wellbore is equal to the formation pressure. Owing to the nature of all gas bubbles, they tend to rise in fluids which have greater density than their own. If a gas bubble rises without expansion, it will have the same pressure on the surface as it had on bottom, in effect bringing bottomhole formation pressure to the surface! The consequences of this action can be disastrous, often resulting in ruptured casing or an underground blowout. On the other hand, if we allow the volume of the gas to increase as it rises in the annulus, then according to Boyle's Law, the pressure in the gas bubble will decrease. This is precisely the action we take when using volumetric control. We allow the gas bubble to expand by bleeding off mud at the surface through the choke.

1.2 Second Basic Principle - Hydrostatic Pressure

The rising gas bubble can be treated as a surface pressure with respect to the mud below it. Anytime the gas bubble rises by one foot in the annulus, there will be one additional foot of mud below the gas bubble. The additional foot of mud below the gas bubble increases the hydrostatic pressure of the mud below the gas bubble, which increases the bottomhole pressure by a like amount according to the following formula:

Bottomhole Pressure = Hydrostatic Pressure + Surface Pressure

If we bleed mud from the annulus in order to lower the pressure in the gas bubble, then we naturally reduce the volume of mud in the annulus, and therefore, the hydrostatic pressure as well. When we bleed the mud from the annulus, it is very important that we do it in a way that holds the casing pressure (surface pressure) constant. From the above equation, it is clear that if we bleed mud from the annulus (lower the hydrostatic pressure) while holding the same casing pressure (surface pressure constant), then the bottomhole pressure will also decrease.

WELL CONTROL MANUAL




Therefore, in volumetric control, we have two ways to influence the bottomhole pressure:

• Do nothing, let the gas bubble rise, and bottomhole pressure goes up. • Bleed mud from the annulus, lower the hydrostatic pressure, and

bottomhole pressure goes down.

We must be very careful when bleeding mud from the annulus because if we lower the hydrostatic pressure too much, we may go underbalanced and take another influx of gas into the well. We want to bleed-off just enough mud at the surface so that the bottomhole pressure never drops below the reservoir pressure. In order to accomplish this, we need to equate the loss in hydrostatic pressure with the volume of mud bled-off at the surface. The BHP is maintained at a value slightly above formation pressure by bleeding off a volume of mud which causes a reduction in the hydrostatic pressure which is equal to the rise in casing pressure caused by the migrating gas. It is for this reason that we must measure the amount of mud bled-off from the annulus and equate that volume to a reduction in hydrostatic pressure.

1.3 Third Basic Principle - Volume and Height Everyone should be comfortable with annular volume and height relationships. These are used in cement jobs, prerecorded data sheets, and numerous other everyday calculations on the rig. Annulus capacity factors are tabulated in Tables P.1, P.2 and P.3, or can be calculated with the formula on the following page:

Annulus Capacity Factor

OD2 – ID2 ACF = --------------

1029

where: ACF = Annulus Capacity Factor (bbl/ft) OD = Outside Diameter of Annular Space (in) ID = Inside Diameter of Annular Space (in)

We need these factors in order to calculate the reduction in hydrostatic pressure which occurs each time we bleed mud from the annulus. We must know the drop in hydrostatic pressure which will occur as a result of each mud bleeding.

WELL CONTROL MANUAL




2.0 Description of the Method The volumetric control method is not a kill method, but rather, it is a method of controlling the bottomhole pressure until provisions can be made to circulate or bullhead kill mud into the well. The essence of volumetric control is to allow controlled expansion of the gas bubble as it migrates up the hole. We allow the gas bubble to expand by bleeding-off mud at the surface while holding casing pressure constant. Casing pressure is held constant only while the mud is being bled-off; at other times it is allowed to increase naturally. Each barrel of mud that we bleed-off at the surface changes the wellbore environment in four ways.

1. The gas bubble to expand by one barrel 2. The hydrostatic pressure of the mud in the annulus to decrease 3. The bottomhole pressure to decrease 4. The surface casing pressure to stay the same

2.1 Volumetric Control

Volumetric control is accomplished in a series of steps that causes the bottomhole pressure to rise and fall in succession. We let the gas bubble rise and the bottomhole pressure goes up. Then we bleed mud from the annulus and the bottomhole pressure goes down. Then we let the gas bubble rise, and then bleed mud, and so on. In this way, bottomhole pressure is held within a range of values that is high enough to prevent another influx and low enough to prevent an underground blowout.

Step One - Calculations There are three calculations which need to be performed before a volumetric control procedure can be executed.

• Safety Factor • Pressure Increment • Mud Increment

Safety Factor The safety factor is an increase in the bottomhole pressure which we allow to occur naturally as gas migrates up the annulus. By allowing the gas bubble to rise in the annulus, we are allowing the bottomhole pressure to increase. It is important that we allow the bottomhole pressure to increase to a value which is well above the formation pressure to insure that we don't go underbalanced when we bleed mud from the annulus in later steps. An appropriate value for the safety factor is in the range of 200 psi in most cases. Depending on the depth, angle and fluid in the well, it may take several hours for the gas bubble to rise sufficiently to increase the casing pressure by 200 psi.

WELL CONTROL MANUAL




Sometimes, depending on how close the shoe is to exceeding its fracture pressure under initial shut-in conditions, it will be advisable to select a safety factor smaller than 200 psi. Any increase in the bottomhole pressure will be reflected as an equal increase in the shoe pressure as well. If the shoe is close to its fracture pressure, then the safety factor will have to be appropriately reduced. If you calculate that a 200 psi safety factor will break the shoe down, then a 100 psi safety factor would be more suitable.

Pressure Increment The pressure increment is the reduction in hydrostatic pressure which occurs each time we bleed a given volume of mud from the annulus. The Drilling Foreman should select a pressure increment which produces a reduction in hydrostatic pressure equal to one-third of the value of the initial safety factor (rounded to the nearest 10 psi). For example, if a 150 psi safety factor was chosen, then the pressure increment should produce a reduction in hydrostatic pressure of 50 psi (i.e., one-third of 150 psi).

Pressure Increment

Safety Factor Pressure Increment = _________________ 3

Mud Increment The mud increment is the volume of mud which must be bled from the annulus in order to reduce the annular hydrostatic pressure by the amount of the pressure increment determined above. The mud increment can be calculated with the equation given to the right. It is very important that some means be available to measure the small volumes of mud which are bled off from the annulus.

Mud Increment

PI x ACF Mud Increment = ___________ MW x 0.007

where: PI = Pressure Increment (psi) ACF = Annulus Capacity Factor (bbl/ft) MW = Mud Weight (pcf)

WELL CONTROL MANUAL




For example, if a hydrostatic reduction (pressure increment) of 50 psi is desired and the annulus capacity factor is 0.0714 bbl/ft with a mud weight of 85 pcf, then the proper mud increment is 6 bbls.

Step Two - Allow Casing Pressure to Increase Establish Safety Factor After the calculations are completed, the next step in Volumetric Control is to wait for the gas bubble to migrate up the hole and cause an increase in the shut-in casing pressure. (In reality, this would be occurring as you were performing your calculations). You should allow the gas bubble to rise until the casing pressure has increased by an amount equal to the safety factor. No mud has been bled off from the annulus, so the hydrostatic pressure of the mud has not changed since the well was first shut in.

While Gas Bubble Migrates Bottomhole Pressure = Hydrostatic Pressure + Surface Pressure (Goes Up) (Stays the Same) (Goes Up)

At this point, the bottomhole pressure has also increased by the amount of the safety factor and the well should be safely overbalanced.

Step Three - Hold Casing Pressure Constant by Bleeding Off the Mud Increment

After the safety factor overbalance is applied to the well, the first mud increment can be bled from the well. The manner in which the mud is bled-off from the annulus is very important - it must be bled in such a way that the casing pressure remains constant throughout the entire bleeding. This is done to insure that the bottomhole pressure is reduced only by a loss in the mud hydrostatic pressure, and not by an additional loss in surface pressure. During the bleeding process, the hydrostatic pressure is reduced by the pressure increment while the surface pressure is held the same, so the bottomhole pressure is also reduced by the pressure increment.

While Bleeding Mud from the Annulus Bottomhole Pressure = Hydrostatic Pressure + Surface Pressure (Goes Down) (Goes Down) (Stays the Same)

WELL CONTROL MANUAL




Each time we bleed mud from the annulus, the gas bubble expands to fill the volume vacated by the mud. As the gas bubble expands, the pressure in the bubble decreases according to Boyle's Law.

Step Four - Wait for Casing Pressure to Rise as the Gas Bubble Migrates Each bleeding of mud from the annulus reduces the bottomhole pressure by the amount of the pressure increment. This decreases our safety factor overbalance. In order to get the full value of overbalance back on the well, we simply wait for the gas bubble to migrate up the annulus. As the gas bubble migrates, both surface pressure and bottomhole pressure increase just as when the safety factor was applied. We wait for the gas bubble to rise until the surface casing pressure has increased by an amount equal to the pressure increment. At this point, we have also increased bottomhole pressure by the amount of the pressure increment, and the well is back at full overbalance.

Step Five - Hold Casing Pressure Constant by Bleeding Mud from the Annulus

Once we have our full overbalance back on the well, we can safely bleed another mud increment from the annulus. As with the first bleeding, this step is accomplished while holding casing pressure constant. This reduces the bottomhole pressure by the amount of the pressure increment because a like amount of mud hydrostatic pressure has been bled from the well. This has also caused the gas bubble to expand by the volume of the mud increment.

Step Six - Wait for Casing Pressure to Increase as the Gas Bubble Migrates

After the bleed step we again wait for the gas bubble to migrate with the well shut in. The bottomhole pressure will rise back to its full overbalanced condition. We know when this has occurred because the casing pressure will have risen by the amount of the pressure increment.

Step Seven - Alternate Holding Casing Pressure Constant and Letting It Rise

The remainder of the volumetric control procedure is simply a succession of bleeding and migrating, bleeding and migrating, bleeding and migrating, until the gas has finally migrated all the way to the surface. Each time we bleed we lower the bottomhole pressure, and each time we migrate we raise the bottomhole pressure. During each bleed step we allow the gas bubble to expand which lowers the pressure in the bubble. By the time the gas reaches the surface, it has expanded to many times its original volume so its pressure is greatly reduced.

WELL CONTROL MANUAL




Step Eight - Lubricate Mud into the Well

The casing pressure should stop increasing after the gas has reached the surface. The well is stable at this point, but in most cases, you will want to bleed the gas from the well and replace it with mud before attempting further well work. This step involves bleeding gas from the well to reduce the casing pressure by a predetermined increment. Then, a measured volume of mud should be pumped into the well to increase the hydrostatic pressure in the annulus by the amount of surface pressure which was lost when the gas was first bled off. These steps should be repeated until gas can no longer be bled from the well.

3.0 Lubricate and Bleed

Sometimes during major well control situations, there comes a time when gas is at surface and it is not possible to circulate (as could easily be the case during a Volumetric Control procedure). This is the point in time that the surface pressure is the highest due to decreased hydrostatic in the well. When this occurs, the best way to remove the gas is by circulating. However, when circulation is not possible the well has to be lubricated and bled. The theory involved in lubricating and bleeding is the same as that for Volumetric Control but in reverse. Surface pressure is replaced with hydrostatic pressure by pumping mud into the well on top of the gas. The gas and mud are allowed to change places in the hole and some of the surface pressure is bled off. The lubricate and bleed procedure is listed in the following steps.

Step One - Calculate Calculate the hydrostatic pressure that will be exerted by 1 barrel of mud.

Step Two - Lubricate Slowly pump a given volume of mud into the well. The amount chosen will depend on many different well conditions and may change throughout the procedure. The rise in surface pressure can be calculated by applying Boyle’s law of P1V1 = P2V2 and realizing that for every barrel of mud pumped into the well the bubble size decrease by 1 barrel.

Step Three - Wait

Allow the gas to migrate back to the surface. This step could take quite some time and is dependent on a number of factors such as mud weight and viscosity.

WELL CONTROL MANUAL




Step Four - Bleed

Bleed gas from the well until the surface pressure is reduced by an amount equal to the hydrostatic pressure of the mud pumped in. it is every important to bleed only gas. If at any time during procedure mud reaches the surface and starts bleeding. The well should be shut in and the gas allowed to migrate.

Step Five - Repeat Previous Steps

Repeat Steps 2 through 4 until all of the gas has been bled off or a desired surface pressure has been reached.

4.0 Volumetric Control Example Ali Al-Saffar, the Saudi Aramco Drilling Foreman, was glad he had been to well control school last week on his days off; he knew he would need it now. Kicks were common while drilling through "The Trend", but this one had just turned ugly. Just moments after he started pumping using the Engineer's Method, something had plugged him off at the bit. He noticed one of the roustabouts searching for a glove out by the pipe racks. He knew he would have to use Volumetric Control. Ali gathered up the following information and jotted it down in his tally book:

Hole Size: 8-1/2" Kick Size: 24 bbl Drill Pipe: 5" X-Hole Mud Weight; 114 pcf Ann. Capacity 0.0459 bbl/ft SICP: 640 psi TD: 14,400' MD/TVD SIDP: 520 psi Shoe Test: 126 pcf EMW Casing Shoe: 12,220' MD/TVD

Ali knew the first thing to do was to determine the safety factor, pressure increment and mud increment. He knew he had to check the shoe pressures first. Under shut-in conditions he calculated his shoe pressure as:

Shoe Pressure = (TVDshoe x Mud Weight x 0.007) + SICP

= (12,220' x 114 pcf x 0.007) + 640 psi

= 10,391 psi He knew his shoe would break down at a pressure of,

Shoe Fracture Pressure = (TVDshoe x Shoe Test x 0.007)

= (12,220 x 126 pcf x 0.007)

= 10,778 psi

WELL CONTROL MANUAL




Ali saw that the casing pressure could rise another 387 psi (10,778 psi - 10,391 psi = 387 psi) before breaking the shoe down, so he decided on a safety factor of 200 psi. His pressure increment was quickly calculated by dividing the safety factor by 3, as such,

Pressure 200 psi Increment = _______

3 = 67 psi (or 70 psi)

Ali then had to calculate his mud increment (or the volume of mud to generate 70 psi of hydrostatic pressure in his annulus).

PI x ACF Mud Increment = ____________ MW x 0.007 70 x 0.0459 = ____________

114 x 0.007 = 4.0 bbls

Ali then knew that for every 4.0 bbls of mud he bled from the annulus, the hydrostatic pressure would be reduced by 70 psi. With these calculations completed, he was ready to proceed. Ali had a roughneck bring a chair up to the rig floor because he knew that the operation was going to take a long time. He then told the rig welder to weld a bead in a small tank at the 4.0 barrel mark up from the bottom (Ali had determined that he would use the small tank to measure the mud volume which he bled from the well). Ali sat and waited for the casing pressure to rise. In less than an hour, the casing pressure rose 200 psi, from the initial shut-in value of 640 psi to 840 psi. Ali knew that his well was now safely overbalanced, so he was ready for the first bleed step. The choke manifold was lined up to bleed directly into the small tank through the blooey line out near the reserve pit. He had a roughneck with a walkie-talkie out there to measure the volume. Ali cracked the choke and bled-off the first little bit of mud from the annulus; the drop on the casing pressure gauge was imperceptible. He bled a little more mud and the casing pressure gauge dropped five psi. Ali closed the choke and in a little while, the pressure had risen back to 840 psi. He continued to bleed mud in small increments trying to keep the casing pressure as close to 840 psi as possible. Over an hour later, the roughneck finally had 4.0 bbls in the small tank.

WELL CONTROL MANUAL




Ali knew that he had lowered the bottomhole pressure by 70 psi as he had bled the 4.0 bbls from the annulus, so he waited while the gas bubble migrated up the hole and watched as the casing pressure gauge rose an additional 70 psi to 910 psi (840 psi + 70 psi = 910 psi). By this time in the operation, nearly three hours had elapsed. Now that he had his full 200 psi of bottomhole overbalance back on the well, it was time to bleed another 4.0 barrels of mud from the annulus. This time he held the casing pressure as best he could at 910 psi. The roughneck told him when the tank was full. Figure I.1 Volumetric Control Example Pressures

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For the next seven hours, Ali bled mud and then waited, bled more mud and waited some more, and then bled and waited again for a total of fourteen bleed steps. On the fifteenth bleed, with the casing pressure at 1820 psi, Ali started getting gas through the choke. He stopped bleeding and checked to make sure the pipe rams weren't leaking. Everything was in order and he felt fine. Just then the perforating truck pulled up to location to shoot some holes in his drillcollars. He'd be circulating within the hour. A plot of Ali's volumetric control procedure is shown in Figure I.1 You can see that on each bleed step the bottomhole pressure decreased, and on each migrate step the bottomhole pressure increased. Casing pressure rose during each migrate step and was held constant during each bleed step. The gas bubble volume increased by 4.0 bbls during each bleed step and rose from its initial volume of 24 bbls to 84 bbls when it finally reached the surface (24 bbl kick + 60 bbls bled = 84 bbls).

5.0 Other Things to Consider

5.1 Annulus Capacity Factor The annulus capacity factor which is used to determine the mud increment should be taken at the top of the gas bubble. Note that the annulus capacity factor may change as the gas bubble migrates up the hole if a tapered drillstring is in use or drilling liner is installed in the well. If the bubble migrates into a smaller annular space, then less mud needs to be bled from the annulus to produce the same hydrostatic pressure reduction. In these instances, the rate of rise of the gas bubble should be calculated to help in predicting when the new annulus capacity factor should be used. This rate of rise of the gas bubble can be estimated with Equation I.2.

Equation I.2 Rate of Gas Bubble Rise

∆SICP ROR = __________________

MW x 0.007 x ∆T where: ROR = Rate of Rise (ft/min) ∆SICP = Change in Shut-in Casing Pressure MW = Mud Weight (pcf) ∆T = Time from end of last bleed to start of next bleed (min)

If an accurate time log is kept of the volumetric control procedure, then the rate of rise can be calculated over the interval of each migration step. Remember however, that the gas bubble will continue to rise even while mud is being bled from the well.

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5.2 Directional Wells Due to the hypothetical nature of this well control method, it may be used with limited success in deviated holes.

5.3 Similarity to Driller's Method

In essence, the volumetric control procedure is identical to the first circulation of the Driller's Method, except that no pumps are used and the final casing pressure is somewhat higher. With volumetric control, the influx is allowed to migrate out of the hole rather than being circulated out of the hole. Once the influx is removed and mud is lubricated into the annulus, the well should be in the same state that it would have been if the first circulation of Driller's Method had been completed. However, except that the casing pressure may be higher due to the additional safety factor applied to the well.

5.4 Casing Pressure Continues to Rise with Gas at the Surface

This may occur if the gas bubble is severely strung-out over the length of the hole. Since gas contributes very little to the hydrostatic pressure of the fluids in the well, it can usually be bled from the well without causing much of a pressure reduction at the bottom of the hole. Therefore, if gas reaches the surface and the casing pressure continues to rise, the Drilling Foreman should bleed small amounts of gas from the well while keeping casing pressure constant until the casing pressure no longer continues to rise.

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Drilling & Workover October 2002 __ SECTION J - EQUIPMENT REQUIREMENTS

Current Revision: October 2002 J - 1 3rd Edition Previous Revision: June 2001

Table of Contents

1.0 Drilling BOP Stacks .................................................................. J - 4

1.1 Class ‘A’ 10,000 psi BOP Stack ........................................................ J - 4 1.1.1 Class ‘A’ 10,000 psi BOP Stack Arrangement (Normal)......... J - 4 1.1.2 Class ‘A’ 10,000 psi BOP Stack Arrangement (Tapered)....... J - 7

1.2 Class ‘A’ 5,000 psi BOP Stack .......................................................... J - 8 1.2.1 Class ‘A’ 5,000 psi BOP Stack Arrangement (Normal)........... J - 8 1.2.2 Class ‘A’ 5,000 psi BOP Stack Arrangement (Tapered)....... J - 12

1.3 Class ‘A’ 3,000 psi BOP Stack ........................................................ J - 13 1.3.1 Class ‘A’ 3,000 psi BOP Stack Arrangement (Large Hole)... J - 13 1.3.2 Class ‘A’ 3,000 psi BOP Stack Arrangement (Smaller Hole) J - 15

1.4 Class ‘B’ 3,000 PSI BOP Stack ....................................................... J - 17 1.5 Class ‘C’ 3,000 psi BOP Stack ........................................................ J - 18 1.6 Class ‘D’ Diverter BOP Stack.......................................................... J - 19 1.7 General Requirements for Drilling BOP Equipment..................... J - 20

1.7.1 Annular Units ........................................................................ J - 21 1.7.2 Fixed Rams Preventers ........................................................ J - 21 1.7.3 Variable Bore Rams.............................................................. J - 22 1.7.4 Shear Blind Rams................................................................. J - 22 1.7.5 Blind Flanges on Side Outlets .............................................. J - 24 1.7.6 Minimum Bore Requirements for Kill and Choke Lines………J - 24

2.0 Workover BOP Stacks .............................................................J - 24 2.1 Class ‘I’ 2,000 PSI BOP Stack ........................................................ J - 24 2.2 Class ‘II’ 3,000 psi BOP Stack......................................................... J - 25 2.3 Class ‘III’ 5,000 psi BOP Stack........................................................ J - 26 2.4 Class ‘IV’ 10,000 psi BOP Stack ..................................................... J - 26 2.5 General Requirements for Workover BOP Equipment ................ J - 27

2.5.1 Annular Units ........................................................................ J - 29 2.5.2 Fixed Rams Preventers ........................................................ J - 29 2.5.3 Variable Bore Rams.............................................................. J - 29 2.5.4 Shear Blind Rams................................................................. J - 29 2.5.5 Blind Flanges on BOP Side Outlets………………………………J - 30 2.5.6 Minimum Bore Requirements for Kill and Choke Lines……..J - 30

3.0 Special Operations BOP Stacks .............................................J - 30 3.1 Coil Tubing Operations ................................................................... J - 30

3.1.1 Low Pressure BOP Equipment Requirements ..................... J - 31 3.1.2 High Pressure BOP Equipment Requirements..................…J - 32

3.2 Snubbing Operations ...................................................................... J - 33 3.2.1 Low Pressure BOP Equipment Requirements ..................... J - 33

3.2.2 High Pressure BOP Equipment Requirements..................... J - 34

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3.3 Electric Line Operations ................................................................. J - 35

3.3.1 Open Hole BOP Equipment Requirements .......................... J - 35 3.3.2 Cased Hole BOP Equipment Requirements......................... J - 35

4.0. Choke Manifolds .......................................................................J - 37 4.0.1 10,000 psi Working Pressure ............................................... J - 37 4.0.2 5,000 psi Working Pressure (Onshore) ................................ J - 38 5,000 psi Working Pressure (Offshore) ................................ J - 39 4.0.3 3,000 psi Working Pressure ............................................... .J - 41

4.1 Location ............................................................................................ J - 42 4.2 Choke Manifold Pressure Ratings ................................................ J - 42 4.3 Piping Specifications ...................................................................... J - 42 4.4 Choke Manifold Discharge ............................................................. J - 42

4.4.1 Flare Lines ............................................................................ J - 42 4.4.2 Gas Buster Lines .................................................................. J - 43

4.5 Choke Requirements....................................................................... J - 44 4.6 Valve Requirements ........................................................................ J - 44 4.7 Gauges.............................................................................................. J - 44 4.8 Line Maintenance............................................................................. J - 44 4.9 Normal Valve Position..................................................................... J - 44

5.0 Accumulator Closing Units .....................................................J - 44 5.1 Fluid Requirements ......................................................................... J - 44 5.2 Design Requirements...................................................................... J - 45 5.3 Bottle Pre-Charge Requirements ................................................... J - 45 5.4 Operator Control Requirements..................................................... J - 45 5.5 Accumulator Location ..................................................................... J - 45 5.6 Pump System ................................................................................... J - 45 5.7 Pressure Regulator Settings .......................................................... J - 46

6.0 Sizing BOP Closing Equipment ..............................................J - 46 6.1 General Requirements .................................................................... J - 46 6.2 Size Calculations ............................................................................. J - 47 6.3 Alternate Size Calculations............................................................. J - 50

7.0 Preventer Units.........................................................................J - 53 7.1 Annular Preventers.......................................................................... J - 53

7.1.1 Hydril ‘MSP’ .......................................................................... J - 54 7.1.2 Hydril ‘GK’ ............................................................................. J - 55 7.1.3 Hydril ‘GL’ ............................................................................. J - 56 7.1.4 Shaffer ‘Spherical’................................................................. J - 57 7.1.5 Cameron Model ‘D’ ............................................................... J - 58

7.2 Sealing Elements ............................................................................. J - 59 7.3 Stripping with Annular .................................................................... J - 60 7.4 Ram Preventers ............................................................................... J - 60

7.4.1 Hydril Type ‘V’....................................................................... J - 60 7.4.2 Shaffer Type ‘LWS’............................................................... J - 61 7.4.3 Shaffer Type ‘SL’ .................................................................. J - 62 7.4.4 Cameron Type ‘U’................................................................. J - 62

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7.5 Ram Construction............................................................................ J - 63

7.5.1 Hydril Rams .......................................................................... J - 63 7.5.2 Cameron Rams .................................................................... J - 64 7.5.3 Shaffer Rams........................................................................ J - 65

7.6 Variable Bore Rams ......................................................................... J - 65 7.7 Shear Blind Rams ............................................................................ J - 66 7.8 Secondary Seals .............................................................................. J - 68

8.0 Accessory Blowout Prevention Equipment ...........................J - 68 8.1 Pit Volume Totalizer ........................................................................ J - 68 8.2 Mud Flow Indicators ........................................................................ J - 69 8.3 Mud/Gas Separators........................................................................ J - 69

8.3.1 Degassers............................................................................. J - 69 8.3.2 Gas Busters .......................................................................... J - 69

8.4 Full-Opening Safety Valve .............................................................. J - 72 8.5 Inside BOP........................................................................................ J - 73 8.6 Drilling Chokes ................................................................................ J - 74 8.7 Trip Tank........................................................................................... J - 74 8.8 Strokes Counters ............................................................................. J - 76 8.9 Gas Detectors .................................................................................. J - 76 8.10 Mud Logging Unit ............................................................................ J - 76 8.11 Mud Weight Recorders ................................................................... J - 76 8.12 Drilling Rate Recorders ................................................................... J - 77 8.13 Bowl Protectors ............................................................................... J - 77 8.14 Drillpipe Float Valves ...................................................................... J - 77 8.15 Valve Removal Plugs....................................................................... J - 77 8.16 Back Pressure Valves ..................................................................... J - 79

8.16.1 One-Way Check Valve ......................................................... J - 79 8.16.2 Two-Way Check Valve ......................................................... J - 80

8.17 Coflex Hose ...................................................................................... J - 81 8.18 Weco Connections .......................................................................... J - 81 8.19 Chiksans .......................................................................................... J - 81

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Any BOP equipment arrangement or pressure rating variation from the standards set forth herein must be approved by the General Manager, Drilling and Workover. The enforcement of these equipment standards shall be the responsibility of the Drilling Superintendent. The Drilling Foreman shall ensure that the proper equipment is available and correctly installed. All BOP equipment shall comply with API Specifications, if not specified in these standards. The BOP equipment must be arranged to allow:

Ø A means of closing the top of the open hole, as well as around drill pipe or collars, and stripping the drill string to bottom.

Ø A means of pumping into a hole and circulating out a well kick. Ø A controlled release of the influx. Ø A redundancy in equipment in the event that any one function fails.

Changes in this 3rd Edition of the Saudi Aramco Well Control Manual are indicated by a bold vertical line in the right margin, opposite the revision. 1.0 Drilling BOP Stacks

The drilling program shall specify the Class BOP stack (not individual components) to be used.

1.1 Class ‘A’ 10,000 psi BOP Stack

A Class ‘A’ 10,000 psi BOP stack shall be installed on all offshore and onshore wells where surface pressure may become more than 5,000 psi but not more than 10,000 psi. All equipment shall meet NACE Standard MR-01-75 (Latest Revision) for sour service with 10,000 psi working pressure. All elements for Class ‘A’ 10,000 psi stacks shall be 10,000 psi rated working pressure and all flanges in the stack shall be 13-5/8" or 11” 10M. One exception to this is that the annular preventer shall be 5,000 psi working pressure. It is also unnecessary to have a 10,000 psi rotating head. Each ram preventer shall have two 4-1/16" 10M flanged outlets. For a double ram preventer there would be a total of four flanged outlets. All preventers shall be installed so that rams can be changed without moving the stack.

1.1.1 Class ‘A’ 10,000 psi BOP Stack Arrangement (Normal)

When using a single size of drill pipe (one size of drill pipe from bottom to top) the stack arrangement shall be as described below and as shown in Figure J.1:

a) A wellhead spool (casing head) with a 13-5/8" or 11” 10M flange with two (2) 3-1/16" 10M flanged side outlets for emergency kill operations shall be installed. One outlet shall have two (2) 3-1/16" 10M flanged gate valves with a 3-1/16” blind flange installed. The other outlet shall have a manually operated flanged 3-1/16" gate valve next to the wellhead and a hydraulic control flanged 3-1/16" 10M gate valve tied to the emergency kill line. The emergency kill line shall be an individual line with flanged steel piping (no chiksan swings or hammer unions) and a minimum 3" 10M rated working pressure. Coflex hose (coflon lined) may be used in combination with steel line. The emergency kill line shall extend from the wellbore to end of the catwalk (approximately 90 feet), with a 3" 1502 Weco welded union (threaded connections are not acceptable) for connection to an emergency pump.

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Note: All BOP equipment with working pressures of 3,000 psi and above shall have flanged, welded, integral, or hubbed connections only.

b) If the wellhead top flange is below ground level, a 13-5/8" or 11” 10M

spacer spool spacer may be required. If the wellhead spool is not 13-5/8" or 11” 10M, a double studded adapter flange shall be required.

Shear Blind Rams

Figure J.1 Class ‘A’ 10,000 psi BOP Stack (using a single size drillpipe)

3-1/16” 10M Emergency Kill Line

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c) A 13-5/8" or 11” 10M flanged double gate ram preventer shall be

installed on the wellhead spool above ground level with master drill pipe rams (bottom) and blind rams (top).

d) A 13-5/8" or 11” 10M flanged drilling cross shall be installed on the double ram preventer. The drilling cross shall have two (2) 4-1/16" 10M flanged side outlets.

There shall be a double studded adapter flange 4-1/16" 10M to 2-1/16" 10M installed on the kill line side. From the drilling cross out, there shall be:

• a 2-1/16" 10M flanged manually operated gate valve • a 2-1/16" 10M flanged hydraulic control gate valve • a 2-1/16" 10M flanged spacer spool • a 2-1/16" 10M flanged tee

On each side of the tee there shall be a 2-1/16" 10M flanged gate valve and a 2-1/16" 10M flanged check valve. On the remote side, the kill line shall be 10M and run at least 90 feet from the wellbore to the end of the walk, with a flange to Weco 2" welded union. On the primary side, the kill line shall be 10M and connected directly to the mud pumps or to the stand pipe manifold, with a 10M manual isolation valve between the kill line and 5M stand pipe.

On the choke line, from the drilling cross out, there shall be:

• a 4-1/16" 10M flanged manually operated gate valve • a 4-1/16" 10M flanged hydraulic control gate valve • a 4-1/16" 10M flanged line to a 4-1/16" 10M flanged

manually operated gate valve at the choke manifold

All steel piping shall be made with 10M flanges, targeted tees, block-tee elbows, and factory-made 10M working pressure line. All tees must be targeted with renewable 10M blind flanges (welded tees are not acceptable).

Chiksans and Weco connections (other than the remote connections at end of the catwalk) are not acceptable for kill line, emergency kill line, or choke line. Coflex hose (coflon lined) may be used in combination with steel line for the kill or emergency kill line.

e) A 13-5/8" or 11” 10M flanged double gate ram preventer shall be installed on the 10M drilling cross. There shall be shear blind rams (bottom) and drill pipe rams (top) of the double ram preventer.

f) A 13-5/8" or 11” 5/10M flanged bottom and studded top annular preventer will be installed on the top double ram preventer. A screw-on top annular is acceptable.

g) A 13-5/8" or 11” 5/10M flanged rotating head, with a flanged bottom connection to match the top connection of the annular preventer and a 9" 3M flanged side outlet, shall be installed on top of the annular preventer. A spacer spool may be required if annular studded top is not compatible with rotating head flange.

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1.1.2 Class ‘A’ 10,000 psi BOP Stack Arrangement (Tapered)

When using a tapered drill string (two sizes of drill pipe) from the bottom to top shall be exactly the same as the arrangement for a single size drill pipe string, except the blind rams in the lower double ram preventer shall be replaced with rams to fit small drill pipe, as shown in Figure J.2.

Note: All BOP equipment with working pressures of 3,000 psi and above shall have

flanged, welded, integral, or hubbed connections only.

Figure J.2 Class ‘A’ 10,000 psi BOP Stack (using a tapered drill string)

Shear Blind Rams


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1.2 Class ‘A’ 5,000 psi Stack

A Class ‘A’ 5,000 psi stack shall be installed on all offshore and onshore wells where surface pressure may become more than 1,000 psi, but not more 5,000 psi. All equipment shall meet NACE Standard MR-01-75 (Latest Revision) for sour service with a 5,000 psi working pressure. All elements of Class ‘A’ 5,000 psi stacks shall be 5,000 psi rated working pressure and all flanges on the stack shall be either 13-5/8" or 11" 5M. Each ram preventer shall have two (2) 3-1/8" (or larger) 5M side outlets. A double ram preventer will have four side outlets. All preventers shall be installed so that rams can be changed without moving the stack.

All Class ‘A’ 5,000 psi stacks used offshore shall have shear blind rams installed in the ram cavity immediately above the drilling cross. Shear blind rams on onshore stacks are required only on wells with high H2S, in gas cap areas, and wells in populated areas. Details regarding shear blind ram applications are provided in Section 1.7.4. 1.2.1 Class ‘A’ 5,000 psi Stack Arrangement (Normal)

When using a single size drill pipe string (one size of drill pipe) from the bottom to top, the stack arrangement shall be as described below and as shown in Figure J.3:

a) A wellhead spool (casing head) with a 13-5/8" or 11" 3M flange with

two (2) 2-1/16" 3M side outlets for emergency kill operations shall be installed. One outlet shall have a 2-1/16" 3M gate valve with a 2-1/16" 3M blind flange. The other outlet shall have a manually operated 2-1/16" 3M flanged gate valve next to the wellhead and a hydraulic control 2-1/16" 3M flanged gate valve tied into the emergency kill line. The emergency kill line shall be an individual line with flanged steel piping (no chiksan swings or hammer unions) and a minimum 2” 5M rated working pressure. Coflex hose (coflon lined) may be used in combination with steel line.

For onshore operations, the emergency kill line shall extend from the wellbore to end of the catwalk (approximately 90 feet), with a 2" 1502 Weco welded union (threaded connections are not acceptable) for connection to an emergency pump.

Note: If shear blind rams are utilized, then the emergency kill line shall be 3”

and 5 M rated working pressure. The manual gate valve shall remain as 2” with double studded adapter to 3”.

Note: If the wellhead spool has a 5M top flange, then the side outlet valves

shall be 5M.

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2-1/16” 5M Emergency Kill Line (3-1/8” 5M if Shear Blind Rams are utilized)

or Shear Blind Rams (see Sec. 1.7.4)

Optional

Figure J.3 Class ‘A’ 5,000 psi BOP Stack – (using a single size drill pipe)

Note: Kill and Emergency Kill Lines configured for onshore operations

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Note: All BOP equipment with working pressures of 3,000 psi and

above shall have flanged, welded, integral, or hubbed connections only.

b) If the wellhead top flange is below ground level, a 13-5/8" or 11" 5M

spacer spool may be required. c) A 13-5/8" or 11" 5M flanged single ram preventer shall be installed on

the wellhead spool above ground level with master drill pipe rams.

Variable bore rams are optional (provided the minimum acceptable ratings for H2S and temperature are met) for tapered drill string applications on Class ‘A’ 5M stacks. However, the master pipe ram must be a fixed ram. Note: Currently, Cameron’s Extended Range High Temperature

VBR-II Packer is the only variable bore ram is approved for 5M applications. Additional information regarding the use of variable bore rams is provided in Section 1.7.3.

d) A 13-5/8" or 11" 5M flanged drilling cross shall be installed on the

single ram preventer. The drilling cross shall have two (2) 3-1/8" 5M side outlets.

e) There shall be a 3-1/8" 5M to 2-1/16" 5M double studded adapter

flange installed on the kill line side.

For Land Operation: From the drilling cross out, there shall be:

• a 2-1/16" 5M flanged manually operated gate valve • a 2-1/16" 5M flanged hydraulic control gate valve • a 2-1/16" 5M flanged spacer spool • a 2-1/16" 5M flanged tee

On each side of the tee there shall be a 2-1/16" 5M flanged gate valve and a 2-1/16" 5M flanged check valve. On the remote side, the kill line shall be 5M and run at least 90 feet from the wellbore to the end of the catwalk, with a flange to Weco 2" welded union. On the primary side, the kill line shall be 5M and connected directly to the mud pumps or to the stand pipe manifold.

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For Offshore Operation: From the drilling cross out, there shall be:

• a 2-1/16" 5M flanged manually operated gate valve • a 2-1/16" 5M flanged hydraulic control gate valve • a 2-1/16" 5M check valve • a 2-1/16" 5M flanged line or Coflex hose (coflon lined) to the

pump/choke manifold

The emergency kill line shall have the capability of being connected to the cement manifold through the choke manifold as shown in Figure 18A or through a dedicated line from the rig floor cement manifold. A 3” ID, 5M Coflex (coflon lined) hose shall be run between the fixed piping and applicable casing spool. Note: Due to the length required in offshore operations, it is

recommended that a short connection (between the cement manifold and whatever facility is used) be of a removable type to reduce the chance of plugging the line with cement during cementing operations. This connection shall be in place and tested during drilling operations.

On the choke line, from the drilling cross out, there shall be:

• a 3-1/8" 5M flanged manually operated gate valve • a 3-1/8" 5M flanged hydraulic control gate valve • a 3-1/8" 5M flanged line or Coflex hose (coflon lined) to a 3-1/8"

5M flanged manually operated gate valve at the choke manifold

All steel piping shall be made with 5M flanges, targeted tees, block-tee elbows, and factory-made 5M working pressure line. All tees must be targeted with renewable 5M blind flanges (welded tees are not acceptable). Chiksans and Weco connections (other than the remote connection at the catwalk, land operation) are not acceptable. Coflex hose (coflon lined) may be used in combination with steel line for kill, emergency kill line, or choke line.

f) Either two (2) 13-5/8" or 11" 5M flanged single ram preventers or a double ram preventer shall be installed, blind rams or shear blind rams, see required applications in Section 1.7.4, (bottom) and drill pipe rams (top).

g) A 13-5/8" or 11" 5M flanged bottom and studded top annular preventer

will be installed on the top ram preventer. A screw-on top annular is acceptable.

h) A 13-5/8" 5M or 11" 5M rotating head is optional.

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1.2.2 Class ‘A’ 5,000 psi Stack Arrangement (Tapered)

When using a tapered drill string (two sizes of drill pipe) from the bottom to top shall be exactly the same as the arrangement for the single size drill pipe string. The only exception is the top drill pipe rams shall be replaced with small drill pipe rams, as shown in Figure J.4.

2-1/16” 5M Emergency Kill Line (3-1/8” 5M if Shear Blind Rams are utilized)


Figure J.4 Class ‘A’ 5,000 psi BOP Stack – (using a tapered drill string)

Note: Kill and Emergency Kill Lines configured for onshore operations

Optional

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Note: All BOP equipment with working pressures of 3,000 psi and above shall have flanged,

welded, integral, or hubbed connections only.

1.3 Class ‘A’ 3,000 psi BOP stack

A Class ‘A’ 3,000 psi BOP stack shall be installed on all wells where large diameter hole is being drilled, as through 18-5/8" casing, and where hydrocarbon reservoirs with up to 3000 psi surface pressure may be drilled. 1.3.1 Large Diameter Hole (as with Deep Gas Wells)

All equipment shall meet NACE Standard MR-01-75 (Latest Revision) for sour service with a 3,000 psi working pressure. All elements of Class ‘A’ 3,000 psi stacks shall be 3,000 psi rated working pressure and all flanges on the stack shall be either 26-3/4" or 20-3/4” 3M. Each ram preventer shall have two (2) 4-1/16" 3M side outlets. A double ram preventer will have four side outlets. All preventers shall be installed so that rams can be changed without moving the stack.

The arrangement from the bottom to the top shall be as follows:

a) A wellhead spool (18-5/8" landing base or casing spool) with 20-3/4" 3,000 psi flange and two (2) 3-1/16" 3M side outlets for emergency kill operations shall be installed. One outlet shall have a 3-1/16" 3M gate valve with a 3-1/16" 3M blind flange. The other outlet shall have a manually operated 3-1/16" 3M flanged gate valve next to the wellhead and a hydraulic control 3-1/16" 3M flanged gate valve tied into the emergency kill line. The emergency kill line shall be an individual line with flanged steel piping (no chiksan swings or hammer unions) and a minimum 3” 10M rated working pressure. Coflex hose (coflon lined) may be used in combination with steel line. The emergency kill line shall extend from the wellbore to end of the catwalk (approximately 90 feet), with a 3" 1502 Weco welded union (threaded connections are not acceptable) for connection to an emergency pump.

b) If the wellhead top flange is below ground level, a 20-3/4” 3M spacer spool may be required.

c) A 26-3/4” or 20-3/4” 3M flanged single ram preventer shall be installed on the wellhead spool above ground level with master drill pipe rams. If a 26-3/4” BOP stack is used, a 20-3/4” 3M to 26-3/4” DSA flange will be required.

d) A 26-3/4” or 20-3/4” 3M flanged drilling cross shall be installed on the single ram preventer. A drilling cross shall have two (2) 4-1/16" 10M side outlets. The same valve arrangement (with same equipment requirements) on the kill and choke lines as for the Class ‘A’ 10,000 psi BOP stack shall be used, as shown in Figure J.5.

e) Either a 26-3/4" or 20-3/4" 3M flanged double ram preventer or two (2) single ram preventers shall be installed, with blind rams (bottom) and drill pipe rams (top).

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f) A 26-3/4” or 20-3/4" 3M to 30” 1M or 21-1/4" 2M double studded

adapter flange (DSA) will be required on top of this preventer. The DSA can be eliminated if a 26-3/4” or 20-3/4" 3M psi flange is manufactured on the annular preventer.

g) A 30” 1M or 21-1/4" 2M flanged bottom annular preventer shall

complete this stack. A screw-on top annular is acceptable.

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1.3.2 Smaller Diameter Hole (as with Critical Oil Wells)

At the discretion of the Drilling Manager, some oil wells may require a Class ‘A’ 3,000 psi stacks rather than a Class ‘B’ 3,000 psi stack. All equipment shall meet NACE Standard MR-01-75 (Latest Revision) for sour service with a 3,000 psi working pressure. All elements of Class ‘A’ 3,000 psi stacks shall be 3,000 psi rated working pressure and all flanges on the stack shall be 13-5/8" 3M. Each ram preventer shall have two (2) 3-1/16" 3M side outlets. A double ram preventer will have four side outlets.

Shear blind rams (SBR) are required in the Class ‘A’ 3,000 psi stack on wells in the gas cap or populated areas.

The arrangement from the bottom to the top shall be as follows:

a) A wellhead spool (13-3/8" landing base) with 13-5/8" 3,000 psi flange and two (2) 2-1/16" 3M side outlets for emergency kill operations shall be installed. One outlet shall have a 2-1/16" 3M gate valve with a 2-1/16" 3M blind flange. The other outlet shall have a manually operated 2-1/16" 3M flanged gate valve next to the wellhead and a hydraulic control 2-1/16" 3M flanged gate valve tied into the emergency kill line. The emergency kill line shall be an individual line with flanged steel piping (no chiksan swings or hammer unions) and a minimum 3” 3M rated working pressure (if SBR used) otherwise 2” 3M. Coflex hose (coflon lined) may be used in combination with steel line. The emergency kill line shall extend from the wellbore to end of the catwalk (approximately 90 feet), with a 1502 WECO welded union (threaded connections are not acceptable) for connection to an emergency pump.

Note: If shear blind rams are utilized, then the emergency kill line shall be 3” and 3M rated working pressure. The manual gate valve shall remain as 2” with double studded adapter to 3”.

b) If the wellhead top flange is below ground level, a 13-5/8” 3M spacer spool may be required.

c) A 13-5/8” 3M flanged single ram preventer shall be installed on the wellhead spool above ground level with master drill pipe rams.

d) A 13-5/8” 3M flanged drilling cross shall be installed on the single ram preventer. A drilling cross shall have two (2) 3-1/16" 3M side outlets. The same arrangement on the kill and choke lines as for the Class ‘A’ 5,000 psi BOP stack (land operation) shall be used, as shown in Figure J.6.

All steel piping shall be made with 3M flanges, targeted tees, block-tee elbows, and factory-made 3M working pressure line. All tees must be targeted with renewable 3M blind flanges (welded tees are not acceptable).

Chiksans and Weco connections (other than the remote connections at the end of the catwalk) are not acceptable. Coflex hose (coflon lined) may be used in combination with steel line.

WELL CONTROL MANUAL




e) Either two (2) 13-5/8" 3M flanged single ram preventers or a double

ram preventer shall be installed, with blind rams or shear blind rams, see required applications in Section 1.7.4, (bottom) and drill pipe rams (top).

f) A 13-5/8" 3M flanged bottom with studded top annular preventer shall

complete this stack.

2-1/16” 3M Emergency Kill Line 3-1/16” 3M if Shear Blind Rams are utilized

Figure J.6 Class ‘A’ 3,000 psi BOP – (using single size drill pipe)

Smaller Diameter Hole (Critical Oil Wells)


3-1/16” ID 3M

2-1/16” 3M Kill Line

3-1/16” x 2-1/16”

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1.4 Class ‘B’ 3,000 PSI BOP Stack

A Class ‘B’ 3,000 psi BOP stack (Figure J.7) shall be installed, as a minimum, on all development oil producers, water injectors, observation and water disposal wells. All BOP equipment shall be 13-5/8” 3M, with kill and choke line requirements as previously described in the Class ‘A’ 3M. The kill line shall be 3M and connected directly to the mud pumps or to the stand pipe manifold.

All tees must be targeted with renewable 3M blind flanges (welded tees are not acceptable). Chiksans and Weco connections (other than the remote connection on the emergency kill line at the end of the catwalk) are not acceptable. Coflex hose (coflon lined) may be used in combination with steel line for kill, emergency kill, or choke line.

Note: All BOP equipment with working pressures of 3,000 psi and above shall have

flanged, welded, integral, or hubbed connections only.


Figure J.7 Class ‘B’ 3,000 psi BOP Stack

WELL CONTROL MANUAL



This stack will also be used for deep gas wells on 24” casing (K1 or K2 well design) or 18-5/8” casing (MK1 well design). All BOP equipment shall be 26-3/4” 3M, as previously described in Class ‘A’ 3,000 psi.

1.5 Class ‘C’ 3,000 psi BOP Stack

A Class ‘C’ 3,000 psi BOP stack (Figure J.8) shall be installed on all power water injector wells during the drilling and acidizing operations in the Arab-D hole section. The minimum equipment required will be an annular type preventer and a hydraulically operated dual ram preventer (or two single ram preventers) with blind rams located on top and pipe rams on bottom. Two (2) 3-1/16” 3M side outlets below the pipe rams are required, one for the kill line hook-up and other for the choke line. The kill line shall be adapted to 2-1/16” 3M and connected directly to the mud pumps or to the stand pipe manifold. A 10” 3M Ball Valve (with 9” bore) is located below the ram preventers and becomes part of the injection tree upon completion of the well.

All tees must be targeted with renewable 3M blind flanges (welded tees are not acceptable). Chiksans and Weco connections are not acceptable. Coflex hose (coflon lined) may be used in combination with steel line for kill or choke line.

Ball Valve 8” Invasion Line to Pit

Figure J.8 Class ‘C’ 3,000 psi BOP Stack

3-1/16” Min ID

Double Gate or Two Single Preventers

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1.6 Class ‘D’ Diverter Stack A Class ‘D’ Diverter stack (Figure J.9) will be installed on the conductor and/or next casing of all onshore exploration wells and development wells in the shallow gas area or areas where offset data indicates possible shallow gas. In addition, this diverter stack will also be required on the conductor of all offshore exploration wells and wells where offset data indicates possible shallow gas. The diverter line shall consist of Schedule 40 steel piping. This line shall be securely anchored and terminate in the reserve pit or overboard. Saudi Aramco requires two (2) 6” ID full opening valves and 10” lines. All lines must be as straight as possible and all turns targeted to minimize erosion. The emergency pump in connection shall be a 3-1/8” 2M flanged connection, located 90 degrees offset from the diverter lines (as noted in Figure J.9 below). The kill line shall be connected directly to the mud pumps or to the stand pipe manifold.

3-1/8” 2M Side Outlet (offset 900 from diverter lines)

Figure J.9 Class ‘D’ Diverter Stack

10.75” OD x 10.50” ID 10.75” OD x 10.50” ID

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1.7 General Requirements for Drilling BOP Equipment

• All newly manufactured BOP equipment shall be API monogrammed.

• A full OEM certification of the BOP, choke manifold (including chokes), and all related equipment (i.e. closing unit, kill line valves, choke line valves, coflex hoses etc.) shall be required at contract start-up and contract renewal with a maximum period of 3 years between OEM re-certification.

• The BOP should be opened, cleaned, and visually inspected after every nipple down, including servicing the manual lock screws.

• Elastomers exposed to well fluids shall be changed at a maximum of every 12 months, unless visual inspection requires changing earlier. However, it is acceptable to use seal elements for 30” annulars up to 36 months (provided inspections are satisfactory, properly documented, and the expiration date of the elastomer is not exceeded). Seal elements for all other annulars (21-3/4” and smaller) shall be replaced no later than every 12 months, as per policy.

• A Maintenance Log for each piece of BOP equipment shall be maintained. This log shall include, at a minimum, records of all service and inspections performed on the BOP. The log will travel with the Contractor owned equipment and shall be kept in the BOP shop for Saudi Aramco owned equipment.

• The pressure rating of all pressure control equipment (BOP, valves, etc.) must be greater than the maximum anticipated surface pressure.

• Vibrator hoses on the rig pumps shall have molded end connections. Threaded or seal welded connections are not acceptable.

• The through-bore size of the preventer stack, tubing head, and any adapters used in the BOP hook-up shall be large enough for the maximum size bit, scraper, liner hanger, packer, plug, cup tester, or any other large diameter down-hole tools to be run in the well.

• Only a drilling spool is acceptable for kill/choke line installation. However in special cases (as space limitation), preventer side outlets may be used in lieu of a drilling spool. The diameter of all preventer side outlets must be as large as the choke manifold lines.

• Valve Removal (VR) plugs are not required on side outlets of the ram preventers.

• All ram preventers must be equipped with manual or automatic locking devices, which must be locked whenever the rams are used to control the well. Hand crank/wrench or hand wheel systems are acceptable manual locking devices.

• The inside manual valves on the choke and kill lines are considered master valves and normally would never, except for pressure testing, be closed unless the outside valve (HCR) has failed.

• Check valves must be installed on the kill lines but are not required on the emergency kill line.

• The emergency kill line and choke/kill lines should be washed out as required to prevent mud solids settling.

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• Preventer assemblies will be dismantled between wells to inspect for internal

corrosion and erosion and to check flange bolts.

• At least one spare set of ram seals (top seals and packer rams) for all rams, including packer rams for each size of tubing or drill pipe to be used, bonnet or door seals, connecting rod seals, plastic packing for ram shaft secondary seals, ring gaskets to fit flange connections, and spare seal element for the annular preventer must be on the rig site.

• Ram blocks should not be dressed until ready to use.

• Only OEM parts are acceptable when repairing or redressing the BOP, valves, chokes, and closing units.

• All rigs shall maintain a logbook of BOP schematics detailing the components installed in each ram cavity. The logbooks shall contain the part number, description and installation date of ram blocks, top seals, ram or annular packers and bonnet/door seals. To be witnessed/co-signed by Toolpusher and Saudi Aramco Representative (see Form # 1.0 in Section S of this manual).

• All preventers shall meet NACE STANDARD MR-01-75 (Latest Revision).

1.7.1 Annular Units

§ Cameron, Shaffer, and Hydril are acceptable manufacturers for annulars.

§ The minimum acceptable ratings for H2S and temperature are as follows,

3000 psi and less 2.5% H2S and 180°F 5000 psi equipment 2.5% H2S and 180°F 10000 psi equipment 2.5% H2S and 180°F

§ Gray/Regan diverters are acceptable for 500, 1,000, and 2,000 psi service.

§ If a rotary diverter system is utilized on an offshore rig, the diverter lines must have the capability of discharging below the bottom of the hull due to H2S.

1.7.2 Fixed Ram Preventers

§ Cameron, Shaffer and Hydril are acceptable manufacturers for fixed rams.

§ As of April 2000, Hydril has met the minimum acceptable ratings.

§ Only fixed rams are acceptable as master pipe rams on all BOP stacks.


3000 psi stack 5.0% H2S and 250°F 5000 psi stack 10.0% H2S and 250°F 10000 psi stack 20.0% H2S and 300°F

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1.7.3 Variable Bore Ram Preventers

§ Variable bore rams (VBR) are optional for tapered drill string applications on Class ‘A’ stacks. However, the master pipe ram must be a fixed ram.

§ The Cameron Extended Range High Temperature VBR-II Packer (3-1/2” to 5-7/8” pipe sizes) for the Cameron 13-5/8” U Type blowout preventer is acceptable for 3M and 5M applications. The VBR was successfully tested to 250 degrees F with a CAMLAST elastomer rated for 20% H2S. See Section S for details.

§ The minimum acceptable ratings for H2S and temperature for VBRs are,

3000 psi stack 5.0% H2S and 250°F 5000 psi stack 10.0% H2S and 250°F

10000 psi stack 20.0% H2S and 250°F

1.7.4 Shear Blind Rams

§ A new policy of utilizing shear blind rams (SBR) in Saudi Aramco operations was approved in October 2000.

SBR are required on,

q Class ‘A’ 10000 psi stacks (All Deep Gas Expl./Dev. Wells) q Offshore Class ‘A’ 5000 psi stacks (All Offshore Wells) q Onshore Class ‘A’ 5000 psi stacks (Expl./Dev. Wells >10 % H2S) q Gas Cap Wells (Either 3000 or 5000 Class ‘A’ Stacks) q Populated Wells (All Wells in Populated Areas)

§ Cameron’s 13-5/8” and 11” Shearing Blind Rams (for use with U-Type ram preventer) are acceptable for pressure applications to 10M psi. Recent HTHP testing at Cameron has exceeded the requirements of API 16A and Saudi Aramco specifications (300 degrees F and 20% H2S). See Section S for details.

§ Shaffer’s 13-5/8” ‘V’ Shear Ram (for use with Model SL ram preventer) is also acceptable for pressure applications to 10M psi. Recent HTHP testing at Shaffer has exceeded the requirements of API 16A and Saudi Aramco specifications (300 degrees F and 20% H2S). See Section S for details.

§ The minimum acceptable ratings for H2S and temperature for SBR are,



Note: The minimum temperature rating for 10M has been increased from 250 to 300 degrees F because of successful test results by Shaffer and Cameron.

§ Hydril’s shear blind rams are not approved at this time. Their current temperature rating is limited to 180 0F.

§ All rigs utilizing SBR shall have a 3” emergency kill line. This will provide additional emergency kill line capacity, in case the SBR did not make a proper seal after cutting the pipe. If the wellhead spool outlet is 2”, then the inboard manual valve shall be 2” with DSA back to 3”.

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§ The table below indicates the shear capability of SBR for different BOP

pressure applications.

SHEAR BLIND RAM CAPABILITY

10,000 PSI SERVICE

OEM

SIDE PACKER

RATINGS

BOP

SERVICE

BOPE

SIZE - WP

CLASS

MFG. DRILL PIPE SHEAR

CAPABILITY

REQUIRED

SHEAR

BLIND

RAM TYPE

OPERATOR

REQUIRED

SIZE

TEMP, 0F H2S, %

Ø DEEP GAS

EXPL/ DEV.

13-5/8" 10M CLASS 'A'

CAMERON (1) ALL SIZES TO

5-1/2" 24.7# G-105

'SBR' YES/ LBT (2) 300 20

SHAFFER (1) ALL SIZES TO

5-1/2" 24.7# G-105

'V' 14"/10" (3) 300 20

11" 10M

CLASS 'A'


5" 19.5# G-105

'SBR' YES/ LBT (2) 300 20


5" 25.6# G-105

'T-72' 14"/10" (3) 250 20

3,000 - 5,000 PSI SERVICE

OEM

SIDE PACKER

RATINGS

BOP

SERVICE

BOPE

SIZE - WP

CLASS

MFG. DRILL PIPE SHEAR

CAPABILITY

REQUIRED

SHEAR

BLIND

RAM TYPE

OPERATOR

REQUIRED

SIZE

TEMP, 0F H2S, %

13-5/8" 3-5M

CLASS 'A'


5-1/2" 24.7# G-105

'SBR' YES/ LBT (2) 250 20

DUAL TUBING

STRINGS

(SHEAR RAMS UNDER REVIEW)

Ø OFFSHORE

Ø ONSHORE

Ø EXPL/DEV. w/ H2S > 10%

Ø GAS CAP WELL

Ø POPULATED

AREAS


5-1/2" 24.7# G-105

'V'

14"/10" (3) 250 20

11" 3-5M

CLASS 'A'


5" 19.5# G-105

'SBR' YES/ LBT (2) 250 20


5" 25.6# G-105

'T-72' 14"/10" (3) 250 20

NOTE: (1) BOTH CAMERON AND SHAFFER ARE APPROVED MANUFACTURERS. (2) CAMERON - LBT REFERS TO LARGE BORE SHEAR BONNETS WITH TANDEM BOOSTERS.

(3) SHAFFER - 14" OPERATOR WITH 10" BOOSTER IS REQUIRED.

WELL CONTROL MANUAL



1.7.5 Blind Flanges on BOP Side Outlets

§ Flanges installed on the side outlets of ram preventers that do not have VR (Valve Removal) plugs installed shall be blind with no penetrations.

§ Flanges installed on the side outlets of ram preventers that have VR (Valve Removal) plugs installed shall have a ½” NPT tap with a ½” NPT plug installed.

1.7.6 Minimum Bore Requirements for Kill, Emergency Kill, and Choke Lines

§ The minimum bore size for kill, emergency kill, and choke lines shall be the same bore as the weld neck flange used in the pressure application (see specification details in Section R).

§ All lines shall be welded and pressure tested as per API Specification 6A.

2.0 Workover BOP Stacks Maintaining control of a well during the completion and workover phases may be more complicated than well control in drilling operations. Additional complications may exist as, a) various types of workover fluids ranging from low-density diesel to high-density brine fluids may be used; b) interrelated activities may occur simultaneously, such as workovers on a platform with producing wells. Saudi Aramco has four (4) classes of BOP arrangements for workover operations. The workover program shall specify the Class BOP stack (not individual components) to be used.

2.1 Class ‘I’ 2000 psi Workover Stack

a) This class is used on water supply wells and shallow low-pressure aquifer

observation wells, where the operation to be performed on the well and/or space below the rig substructure precludes use of ram-type preventers.

b) The minimum equipment required will be a Hydril, Cameron, or Shaffer

annular type preventer. A 2” kill and/or fill-up line shall be connected to the landing base side outlet.

c) When sufficient space below the rig substructure is available, a ball valve shall

be used below the annular, as shown in Figure J.10.

d) Annular preventer will be visually inspected and functionally tested prior to installation and pressure tested after installation using a cup-type tester set at a depth of 60’. Test pressures will be specified in the workover program.

WELL CONTROL MANUAL



2.2 Class ‘II’ 3000 psi Workover Stack

a) This class BOP stack is used on most onshore workovers to be performed on

producing, water injection and reservoir observation wells. These wells are normally low-pressure and equipped with 3000 psi WP wellhead equipment.

b) The minimum equipment required will be an annular type preventer and a

hydraulically operated dual ram preventer (or two single ram preventers) with blind rams (bottom) and pipe rams (top). Two (2) 3-1/16” 3M side outlets from below the blind rams are required, one for kill line hook-up and one for the choke line.

c) The kill line shall be adapted to 2-1/16” 3M and connected directly to the mud

pumps or to the stand pipe manifold.

d) Position manual valves adjacent to the stack and HCR valves outboard on the kill and choke lines, as shown in Figure J.11.

e) All tees must be targeted with renewable 3M blind flanges (welded tees are not

acceptable). Chiksans and Weco connections are not acceptable. Coflex hose (coflon lined) may be used in combination with steel line for kill or choke line.

Ball Valve

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2.3 Class ‘III’ 5000 psi Workover Stack (same as Class ‘A’ 5000 psi Drilling Stack)

a) This class BOP is used on most offshore workovers and onshore wells with 5000 psi WP wellhead equipment.

b) The Class ‘III’ 5000 psi workover stack is arranged the same as the Class ‘A’

5000 psi drilling stack. All equipment requirements are as previously discussed in Section 1.2 and shown in Figures J.3 and J.4.

2.4 Class ‘IV’ 10000 psi Workover Stack (same as Class ‘A’ 10000 psi Drilling Stack)

a) This class BOP is used on all workovers with 10000 psi WP wellhead equipment.

b) The Class IV 10000 psi workover stack is arranged the same as the Class ‘A’

10000 psi drilling stack. All BOP equipment in this stack shall be 11” 10M rated working pressure, including the annular preventer. All other equipment requirements are as previously discussed in Section 1.1 and shown in Figures J.1 and J.2.

Two (2) 3” minimum flanged outlets required below blind rams (one for the kill line hook-up and the other for the choke line). The kill line shall be adapted to 2-1/16” 3M.

3-1/16” Min

Double Gate or Two Single

WELL CONTROL MANUAL



2.5 General Requirements for Workover BOP Equipment

• All newly manufactured BOP equipment shall be API monogrammed.

• A full OEM certification of the BOP, choke manifold (including chokes), and all related equipment (i.e. closing unit, kill line valves, choke line valves, coflex hoses etc.) shall be required at contract start-up and contract renewal with a maximum period of 3 years between OEM re-certification.

• The BOP should be opened, cleaned, and visually inspected after every nipple down, including servicing the manual lock screws.

• Elastomers exposed to well fluids shall be changed at a maximum of every 12 months, unless visual inspection requires changing earlier. However, it is acceptable to use seal elements for 30” annulars up to 36 months (provided inspections are satisfactory, properly documented, and the expiration date of the elastomer is not exceeded). Seal elements for all other annulars (21-3/4” and smaller) shall be replaced no later than every 12 months, as per policy.

• A Maintenance Log for each piece of BOP equipment shall be maintained. This log shall include, at a minimum, records of all service and inspections performed on the BOP. The log will travel with the Contractor owned equipment and shall be kept in the BOP shop for Saudi Aramco owned equipment.

• The pressure rating of all pressure control equipment (BOP, valves, etc.) must be greater than the maximum anticipated surface pressure during the workover.

• Vibrator hoses on the rig pumps shall have molded end connections. Threaded or seal welded connections are not acceptable.

• The through-bore size of the preventer stack, tubing head, and any adapters used in the BOP hook-up shall be large enough for the maximum size bit, scraper, liner hanger, packer, plug, cup tester, or any other large diameter down-hole tools to be pulled or run.

• A double-ram preventer may be used in the Class ‘II’ 3M stack, but the connection for the choke line and kill line must be below the blind ram (lower ram). The diameter of all preventer side outlets must be as large as the choke manifold lines.

• Valve Removal (VR) plugs are not required on side outlets of the ram preventers.

• All ram preventers must be equipped with manual or automatic locking devices, which must be locked whenever the rams are used to control the well. Hand crank/wrench or hand wheel systems are acceptable manual locking devices.

• The inside manual valves on the choke and kill lines are considered master valves and normally would never, except for pressure testing, be closed unless the outside valve (HCR) has failed.

• Check valves must be installed on the kill lines but are not required on the emergency kill line.

• The emergency kill line and choke/kill lines should be washed out as required to prevent mud solids settling.

WELL CONTROL MANUAL



• Preventer assemblies will be dismantled between wells to inspect for internal

corrosion and erosion and to check flange bolts.

• At least one spare set of ram seals (top seals and packer rams) for all rams, including packer rams for each size of tubing or drill pipe to be used, bonnet or door seals, connecting rod seals, plastic packing for ram shaft secondary seals, ring gaskets to fit flange connections, and spare seal element for the annular preventer must be on the rig site.

• Ram blocks should not be dressed until ready to use.

• Only OEM parts are acceptable when repairing or redressing the BOP, valves, chokes, and closing units.

• All rigs shall maintain a logbook of BOP schematics detailing the components installed in each ram cavity. The logbooks shall contain the part number, description and installation date of ram blocks, top seals, ram or annular packers and bonnet/door seals. To be witnessed/co-signed by Toolpusher and Saudi Aramco Representative (see Form # 1.0 in Section S of this manual).

• All preventers shall meet NACE STANDARD MR-01-75 (Latest Revision).

• All workover rigs using a 3M choke manifold shall use the manifold configuration described in Section J 4.0.3. This manifold includes one (1) 3” minimum diameter choke line, two (2) 3” minimum flare lines, a manual adjustable choke and a remote hydraulic controlled adjustable choke.

• All wells on the same offshore platform shall be shut-in prior to workover operations using two (2) mechanical methods of isolation,

Below Surface: Closed and Tested Surface Controlled Sub-Surface Safety Valve (locked out of operation). Prior to moving in a workover rig, Field Services will close Sub-Surface Safety Valves on all wells and de-pressurize the platform. If a Sub-Surface Safety Valve is leaking, Well Services will replace the valve.

At Surface: Closed Master Valve

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2.5.1 Annular Units

§ Cameron, Shaffer, and Hydril are acceptable manufacturers for annulars.


3000 psi and less 2.5% H2S and 180°F 5000 psi equipment 2.5% H2S and 180°F 10000 psi equipment 2.5% H2S and 180°F

§ Gray/Regan diverters are acceptable for 500, 1,000, and 2,000 psi service.

§ If a rotary diverter system is utilized on an offshore rig, the diverter lines must have the capability of discharging below the bottom of the hull due to H2S.

2.5.2 Fixed Ram Preventers

§ Cameron, Shaffer and Hydril are acceptable manufacturers for fixed rams.

§ As of April 2000, Hydril has met the minimum acceptable ratings.

§ Only fixed rams are acceptable as master pipe rams on all BOP stacks.



2.5.3 Variable Bore Ram Preventers

§ Variable bore rams (VBR) are optional for tapered drill string applications on Class ‘A’ stacks. However, the master pipe ram must be a fixed ram.

§ The Cameron Extended Range High Temperature VBR-II Packer (3-1/2” to 5-7/8” pipe sizes) for the Cameron 13-5/8” U Type blowout preventer is acceptable for 3M and 5M applications. The VBR was successfully tested to 250 degrees F with a CAMLAST elastomer rated for 20% H2S. See Section S for details.

§ The minimum acceptable ratings for H2S and temperature for VBRs are,



2.5.4 Shear Blind Rams

§ A new policy of utilizing shear blind rams (SBR) in Saudi Aramco operations was approved in October 2000.



WELL CONTROL MANUAL



§ Cameron and Shaffer are acceptable manufacturers for SBR (refer to Section

1.7.4 for details).

§ The minimum acceptable ratings for H2S and temperature for SBR are,



§ Hydril’s shear blind rams are not approved at this time. Their current temperature rating is limited to 180 0F.

§ All rigs utilizing SBR shall have a 3” emergency kill line. This will provide additional emergency kill line capacity, in case the SBR did not make a proper seal after cutting the pipe. If the wellhead spool outlet is 2”, then the inboard manual valve shall be 2” with DSA back to 3”.

§ The table shown in Section 1.7.4 indicates the shear capability of SBR for different BOP pressure applications.

2.5.5 Blind Flanges on BOP Side Outlets

§ Flanges installed on the side outlets of ram preventers that do not have VR (Valve Removal) plugs installed shall be blind with no penetrations.

§ Flanges installed on the side outlets of ram preventers that have VR (Valve Removal) plugs installed shall have a ½” NPT tap with a ½” NPT plug installed.

2.5.6 Minimum Bore Requirements for Kill, Emergency Kill, and Choke Lines

§ The minimum bore size for kill, emergency kill, and choke lines shall be the same bore as the weld neck flange used in the pressure application (see specification details in Section R).

§ All lines shall be welded and pressure tested as per API Specification 6A.

3.0 Special Well Operations BOP Stacks The following represents Drilling and Workover’s minimum BOP equipment requirements for coil tubing, snubbing, and wireline operations. In some cases, the service company’s internal policy may exceed these BOP requirements.

3.1 BOP Equipment Requirements for Coil Tubing Operations

BOP equipment requirements for low-pressure and high-pressure coil tubing (CT) operations are shown in Figures J.12 and J.13, respectively. Selecting the BOP arrangement shall be based on the maximum anticipated operating or shut-in wellhead pressure. These arrangements are for standard CT operations and should be modified as needed for special or unusual applications.

WELL CONTROL MANUAL



3.1.1 Low-Pressure Coiled Tubing BOP Equipment Requirements

The low-pressure or standard arrangement (less than 5000 psi WHP) includes 4 sets of rams: blinds rams on top, cutter rams in the #2 position, slip type rams in the #3 position, and tubing rams in the #4 position. In addition, there is a flow cross with a valve installed below the cross. See Figure J.12.

Low-pressure stacks shall comply with the following minimum requirements: • All equipment shall meet or exceed NACE MR-01-75 and API Standards

for well control • Rated WP greater than the maximum anticipated well pressure • Side-door stripper • Minimum BOP configuration of blind, shear, slip, and pipe rams • Kill line with minimum 2-1/16” flanged connection • Flow cross with flanged outlets and double valves • Ability to monitor wellhead pressure below the pipe rams with isolator • Slip design that will minimize fatigue/deformation damage • Slip rams capable of holding the pipe up to the yield point with maximum

rated WP in a hang-off mode • Accumulator shall be sized to operate all BOPE (close-open-close) at

maximum rated WP

Figure J.12 Low-Pressure Coil Tubing BOP Arrangement

WELL CONTROL MANUAL



3.1.2 High-Pressure Coiled Tubing BOP Equipment Requirements

The high-pressure arrangement (greater than 5000 psi WHP) includes the same equipment as in the low-pressure arrangement, plus a second set of tubing rams below the flow cross when lifting the well. The master pipe rams should be substituted for combination shear/seal and pipe/slip rams when flowing the well with coil tubing in the hole (i.e. treating or production logging). A second stripper is also required when treating or production logging. See Figure J.13.

High-pressure stacks shall comply with the following minimum requirements:

• All equipment comply or exceed NACE STANDARD MR-01-75 and API Standards for well control

• Rated WP greater than the maximum anticipated well pressure • Side-door stripper • Second side-door or radial stripper is required if flowing well w/ CT in hole • Minimum BOP configuration of blind, shear, slip, pipe rams, and master

pipe rams below flow cross • Master pipe rams should be substituted for combination shear/seal and

pipe/slip rams when flowing the well with CT in the hole • Kill line with minimum 2-1/16” flanged connection • Flow cross with flanged outlets and double valves • Ability to monitor wellhead pressure below the pipe rams with isolator • Slip design that will minimize fatigue/deformation damage • Slip rams capable of holding the pipe up to the yield point with maximum

rated WP in a hang-off mode • Accumulator shall be sized to operate all BOPE (close-open-close) at

maximum rated WP

Figure J.13 High-Pressure Coil Tubing BOP Arrangement

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3.2 BOP Arrangement for Snubbing Operations

The stack arrangements in Figure J.14 and J.15 show basic set-ups for low-pressure and high-pressure snubbing operations. Selecting the BOP arrangement shall be based on the maximum anticipated operating or shut-in pressure.

3.2.1 Low-Pressure Snubbing BOP Equipment Requirements

The low-pressure (less than 5000 psi WHP) or standard arrangement’s basic features are the #1 and #2 stripping rams, equalizing loop, safety, and blind rams. The primary rams are the #1 and #2 stripping rams. These rams are used in conjunction with the equalizing loop to strip the pipe into or out of the hole. The equalizing loop and vent line are used to bleed off the pressure. Note that the equalizing loop contains a fixed or positive choke to minimize the surge pressure when bleeding off the pressure. Each set of valves contains one manual and one remotely operated valve. Below the #2 rams is a set of safety or secondary rams to be used whenever either of the stripper rams begin to leak or fail. Below the safety rams is a set of blind rams to be used to shut the well in when pipe is out of the hole or landed in the hangar.

Figure J.14 Low-Pressure Snubbing Stack

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3.2.2 High-Pressure Snubbing BOP Equipment Requirements

The high-pressure arrangement (greater than 5000 psi WHP) includes everything the standard arrangement has plus a second spool with dual outlets that contains a remotely operated choke, a set of shear blind rams, and a second set of safety rams. The shear blind rams are considered a third line of defense and are a last resort if primary control of the well is lost. In addition, a positive choke is added to the vent line to allow a slower bleed-off of pressure from the well.

Outlet Spool with Dual Hydraulic Chokes

Figure J.15 High-Pressure Snubbing Stack

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3.3 BOP Arrangements for Electric Line Operations

The required BOP arrangement shall be determined by the electric line application (open-hole or cased hole) and maximum anticipated surface pressure during the operation. All BOP equipment shall comply with API 6A and NACE MR-01-75 (Latest Revision).

3.3.1 Open-Hole Electric Line BOP Requirements (Over-Balanced Condition)

When open-hole logging, an electric line BOP is not required, provided primary well control (hydrostatic pressure > formation pressure) can be maintained and confirmed. However, an electric line BOP is recommended on all gas wells by the Gas Drilling & Workover Operations Department.

3.3.2 Cased-Hole Electric Line BOP Requirements (Under-Balanced Condition)

When perforating or logging under-balanced, an electric line BOP and lubricator are required with a wellhead adapter flange connected to the top of the test head or tree. Minimum electric line BOP requirements for various cased-hole pressure applications are summarized below.

Cased-Hole Electric Line BOP Requirements:

(Under-Balanced Condition) 7/32 –1/4” Line

Wells with Max. Expected WHP

< 5,000 psi

Wells with Max. Expected WHP 5,000 to 10,000

psi Working Pressure

5,000 psi

10,000 psi

Manual BOP

Not Acceptable

Not Acceptable

Hydraulic BOP

Required

Required

Minimum Number of Rams

2

3

Minimum Temperature Rating of Elastomer

2500 F

3000 F

Tool Trap

Required

Required

Tool Catcher

Optional

Optional

Ball Check Valve

Required

Required

Remote Grease Injection Unit

Required

Required

Stuffing Box with Hydraulic Operated Pack-Off

Required

Required

A stuffing box (w/ hydraulic operated pack-off) is required in unperforated cased hole when running CBL, or similar logs, with + 1000 psi surface pressure while logging. An electric line BOP is optional in this situation.

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A typical electric line rig-up for cased-hole operations is shown in Figure J.16.

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4.0 Choke Manifolds

All choke manifolds and piping shall meet Sour Service NACE MR-01-75 (Latest Revision) and API Specification 6A. Required specifications and applications for the 10000 psi, 5000 psi, and 3000 psi choke manifolds are shown below.

4.0.1 10,000 psi Working Pressure Choke Manifold

ACCEPTABLE FOR THE FOLLOWING CLASS APPLICATIONS: CLASS ‘A’ 10,000 PSI (DRILLING)

CLASS ‘IV’ 10,000 PSI (WORKOVER)

All 10M psi (& higher) choke manifolds shall comply with the following minimum requirements:

• Valves and chokes shall be monogrammed to API Specification 6A and made to the following,

PSL-2 (with PSL-3 gas test) PR-1 MR-EE TR-U (Suitable for 3000 F service) Forged Bodies and Bonnets All valves must be of a single gate (slab) design

• All flanges and other components shall be monogrammed to API Spec-6A

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Choke manifold configurations for 5,000 psi onshore and offshore applications are shown in Figure J.18 and Figure J.18A respectively. Figure J.18B shows the test manifold and associated required connections from the choke manifold in offshore applications.

ACCEPTABLE FOR THE FOLLOWING ONSHORE APPLICATIONS:

CLASS ‘A’ 5,000 PSI (DRILLING) CLASS ‘III’ 5,000 PSI (WORKOVER)

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ACCEPTABLE FOR THE FOLLOWING OFFSHORE APPLICATIONS:

CLASS ‘A’ 5,000 PSI (DRILLING) CLASS ‘III’ 5,000 PSI (WORKOVER)

Note: All 3-1/8” lines shall be 5M flanged steel piping or Coflex flexible hose (coflon lined, with a

3” minimum ID). A combination of flanged steel piping and Coflex hose is acceptable. Weco or chiksan-type connections are not acceptable. Only targeted or block-tee elbows with renewable blind flanges are acceptable.

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All 5M psi choke and test manifolds shall comply with the following minimum requirements:


PSL-2 PR-1 MR-EE TR-U Forged Bodies and Bonnets All valves must be of a single gate (slab) design


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ACCEPTABLE FOR THE FOLLOWING CLASS APPLICATIONS:

CLASS ‘A’ 3,000 PSI (DRILLING) CLASS ‘B’ 3,000 PSI (DRILLING) CLASS ‘C’ 3,000 PSI (DRILLING)

CLASS ‘II’ 3,000 PSI (WORKOVER)

All 3M psi choke manifolds shall comply with the following minimum requirements:


PSL-2 PR-1 MR-EE TR-U Forged Bodies and Bonnets All valves must be of a single gate (slab) design


-

Remote ControlledHydraulic Choke

ManualAdjustable Choke

8”M

inim

um

O.D

4-Way Crossw/ Pressure Tap and

Gauge

OPEN

OPEN

#2 To Flare Pit(3” Minimum Line)

OPEN

To Shaker/Trip Tank

CLOSED

3-1/16” Min. x 3M

#1 To Flare Pit(3” Minimum Line)

Note - 1

OPEN

3-1/16” Min. x 3M

3-1/16” Min. x 3M

Note: 1. Manual Valves on LP downstream side of Buffer Tank are normally OPEN 2 Manual Valves upstream of Buffer Tank are normally OPEN 3 Manual Valve upstream of Buffer Tank on emergency gut line is normally CLOSED and downstream

Manual Valve is normally OPEN

Figure J.19 3,000 psi Working Pressure Choke Manifold

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4.1 Location

The choke manifold shall be skid mounted on land rig (rig floor mounted on offshore rigs) and located in an accessible area.

4.2 Choke Manifold Pressure Ratings

The complete choke manifold, chokes, valves and piping will be full working pressure of the BOP stack through the block valves down-stream of the chokes.

4.3 Piping Specifications

The piping from the BOP stack to the choke manifold shall have the same working pressure (or greater) as the BOP stack. All piping shall meet Sour Service NACE MR-01-75 (Latest Revision) and API Specification 6A. Choke lines for 3M and 5M applications shall either be steel pipe, Coflex hose (coflon lined only), or combination of Coflex and steel pipe. All flexible hose shall be monogrammed to API Specification 16C, and all end connections monogrammed to API Specification 6A. Choke lines for 10000 psi application shall be flanged pipe only. All fabricated steel piping shall be as straight as possible, with targeted or block-tee elbows at turns. All tees must be targeted with renewable blind flanges (welded tees are not acceptable). All choke line and manifold connections shall be flanged, welded, integral, or hubbed. Chiksans and Weco connections are not acceptable.

4.4 Choke Manifold Discharge

Provisions shall be made for the discharge from the choke manifold to be selectively diverted to: 4.4.1 Flare Lines

Two (2) 3-1/2” EUE flare lines, each approximately 400 feet in length, shall be required for onshore oil wells. Four (4) 4-1/2” LTC gas flare lines and one (1) 3-1/2” EUE liquid flare line, each 1000 feet in length, shall be required for onshore gas wells. Note: Using drill pipe for flare line is not recommended because of the

difficulty of properly making up the connections on the ground. Elbows and chiksans on the flare line are susceptible to erosion/washouts and are not acceptable (because of the potential for high fluid velocities). The flare line, as with the choke line, shall be as straight as possible, with targeted or block-tee elbows at turns, as required.

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An alternate flare pit and flare line will be rigged-up on deep gas wells (Figure J.20). This emergency flare pit will be used in well kill operations if the main flare pit cannot be utilized due to change in wind direction. Electronic flare ignition sources shall be positioned in the main flare pit, alternate flare pit, and gas buster flare pit.

4.4.2 Gas Buster Lines

There should be a bypass line up-stream of the gas buster directly to the flare line and a valve on the gas buster inlet line to protect the separator from high pressure. The mud discharge line from the gas buster must have a vacuum breaker stacked vent line if the discharge line outlet is lower than the bottom of the separator. This is to prevent siphoning gas from the separator to the mud pits. The vacuum breaker stack must be as high as the gas buster.

One (1) 8” flanged/clamped steel vent line, minimum of 240 feet in length (from the gas buster), shall be required for onshore oil wells.

Two (2) 8” flanged/clamped steel vent line, minimum of 240 feet in length (from the gas buster), shall be required for onshore gas wells.

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The flare pit shall be positioned away from the reserve/waste pits to prevent ignition of any waste hydrocarbons while circulating gas from the wellbore.

Specific design requirements for gas buster are discussed in Section 8.3.

4.5 Choke Requirements

A remote-controlled hydraulic choke(s) shall be installed on each manifold. A SWACO ‘Super Choke’, Cameron Drilling Choke or NL Drilling Choke are acceptable units. Other hydraulic control steel drilling chokes will be considered on an individual basis. All hydraulic control chokes must be able to provide full closure.

§ Two (2) remote-controlled hydraulic chokes are required on all 10M applications § Two (2) remote-controlled hydraulic chokes are required on all 5M applications § One (1) remote-controlled hydraulic choke is required on all 3M applications

4.6 Valve Requirements

All manifold valves shall be non-rising stem gate or plug valves and monogrammed to API Specification 6A. Additional valve specifications are described in Figures J.17, J.18, and J.19 for each pressure application. It is acceptable to convert API monogrammed ‘DD’ valves to ‘EE’ under API 6A, Section 11.

4.7 Gauges

All chokes manifolds shall have a remote reading pressure gauge on the rig floor at the hydraulic operating panel.

4.8 Line Maintenance

The choke line, choke manifold, mud/gas separator, valves, lines and flare lines shall be flushed with water after testing or use.

4.9 Normal Valve Position

During normal operations, the valves downstream from the hydraulic control gates and the hydraulic control chokes shall be in the open position as shown in Figures J.17, J.18, and J.19.

5.0 Accumulator Closing Units The brand of closing unit used by the drilling contractor is not dictated by Saudi Aramco; however, the closing unit must meet the following minimum requirements.

5.1 Fluid Requirements

The accumulator shall store enough fluid under pressure to close all preventers, open the choke hydraulic control gate valve (HCR), and retain 50% of the calculated closing volume with a minimum of 200 psi above pre-charge pressure, without assistance of the accumulator pumps.

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5.2 Design Requirements

The accumulators and all fittings are to be 3,000 psi working pressure. Hydraulic lines from the accumulator to the BOP stack shall be designed and manufactured in compliance with API Specification 16D. They must be steel or approved armored hose (equivalent to Goodhall No. 660 with 4000 psi working pressure). Manifold and BOP hydraulic lines should be tested to 3,000 psi at installation to ensure pressure integrity at higher pressures.

Note: All air and hydraulic BOP operating units shall be equipped with regulator valves similar to the Koomey Type TR-5, which will not fail open causing loss of operating pressure.

5.3 Bottle Pre-Charge Requirements

The accumulator bottles will be pre-charged with nitrogen as per manufacturer’s specifications/recommendations. The minimum required pre-charge pressure for a 3000 psi working pressure accumulator unit is 1,000 psi. The nitrogen pre-charge pressure shall be checked and adjusted prior to connecting the closing unit to the BOP stack and any other time the accumulator must be completely de-pressured.

The accumulator should be capable of closing each ram within 30 seconds. Closing time should not exceed 30 seconds for annulars smaller than 18-3/4” nominal bore and 45 seconds for annular preventers of 18-3/4” and larger.

5.4 Operator Control Requirements

All operating controls shall be clearly marked with function and ram sizes. Accumulator controls must be in open or closed position, but not in neutral position. During normal drilling operations the hydraulic control choke line gate valve next to the wellhead will be closed.

5.5 Accumulator Location

The accumulator shall be located at a remote location, at least 60 feet distance from the wellbore for oil wells and 100 feet for gas wells, shielded from the wellhead and protected from other operations around the rig. There must be at least two (2) sets of remote controls for operating the accumulator to activate the BOPs. One remote control shall be on the rig floor, accessible to and visible by the driller and the other shall be located 100’ from the wellhead and near the Company Representative’s office. Master Controls shall be at the accumulator.

5.6 Pump System

The primary electric/hydraulic pump system and the secondary air/hydraulic pump system must be independent of each other and fully operational when the accumulator is in use. The high-pressure set point for both the electric pump and air pump should be 3,000 psi. The low-pressure set point should be above 2,800 psi for both systems. Do not bleed off pressure due to ambient temperature rise. Pressure may vary from 3,000 to 3,400 psi in a 24-hour period.

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5.7 Pressure Regulator Settings

The pressure regulators for the annular preventer and ram preventers will be set as per manufacturer’s specification/recommendation.

Note 1 For non-emergency BOP operation, use of the lowest possible pressure for daily operation will extend rubber life. Upon completion of daily testing, return pressure regulators to normal operations pressure.

Note 2 DO NOT close annular preventers on open hole for complete shut-off except in an

emergency. Note 3 DO NOT close pipe rams without pipe in the hole. Pipe rams should only be

closed on the proper size pipe in order to avoid damage to the rubber packer or to the ram carriers.

6.0 Sizing BOP Closing Equipment

6.1 General Requirements

The accumulator system and pumps must be of adequate capacity for the BOP stack in use. The system must hold pressure without leaks or excessive pumping and should maintain enough pressure capacity reserve to close the preventers with the recharging pumps turned off. These pumps are designed to charge the accumulator within a reasonable time period and maintain this charge during preventer operations. Saudi Aramco’s design base for accumulator capacity is the following:

a. A hydraulic actuating system that provides sufficient accumulator capacity to supply 1.5 times the volume necessary to close and hold closed all BOP equipment units with a minimum pressure of 200 psi above the pre-charge pressure without assistance from a charging system.

b. An accumulator-backup system shall be automatic, supplied by a

power source independent from the power source to the primary accumulator-charging system, and possess sufficient capability to close all blowout components and hold them closed.

The design base is equivalent to sizing a 3000 psi accumulator (1000 psi pre-charge) with enough capacity to close the annular and all ram preventers one time, with the pumps out of service, while maintaining a minimum remaining operating pressure of 1500 psi. This equivalence is shown on the next page.

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This demanding base using a 50% safety factor is recommended by Saudi Aramco because it provides complete replenishment of fluid in “close” lines at the time preventers are activated. The safety factor also allows for loss of fluid capacity due to “inter-flow” in the four-way valves and possible loss through the packing of the preventer units. Opening/closing volume tables provide the necessary information to calculate individual requirements as to accumulator size needed. Hydraulically operated choke and kill line valves require added fluid capacity. It must be remembered that only one-half to two-thirds of the accumulator bottle is liquid filled when fully charged, depending on the unit.

6.2 Size Calculations

a) Determine the total gallons to close all the preventers. Check with manufacturer for exact volumes to function BOP equipment.

Gallons Blowout Preventer Equipment To Close

Typical Annular B.O.P. (13 5/8”, 5,000 psi W.P.) after normal wear 17.98

Three Typical Ram B.O.P.’s (13 5/8”, 5,000 psi W.P.) (3 X 5.8 gallons) 17.40 Total Gallons for Full Closure of All Preventers 35.38

The total system accumulator capacity should meet or exceed the following requirements:

Total Gallons to Close 35.38 50% Safety Factor (Required) 17.69

Total Gallons of Usable Fluid Required (VR) 53.07

b) Calculate the total volume (nitrogen and fluid) required for a 3,000 psi accumulator.

Use equation below and refer to pressure and volume diagram in Figure 21.

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Figure 21 System Pressure and Volume Diagram

Equation J.1 VR V3 = P3 P3 P2 P1 Where: P1 = Maximum pressure of accumulator when completely charged

P2 = Minimum operating pressure of accumulator

P3 = Nitrogen pre-charge pressure

V1 = Volume of nitrogen at maximum pressure

V2 = Volume of nitrogen at minimum pressure

V3 = Total accumulator volume of (nitrogen and fluid)

VR = Total usable fluid required including safety factor

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Therefore, for a 3000 system with 1000 psi pre-charge pressure,

VR

V3 = P3 P3

P2 P1 53.07

= 1000 1000 1200 3000 = 106.14 gallons

Alternate quick calculation, Table J.1 Surface BOP Quick Sizing Table

Accumulator Pre-Charge Sizing Factor 5000 psi 1500 psi 2.58 3000 psi 1000 psi 3.0

Multiply gallons to close all preventers by 3.0 for a 3000 psi BOP control system with 1000 psi pre-charge:

= 35.38 gal x 3.0 = 106.14 gallons

c) Determine the number of accumulator bottles required Divide the total accumulator volume (nitrogen and fluid) by the nominal accumulator capacity. The nominal accumulator capacity is the accumulator size in gallons, less 1 gallon to allow for bladder/float displacement.

Using 11-gallon accumulator bottles: Total Accumulator Volume = 106.14 Nominal Accumulator Capacity 10.00 Number of Eleven Gallon Bottles = 10.61 or 11

Total Accumulator Volume = 110 Gallons

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6.3 Alternate Size Calculations

Another method of sizing the accumulator capacity is as follows:

Take a 10-gallon nominal accumulator bottle and a pre-charge pressure of 1000 psi.

Let,

V = Total volume of bottle (excluding volume occupied by the bladder)

Vx = Volume of nitrogen (N2) in the bottle at x psi. Calculate Vx for pressures of 1500 psi and 3000 psi.

Solution Bottle #1 (see Figure J.22) We know by definition that V1000 psi = 10 gallons of N2 and by using Boyles’ Law, we can calculate the values of Px at 1500 psi and 3000 psi. Solution Bottle #2 (see Figure J.22) P1 V1 = P2 V2 1500 psi (V1500) = 1000 psi (10 gal) V1500 = 6.67 gallons of N2 Solution Bottle #3 (see Figure J.22) P1 V1 = P2 V2 3000 psi (V3000) = 1000 psi (10 gal) V3000 = 3.33 gallons of N2 Thus, for a 3000 psi accumulator with 1000 psi pre-charge, V1000 = 3V3000 This verifies the Sizing Factor of 3 shown in Table J.1.

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Using the fluid requirements from the previous calculation, 35.38 gallons to close all preventers Calculate the number of bottles required to close this equipment and leave 1500 psi on the bottles. Taking a 10-gallon (nominal) bottle from 3000 psi to 1500 psi renders us

6.67 gal – 3.33 gal = 3.34 gallons of usable fluid Thus, we will require ....

35.38 gal = 10.59 bottles 3.34 gal/bottle

.... to close this equipment.

1,000 psi

6.67 gals

6.67 gals

3.33 gals

3.33 gals

Figure J.22 Accumulator Volumes at Varying Pressures

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This value rounded up to the nearest full bottle, equals (11) 10 gallon bottles or 110 gallons accumulator capacity. Check the requirement to provide sufficient accumulator capacity supplying 1.5 times the volume necessary to close all BOP equipment units with a minimum pressure of 1200 psi (200 psi above pre-charge). P1 V1 = P2 V2 1200 psi (V1200) = 3000 psi (3.33 gal) V1200 = 8.33 gal Useable Fluid = 10 gal – 8.33 gal = 1.67 gal (3000 psi to 1200 psi) We know that for a 10 gallon bottle, there is 5 gallons of usable fluid, (6.67 gal – 1.67 gal), when the pressure is reduced from 3000 psi to 1200 psi. Total Gallons to Close All BOP Units 35.38 50% Safety Factor 17.69 Total Gallons of Usable Fluid Required (VR) 53.07 Thus, the number of 10 gallon bottles required will be 53.07 gal / 5 gal/bottle = 10.6 bottles rounded up to (11) 10 gallon bottles

Therefore, both calculations for a 3000 psi accumulator (with 1000 psi pre-charge) show the same requirement stated in different manners.

• Have 1 times the fluid volume to close all BOP equipment with the

remaining bottle pressure of 1500 psi or greater. • Have 1.5 times the fluid volume to close all BOP equipment with the

remaining bottle pressure of 1200 psi or greater.

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Surface BOP Quick Sizing Example Preventer Working Gallons Type Manufacturer Size Pressure to Close Annular Hydril (GK) 13-5/8" 10000 psi 37.18 Pipe & Blind Rams Shaffer 13-5/8" 10000 psi 21.16 Pipe & Blind Rams Shaffer 13-5/8" 10000 psi 21.16 HCR Valve McEvoy (E) 4-1/16" 10000 psi 1.00 (open)

Total Gallons to Close 80.50

Will a 180 gallon 3,000 psi KOOMEY accumulator unit with (18) 11-gallon accumulator bottles and 1000 psi pre-charge meet Saudi Aramco sizing criteria? Volume Needed: 80.50 x 3.0 = 241.5 gals, or (25) 11-gallon bottles

7.0 Preventer Units

7.1 Annular Preventers

Introduction

When included in a particular BOP stack, the annular preventer is normally the first preventer used to shut-in the well. Annulars can close and seal on almost anything in the wellbore, and in some models, completely shut-off the open hole in emergency situations. With most annular preventers, closure is accomplished by applying hydraulic pressure to raise a contractor piston. As the piston travels upwards, it displaces and deforms a rubber-sealing element radially inward, eventually contacting and sealing around the outside of pipe in the hole. Compression of the rubber throughout the sealing area assures a seal against any shape.

Annular Preventers

§ Hydril ‘MSP’ § Hydril ‘GK’ § Hydril ‘GL’ § Shaffer ‘Spherical’ § Cameron Type ‘D’

Annular preventers with threaded caps are considered acceptable.

Note: Never use pipe dope on the screwed-cap threads.

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7.1.1 Hydril ‘MSP’

The Hydril ‘MSP’ preventer is a low pressure (2,000 psi) annular preventer, which is best suited for diverter applications. While the preventer can close completely on an open hole, this is not recommended. In the closed position, wellbore pressure acts upon the contractor piston to increase sealing effectiveness. The screwed top of the model shown in Figure J.23 makes it difficult and time consuming to change the sealing element, however, a latched-top version is also available.

Figure J.23 Hydril ‘MSP’ Annular Preventer

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7.1.2 Hydril ‘GK’

The Hydril ‘GK’ preventer is a highly wellbore pressure assisted annular preventer which is designed for land applications. (The 15M psi ‘GK’ is not wellbore pressure assisted). This preventer can close on an open hole in an emergency, but damage to the sealing element may result and element life will be reduced. In the closed position, element wear can be determined through an access port located in the top of the preventer. The lifting eyes shown in Figure J.24 should be used to lift the annular preventer only, never the entire stack.

Figure J.24 Hydril ‘GK’ Annular Preventer

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7.1.3 Hydril ‘GL’

The Hydril ‘GL’ preventer is designed primarily for subsea use but also finds application in the deeper land operations. The outstanding feature of the ‘GL’ preventer is its secondary closing chamber, which can be used to compensate for marine riser hydrostatic pressure effects in deep water. The secondary chamber also allows additional closing force to be placed on the contractor piston, which may be necessary in some instances since this preventer is only slightly wellbore pressure assisted. The secondary chamber port should never be plugged; either connect the port to the accumulator or leave it open. The ‘GL’ preventer shown in Figure J.25 has a latched head for easier sealing element change.

Figure J.25 Hydril ’GL’ Annular Preventer

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7.1.4 Shaffer ‘Spherical’ Preventer

The ‘Spherical’ preventer manufactured by Shaffer derives its name from the semi-circular profile on the inside of the cover. Closing pressure moves the contractor piston upwards, and deforms the sealing element upwards and radially inwards along the profile until a seal is made against the pipe in the hole. The ‘Spherical’ preventer can also close on open hole but this is not recommended. For Shaffer preventers greater than 13-3/8”, and closed on pipe greater than 7-5/8”, the closing pressure should be reduced below 1,500 psi to prevent pipe deformation. Charts, which specify the proper closing pressure, can be obtained from all annular preventer manufacturers. The ‘Spherical’ preventer shown in Figure J.26 is only slightly wellbore pressure assisted and has no provisions for measuring element wear without removing the cover.

Figure J.26 Shaffer ‘Spherical’ Annular Preventer

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7.1.5 Cameron Model ‘D’ Annular Preventer

The Cameron Model ‘D’ preventer uses two elastomer elements consisting of a donut and a rubber packer. When closing pressure is applied, the contractor piston moves upwards against the donut, which deforms inward onto the outside of the rubber packer. This action displaces the rubber packer radially inward to produce the seal. The packer is internally steel reinforced to help prevent excessive deformation of the packer under pressure. Since the Model ‘D’ preventer is not wellbore pressure assisted, closing pressure above 1,500 psi may be needed in extreme circumstances to affect a seal. Most sizes of the Model ‘D’ preventer use less closing fluid than the Hydril and Shaffer equivalents, and have a smaller overall height. The Cameron Model ‘D’ annular preventer is shown in Figure J.27.

Figure J.27 Cameron Model ‘D’ Annular Preventer

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7.2 Sealing Elements

All preventer manufacturers provide sealing elements of different composition, which are designed for use in specific wellbore environments. Tables J.2 and J.3 list some of these types of sealing elements for annulars.

Table J.2 Hydril Sealing Elements Packing Color Letter Recommended Usage Type Code Code Natural Rubber Black R Water-base mud, -300 to 2250 F. Synthetic Red S Oil-base mud with aniline (or Nitrile) points between 200 and 1900 F, and H2S service. Neoprene Green N Oil-base mud with operating temperature between – 300 and 1700 F. Table J.3 Shaffer Sealing Elements Packing Color Letter Recommended Usage Type Code Code __________________________________________________________________ Natural Rubber Red 1 or 2 Low temperature operations in water- base mud. Buna (Nitrile) Blue 5 or 6 Oil and water-base mud. H2S in oil-base mud. Neoprene Black 3 or 4 H2S in water-base mud.

Note: Currently the temperature rating of annular sealing elements is approximately 1800 F for Cameron, Hydril, and Shaffer.

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7.3 Stripping With Annular Preventer

Annular preventers will allow for stripping pipe because they have the ability to maintain a seal while passing tool joints and have a better abrasion resistance than pipe ram preventers.

Special attention should be given to the annular preventer during the stripping operations. The accumulator pressure regulator will maintain constant closing pressure. The response of most regulators is slow and requires that the tool joints be moved through the preventer slowly in order that the regulator be given time to react, thus avoiding damage and excess wear to the packing element.

The sealing element can be changed without removing the drillpipe. When it becomes necessary to change the sealing element, the rams below the annular preventer should be closed and locked. The top of the annular preventer is removed and the rubber-sealing element lifted out. This element is then cut between the metal ribs, the rubber parted, and then the old split rubber element is pulled from around the drillpipe. The new rubber-sealing element is cut (never sawed) between the metal rib reinforcements and the new element installed in a method reversed from the removal sequence. All replacement elements must be supplied by the original equipment manufacturer (OEM).

Note: Some Cameron sealing elements cannot be cut in this manner.

7.4 Ram Type Preventers

Acceptable units are:

§ Hydril Type ‘V’ Ram Preventer § Shaffer Type ‘LWS’ Ram Preventer § Shaffer Type ‘SL’ Ram Preventer § Cameron Type ‘U’ Ram Preventer

7.4.1 Hydril Type ‘V’ Ram Preventer

The Hydril Type ‘V’ ram preventer is designed for land applications and is available in a range of working pressures from 3M to 15M psi. The Hydril ram preventer can be equipped with automatic ‘multi-position’ locks or manual locks, which can lock the preventer in the closed position. The bonnet doors swing open on hinges to gain access to the cavity of the preventer and to change the ram blocks. Hydril ram blocks are loaded from the top onto the operating rod. A Hydril Type ‘V’ single ram preventer is shown in Figure J.28.

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7.4.2 Shaffer Type ‘LWS’ Ram Preventer The Shaffer ‘LWS’ (Light Weight Steel”) preventer is designed for land applications and is available with working pressures ranging from 2,000 to 10,000 psi. Like the Hydril preventer, the bonnet doors on all Shaffer preventers swing open to gain access to the rams. The ‘LWS’ have a self-feeding action. This preventer can only be locked manually. A Shaffer ‘LWS’ ram single preventer is shown in Figure J.29.

Figure J.28 Hydril Type ‘V’ Ram Preventer

Figure J.29 Shaffer Type ‘LWS’ Ram Preventer

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7.4.3 Shaffer Type ‘SL’ Ram Preventer

The Shaffer Type ‘SL’ is a ram preventer which can be fitted with an automatic locking provision called ‘Posi-Lock’ (acceptable locking device). The ‘SL’ preventers are trimmed for H2S service and special rams are available which can be used to hang-off the drillpipe. The Shaffer hydraulic system is routed through the door hinges and into the operating cylinder. Shaffer preventers (and all hinged door preventers) should never be “pumped open” by applying closing pressure, as this will almost surely damage the operating rod and the foot. A Shaffer Type ‘SL’ triple ram preventer is shown in Figure J.30.

7.4.4 Cameron Type ‘U’ Ram Preventer

The Cameron Type ‘U’ preventer is a wellbore pressure assisted ram preventer suitable for surface or subsea installations. All Type ‘U’ preventers manufactured since 1979 are equipped for H2S service. The outstanding feature of the Type ‘U’ preventer is its ability to “pump open” the bonnet doors. After removing four bonnet bolts, closing pressure can be applied. This will open the bonnets for easy top-load ram changing. A Cameron Type ‘U’ single ram preventer is shown in Figure J.31.

Figure J.30 Shaffer Type ‘SL’ Ram Preventer

WELL CONTROL MANUAL



7.5 Ram Construction

7.5.1 Hydril Rams

Hydril rams are constructed of a front packer and an upper seal, which are attached to a solid steel ram block. The packer or the seal can be replaced independently of the other. Hydril rams also have a replaceable seal installed in the upper ram cavity, which should be checked if the preventer still leaks after ram seal replacement. The ram block is installed in the preventer by sliding down over a foot attached to the end of the operating rod. The front packers of opposing rams make contact upon closure and the upper seals prevent pressure from exiting about the rams. Various Hydril rams are shown in Figure J.32.

Figure J.31 Cameron Type ‘U’ Ram Preventer

Figure J.32 Hydril Rams

WELL CONTROL MANUAL



7.5.2 Cameron Rams

Cameron rams consist of a front packer element and an upper seal, which are installed onto a single solid steel ram block. Cameron rams have a “self-feeding” feature, which allows additional elastomer material to be extruded as wear is experienced. This is accomplished by bonding two steel plates to the upper and lower surface of the ram-packing element. When the preventer is closed, the steel plates make contact first which forces them into an area inside the ram block which is normally occupied by the elastomer material. This movement extrudes the elastomer material towards the center of the preventer, thus producing a seal. The Cameron ram construction is shown in Figure J.33.

Figure J.33 Cameron Rams

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7.5.3 Shaffer Rams

Shaffer rams are constructed of a single elastomer seal installed between a steel ram block and a steel ram holder. The elastomer seal is attached to the ram block with two retaining screws, and this assembly is then secured to the ram holder with two large retracting screws. Shaffer rams are loaded from the side onto the operating rod. The Shaffer ram construction is shown in Figure J.34.

7.6 Variable Bore Rams

Pipe rams are designed to close on one size of pipe only. All manufacturers of ram preventers offer variable bore rams, which can close and seal on a range of pipe diameters. These rams can be especially useful when a tapered string is in use or when sub-base space limitations restrict the addition of another ram preventer. Also, since the tube of aluminium drillpipe has a larger diameter near the tool joints than at the center, an effective seal cannot always be assured when regular pipe rams are in use. Variable bore rams (VBR) may be the best solution for this problem.

Figure J.34 Shaffer Rams

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Variable bore rams have limited hang-off potential, depending on the size of the pipe on which they are sealing. Most variable bore rams are constructed in a similar fashion with the key element being a feed-able rubber packer. A Cameron VBR is shown in Figure J.35.

Variable bore rams are optional for tapered drill string applications on Class ‘A’ stacks, but must meet the minimum acceptable limits for H2S and temperature. The minimum acceptable ratings for H2S and temperature for VBR are,


The Cameron Extended Range High Temperature VBR-II Packer (3-1/2” to 5-7/8” pipe sizes) for the Cameron 13-5/8” U Type blowout preventer is acceptable for 3M and 5M applications. The VBR was successfully tested to 250 degrees F with a CAMLAST elastomer rated for 20% H2S. See Section S for details. At this point in time, this the only VBR approved for use in Saudi Aramco operations. The VBR should not be used in the master ram position.

7.7 Shear Blind Rams

Shear blind rams (SBR) shear the pipe in the hole, bending the lower section of sheared pipe to allow the rams to close and seal. SBR can be used as blind rams during normal operations. SBR are available for H2S service with a blade material of hardened alloy service. Tandem boosters and bonnets large bore shear bonnets will be required for cutting 5” or 5-1/2” drillpipe.

Figure J.35 Variable Bore Rams

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An important point to remember about SBR is that they require high operating pressure (approx. 2800 psi) to shear pipe and affect a seal. This depends on the size and weight of pipe in use, size of preventer, and model of ram itself. Consideration should be given to dedicating accumulator fluid to the SBR independent of the remainder of the accumulator reserve. As of October 2000, Saudi Aramco has approved the conditional use SBR.



Cameron and Shaffer are acceptable manufacturers for SBR. Both manufacturers have met the Saudi Aramco requirements for pressure applications to 10M psi. The minimum acceptable ratings for H2S and temperature for SBR are,



The Cameron H2S SBR construction is shown in Figure J.36.

Figure J.36 Cameron Shear Blind Rams

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7.8 Secondary Seals

It is very important that wellbore pressure be isolated from the operating cylinder on all ram preventers. Normally a primary lip seal provides this function. The lip seal is installed in the bonnet through which the operating rod passes. If fluid pressure should bypass the primary seal and enter the operating cylinder, it is possible that the ram preventer could be forced open. To prevent this occurrence, a series of secondary seals are provided which may include:

§ Back-up O-rings § Plastic packing injection seal § Vent to the atmosphere (weep hole)

8.0 Accessory Blowout Prevention Equipment

8.1 Pit Volume Totalizers

Various devices will indicate gain or loss of drilling fluids from the mud pits. The volumes should be integrated or totaled from all pits to read out on a chart (or charts) near the driller’s position. Warning devices (horns, lights) are necessary to alert the crew to a change in pit volume. Several of these charts and warning devices should be installed in places such as the mud logging unit, the Toolpusher’s office, or the Drilling Representative’s office. These should be installed on all rigs drilling in areas with hazardous or uncertain formation pressures, and kept on at all times, even when out of the hole, changing bits, or logging. These devices may employ either air pressure or electric signals to monitor the pit volume. A typical pit volume totalizer system is shown in Figure J.37.

Figure J.37 Pit Volume Totalizer

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8.2 Mud Flow Indicators

Flowline monitoring devices detect early changes in the flow pattern of the drilling fluid system. Installed near the wellhead, they “sense” and respond before the pit volume devices do, thus giving the driller early warning of a mud return change, so that proper action can be taken immediately. These devices should be installed and kept operating continuously, even when out of the hole. There are two popular types of Flow Indicators on the market today; electrical differential and flow sensor type. The differential flow meter measures the difference between the fluid input and outflow for the well and records the difference on a strip chart. The flow sensor type uses a paddle installed in the flow line, which is deflected by increasing mud returns.

8.3 Mud Gas Separators

8.3.1 Degassers

Degassers remove gas entrained in the drilling fluid during normal drilling operations, preventing re-circulation of gas-cut mud. Circulating gas-cut mud into the hole can lead to reduction of the bottom-hole hydrostatic pressure and possibly a well kick. Compensating for entrained gas with weighting material unnecessarily increases costs. The degasser should be operated at least daily. Degassers also serve as a mechanical oxygen scavenger, extending the life of the drill string.

Degassers are available in both atmospheric and vacuum models. Atmospheric models occupy less space and are generally easier to maintain, but the vacuum types are generally more efficient. Vacuum degassers must have a 1” vent line, with check valve, tied into the gas buster outlet.

8.3.2 Gas Busters

Gas busters (poor boy degassers) generally are the first line of defense from gas around the location. The gas buster is an open top vessel normally connected to the end of the choke manifold. Most gas busters are constructed from a length of large diameter pipe with a series of interior baffles to cause a rolling/spreading of the drilling fluid. A siphon arrangement at the bottom permits mud to flow to the shale shaker while maintaining a fluid head to hold the gas in the upper part of the vessel. The gas vent pipe at the top shall be large enough to permit gas to be vented at a safe distance away from the rig, without much back-pressure. The vent line(s) shall consist of 8” flanged or clamped steel line (minimum of 240’ in length, from the gas buster) of the same pressure integrity (or greater) of the gas buster. Vent line(s) shall terminate in a flare pit, positioned away from the reserve/waste pits to prevent ignition of any waste hydrocarbons while circulating gas from the wellbore.

Gas busters are more efficient with clear fluids. Low viscosity fluids allow the entrained gas to break out easily under the atmospheric pressure of the vessel. Gas separation in viscous fluids is less; consequently, the flow rate to the gas buster may have to be reduced in order to handle larger amounts of gas. Gas blow-by is a term to describe over-loading the gas buster as pressure builds inside, displacing fluid in the mud leg and allowing the gas to enter the pit area.

WELL CONTROL MANUAL



Gas busters should be cleaned-out periodically. Never circulate cement returns through a gas buster. Gas busters have a tendency to shake/rattle when they are circulated through and should always be securely anchored. Gas buster designs for ‘deep gas rigs’ and ‘oil development rigs’ are shown in Figure J.38 and J.39, respectively. The minimum internal capacity for existing gas busters is 35 barrels deep gas rigs and 17.5 barrels for oil rigs.

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All gas busters shall be built in compliance to ASME Boiler and Pressure Vessel Code, Section VIII, Division I, with all materials meeting requirements of NACE Standard MR-01-75 (Latest Revision). All welding on the vessel shall meet ASME requirements. New gas busters shall be hydrostatically tested to 190 psi to give a maximum working pressure of 150 psi, as per ASME.

WELL CONTROL MANUAL



There should be a by-pass line upstream of the separator directly to the flare line and a valve on the separator inlet line to protect the separator from high pressure. The mud discharge line from the separator must have a vacuum breaker stacked vent line if the discharge line outlet is lower than the bottom of the separator. This is to prevent siphoning gas from the separator to the mud pits. The vacuum breaker stack must be as high as the separator.

8.4 Full-Opening Safety Valve

Safe operations require that a Full-Opening Safety Valve fit each size of drill pipe/ drill collar in use and be kept in the open position on the rig floor (including a closing /opening wrench). Then, should the well begin to flow when the kelly is detached, such as during trips or when making connections, the correct size can be stabbed into the drill pipe tool joint and made up. It is good practice to install a valve as a precaution when the drill pipe is left in the slips during rig repair or any other time that the kelly is not picked up. Care should be taken that all valves have the proper threads and will go through the BOP stack and casing, so that they could be stripped into the hole below a back-pressure valve (Inside BOP). A safety valve and appropriate cross-over are also required when running casing. Note that the term ‘full opening’ does not mean that the ID of the valve is the same as the pipe, but rather that the bore through the valve is not restricted. A drill string Full-Opening Safety Valve is shown in Figure J.40.

Figure J.40 Full-Opening Safety Valve

WELL CONTROL MANUAL



8.5 Inside BOP

The Inside BOP is a back-pressure type valve (or float valve) that allows stripping or running drill pipe into the hole without mud flow upward through the valve. It can be stabbed and made up on the drill pipe only at very low flow rates. The best method is to stab and close the Full-Opening Safety Valve first, then install the Inside BOP if the decision is made to go back into the hole. The ‘dart-type’ Inside BOP is one of the more widely used tools. The dart is used to hold the tool open, making it possible to install the tool while mud is flowing from the well. Release of the dart permits the valve to close. The upper sub is then removed and additional drillpipe may be added as desired. The ‘dart type’ Inside BOP is shown in Figure J.41.

Also available is a ‘drop-in’ Inside BOP, which can be pumped down the drillpipe. This tool lands and seats in a special sub installed in the bottom-hole assembly.

Figure J.41 Inside BOP (Dart Type)

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8.6 Drilling Chokes

The prime function of a drilling choke is to create a back-pressure on the well, which will increase bottom-hole pressure sufficiently to control formation flow while the well is circulated. Chokes are available in either positive or adjustable styles for flow control, with a variety of sizes and pressure ranges. An adjustable choke can better regulate pressure than a positive choke, which has a fixed opening. Hydraulic chokes are more easily adjusted and permit accurate regulation of choke pressure. An important feature of most hydraulic chokes is that the choke itself can be replaced in the manifold, but is controlled remotely from a panel, which also displays the casing and drillpipe pressures. One such remote hydraulic choke is shown in Figure J.42.

8.7 Trip Tank

A circulating tank will be used on all rigs while tripping out or back in the hole. The trip tank shall have two (2) 60 barrel compartments, complete with two (2) independent measuring devices (a mechanical float-operated pit level indicator, graduated in inches, and an electro-mechanical device). Calculated versus actual volumes shall be monitored and recorded in a log book.

Figure J.42 Cameron Drilling Choke

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The log book will be used on each well so that the following data can be recorded:

1) Volume and weight of slug 2) Number of strokes that the slug is pumped 3) Time for slug to stabilize and flow to stop in annulus 4) Amount of mud to fill hole per *five stands…...if the volume of mud

used to fill the hole is not correct for any interval, stop pulling and determine the reason the hole is not taking mud properly

* 5 stands for DP, 2 stands for HWDP, and every stand for DC

5) Total volume of mud per trip to fill hole (calculated and measured) 6) Leave drill pipe wiper rubbers off pipe for first five stands to observe

hole

A circulating trip tank is shown in Figure J.43. For details on tripping procedures, see Section C of this manual.

Note: 5 stands of 5” 19.5 /ft/ drill pipe pulled from 9-5/8” 53.5# /ft. casing will lower the

fluid level 56’, if there is no loss/gain from the hole and the float is working properly.

For example:

.007645 bbl/ft. displacement in .070765 bbl/ft capacity (0.070765 – 0.007645) / 0.007645 = 8.26’ of drill pipe pulled per foot of fluid

drop in casing and inside drillpipe

Figure J.46 Circulating Trip Tank Figure J.43

Circulating Trip Tank

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8.8 Stroke Counter

The Stroke Counter offers the Driller an alternative means of measuring fluid volume used to fill the hole on trips. In order to use the stroke counter properly, the Driller must know two things. First, the Driller must know the fluid displacement for the particular pipe and hole size being used. Second, the amount of volume discharged per stroke of the pump in operation must be known. This knowledge gives the Driller the ability to check for correct volumes required for fill-up while tripping. Using the stroke counter to measure hole fill-up is less accurate than using a trip tank, and is therefore not recommended. Also, there is a tendency to use the kill line for hole filling purposes when the rig pumps and stroke counters are used. This action is never recommended. The kill line is an emergency piece of equipment and should not be used for routing hole fill-up during trips. Stroke counters also provide a means of correctly displacing special fluids or lost circulation pills. Finally, a stroke counter is especially useful to determine pumped volumes while executing well control procedures.

8.9 Gas Detectors

These devices usually found in mud logging units, are useful in detecting abnormal pressure sections as well as shows of hydrocarbons. Rig Supervisors should monitor the trip gas, connection gas, and background gas for any significant change. The presence of gas in the mud can be one of the more useful indicators of abnormal pressure. Gas Detectors can sometimes be misleading however, and the important things to look for are the relative trends and magnitudes, rather than the individual number of gas units reported.

8.10 Mud-Logging Units

Mud logging companies furnish personnel and equipment to analyze well cuttings, mud and cuttings gas, drilling rate vs. formation, and gas type. They also provided detailed mud analysis and predict and analyze hydrocarbon shows. These useful units, personnel, and equipment should be fully utilized, for safety and economy.

8.11 Mud Weight Recorders

These devices periodically measure and record the mud weight. The output is useful for detecting light or heavy streaks in the mud due to ‘slugging’ or other causes. The Rig Supervisor should not depend wholly on these devices, and the mud personnel should check the mud weight routinely as well. The accuracy of these devices should be verified by frequent manual weight checks, particularly with high mud weights.

WELL CONTROL MANUAL



8.12 Drilling Rate Recorders

These devices are very useful as correlation tools, particularly if electric logs are available from other wells in the area. The records can be used to detect and correlate formation tops and types, as well as in selecting bits and estimating their useful lives. A sudden increase in penetration rate can be the first signs of a well kick.

8.13 Bowl Protectors

Bowl protectors (or wear bushings) protect the hanger bowl and the smallest ID of a casing or tubing head spool during extended periods of drilling. In most nipple-up procedures, the bore of the BOP, and its corresponding flange size, are always greater than the bore of the head or spool immediately below the stack. Consequently, the most prolonged contact the drill pipe, tools or tubing has with the surface equipment is at this point. This is aggravated if the derrick is not positioned exactly over the hole, and the pipe rides off-center.

Bowl protectors shall be used during all drilling operations on wells requiring more than 21 days of duration. For the latest specifications on Bowl Protectors, contact the manufacturer of the wellhead equipment being used.

8.14 Drillpipe Float Valves

The Drillpipe Float Valve provides an instantaneous shut-off against pressures below the bit when the well is shut-in and prevents back-flow up through the drill string. In essence a one-way check valve, the drillpipe float allows full flow through the valve under normal circulating conditions. Allowing formation fluids to flow into the drill string can be especially hazardous because the drillpipe can become evacuated very quickly. Also, if the drill string is contaminated by formation fluid when the well kicks, it will be impossible to accurately calculate the mud weight necessary to kill the well. Saudi Aramco’s policy is to run a Drillpipe Float Valve at all times (except when planned operations preclude running a float: as testing, treating, or squeezing). The drillpipe float shall be positioned directly above the bit.

Another advantage of the float valve is that it prevents cuttings from entering the drill string during a connection, which could plug the bit.

8.15 Valve Removal Plugs

The valve removal plug (VR plug) is a threaded one-way check valve that can be installed through an outlet valve on a casing head, casing spool, or tubing spool into a female thread in the outlet. This isolates the valve from any pressure and allows for removal of the outlet valve for its repair or replacement. Once the valve has been repaired or replaced, it can be re-installed and the VR Plug is removed.

VR plugs shall be removed from the wellhead in order to have access to the annulus. This should be confirmed prior to nippling-up the wellhead.

If a VR plug is removed from the blind flange side of the wellhead prior to installation, it must be replaced prior to the rig move/well completion. Under no circumstances should a VR plug be left in a wellhead outlet that has a gate valve installed.

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Note: VR plugs are intended for short-term use only, and should not be considered as a long-term replacement for wellhead valves.

Valve removal plugs are not required on side outlets of the ram preventers. Figures J.44 and J.45 illustrate examples of a VR Plug and Lubricator.

Figure J.44 Valve Removal Plug

Figure J.45 Lubricator

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8.16 Back Pressure Valves

8.16.1 One-Way Check Valves

A Back Pressure Valve, or tubing plug, is usually a One-Way Check Valve that is installed in a specially machined profile in the tubing hanger or plug bushing. The One-Way Check Valve is designed to prevent the flow of fluids and gases through the hanger, but still allows the pumping of fluid into the tubing string. They are installed in the well to remove the production tree and allow the initial nipple-up of the BOP stack, to install the tree while nippling down the BOP stack, and while heavy lifts are being made over the wellhead. The One-Way Check Valve can be installed or removed with either the tree or BOP stack nippled up on the tubing head. They can also be installed with or without pressure on the tubing. Installation of the One-Way Check Valve through the tree with pressure on the well requires the use of a lubricator. Wellhead manufacturers have various designs for Back Pressure Valves depending on the size and make of the hanger and wellhead. Only specifically trained personnel should perform the installation and removal of Back Pressure Valves. A Back Pressure Valve (one-way check valve) shall be set before rig-down or rig-up operations. Figure J.46 shows one model of a One-Way Check Valve.

Figure J.46 One-Way Check Valve

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8.16.2 Two-Way Check Valves

A Two-Way Check Valve (TWCV) is similar to a Back Pressure Valve but is specifically designed to plug the tubing in order to pressure test the tree or BOP stack. The TWCV uses a two-way plunger that will hold tubing pressure from below or moves down and seals test pressure from above. Tubing pressure can be bled down by inserting the retrieving/running tool, which will offset the plunger and allow pressure to by-pass. The TWCV is not to be used for nipple-up or nipple-down operations. When performing these operations a conventional BPV shall be installed. When nipple down, nipple up, operations are complete the BPV shall be removed and the TWCV installed and the equipment can be tested. Figure J.47 shows one model of a Two-Way Check Valve.

Figure J.47 Two-Way Check Valve

WELL CONTROL MANUAL



8.17 Coflex Hose

Coflex flexible steel hose (or a combination of flexible hose and hard line) may be used for kill or emergency kill line on 3M, 5M, and 10M psi applications and choke line on 3M and 5M psi applications, if the following requirements are satisfied,

§ Coflon lined and monogrammed to API Specification 16C. Hoses currently in the field, not monogrammed, may continue to be used for the remaining service life. However as hoses are replaced, they must be monogrammed.

§ All other components of the hose and end-fittings in possible contact with wellbore fluids meet Sour Service NACE STANDARD MR-01-75 (Latest Revision)

§ All end-fittings shall be flanged, welded, integral, or hubbed connections (which are molded to the hose and monogrammed to API Specification 6A)

§ Re-certification by OEM every 3 years § Certified for drilling service (no weep holes) § Same working pressure (or greater) as the BOP stack § Properly supported/anchored, where necessary, when used as choke line § Number of connections minimized when flexible hose is used in

combination with hard line

Coflex flexible steel hose may be used for flowline on 10,000 psi well testing applications, if the following requirements are satisfied,

§ Same as above requirements § Only if expected application has CO2

+ H2S < 30% § Certified for flowline service, complete with weep holes

8.18 Weco Connections

In high-pressure applications, especially with gas, the Weco hammer union lip-seal elastomer will most likely experience the typical ‘explosive decompression’ phenomena. The gas will migrate into the elastomer and deform/damage the lip-seal. The likelihood of a leak is even greater at higher temperatures and when the gas contains a high concentration of CO2. This problem has been encountered several times on deep gas wells. A metal-to-metal seal (API Flanged or Gray-Lock connection) will prevent this unwanted phenomena.

Integral or welded Figure 1502 connections are acceptable downstream of the buffer tank on the choke manifold for all land applications, provided they are monogrammed to API Specification 6A. Weco connections are not acceptable on the well test line (downstream of the choke manifold) for offshore operations.

Figure 602 connections are not allowed on any drilling or workover operation.

8.19 Chiksans

Chiksans are sections of pipe with hammer unions and two swivels in each joint. The primary use of chiksans is in high pressure pumping and cementing operations. Washouts can develop in the packing element in the swivel during long-term use applications. Chiksan-type joints are not acceptable as kill line, emergency kill line or choke line.

WELL CONTROL MANUAL

Drilling & Workover October 2002 SECTION K - MAINTENANCE AND TESTING REQUIREMENTS

Current Revision: October 2002 K - 1 3rd Edition Previous Revision: June 2001

Table of Contents

1.0 Maintenance of Blowout Prevention Equipment ........................ K - 2 2.0 Testing of Blowout Prevention Equipment................................... K - 4

2.1 General Pressure Testing Requirements ....................................... K - 4 2.2 Specific Requirements for Class ‘A’ 10,000 psi BOP Stack.......... K - 6 2.3 Specific Requirements for Class ‘A’ 5,000 psi BOP Stack............ K - 7 2.4 Specific Requirements for Class ‘A’ 3,000 psi BOP Stack............ K - 8 2.5 Specific Requirements for Class ‘B’ 3,000 psi BOP Stack............ K - 9 2.6 Specific Requirements for Class ‘C’ or ‘II’ Workover Stack ....... K - 10 2.7 Specific Requirements for Class ‘D’ Diverter Stack .................... K - 11

3.0 Pressure Testing Procedure ............................................................. K - 11 3.1 Function Testing and Flow Testing .............................................. K - 12 3.2 Fill the Stack with Water................................................................. K - 12 3.3 Casing Test (if required) ................................................................ K - 12 3.4 Blind Rams (if required) ................................................................. K - 13 3.5 Annular Preventer .......................................................................... K - 14 3.6 Upper Pipe Rams ............................................................................ K - 15 3.7 Positive Sealing Chokes................................................................. K - 16 3.8 Choke Manifold (continued)........................................................... K - 17 3.9 Choke Manifold (continued)........................................................... K - 18 3.10 Choke Manifold (continued)........................................................... K - 19 3.11 Choke Line HCR Valve.................................................................... K - 20 3.12 Choke and Kill Line Manual Valves ............................................... K - 21 3.13 Master Pipe Rams ........................................................................... K - 22 3.14 Small Pipe Rams ............................................................................. K - 23 3.15 Kelly, Surface Circulating Equipment, and Safety Valves .......... K - 24 3.16 Wellhead Valves .............................................................................. K - 24

4.0 Accumulator Testing ............................................................................ K - 25 5.0 Hang-Off Limitations while Testing ............................................... K - 28 6.0 Test Pressure Requirements for Casing Rams ........................ K - 28

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1.0 Maintenance of Blowout Prevention Equipment

Blowout prevention equipment is emergency equipment and must be maintained in its proper working condition at all times. The Drilling Foreman can best insure that Saudi Aramco is provided with equipment that performs to our specifications by being an active participant in the maintenance requirements of the BOP equipment.

Changes in this 3rd Edition of the Saudi Aramco Well Control Manual are indicated by a bold vertical line in the right margin, opposite the revision.

Several maintenance items, which the Drilling Foreman should verify on a daily basis (by reviewing the Driller’s pre-tour checklist or by personal observation), are listed below:

1) Examine the fluid level in the accumulator. Make sure it is at the proper level and proper pressures are indicated on the accumulator, manifold, and annular pressure gauges.

2) Verify the control lines are run to prevent damage by trucks or dropped tools.

3) Confirm the preventer controls are either in their proper opened or closed position (not neutral) and that leaks are not evident.

4) Assure the preventer stack is well guyed so that vibrations are minimized while drilling.

5) All preventers must be operated at least each time a trip is made. Alternate trip closures between the remote stations and the accumulator. The annular preventer does not have to be operated to complete shut-off. DO NOT close the pipe rams on open hole.

6) The emergency kill line and choke/kill lines shall be washed out as required to prevent mud solids settling. Clear water should be used to flush and fill the lines (except in extremely cold weather, where diesel or glycol should be used).

Other maintenance requirements are as follows:

7) DO NOT circulate green cement through the preventer stack or choke manifold. Always thoroughly flush with water any piece of blowout prevention equipment, which has come in contact with green cement and verify the equipment is clear upon the next nipple-up.

8) Make sure the rig is centered over the well to reduce drill string and BOP equipment contact and abrasion.

9) DO NOT use the kill line as a fill-up line during trips.

10) If possible, install the ram preventers so that the ram doors are positioned above and shield the valves installed on the casing head below.

11) All rigs shall maintain a logbook of BOP schematics detailing the components installed in each ram cavity. The logbooks shall contain the part number, description and installation date of ram blocks, top seals, ram or annular packers and bonnet/door seals. To be witnessed and co-signed by the Contract Toolpusher and Saudi Aramco Drilling Foreman (or Liaisonman).

WELL CONTROL MANUAL



12) Only OEM parts are acceptable when repairing or redressing the BOPE. Furthermore, only an approved OEM high-temperature lubricant is acceptable for valve maintenance.

13) At least one spare set of ram seals (top seals and packer rams) for all rams including packer rams for each size of tubing or drill pipe, as well as bonnet seals, must be on the rig site.

14) Ram blocks shall not be dressed until ready to use.

15) All BOP rubber goods shall be kept in a cool place and remain in the original packaging with expiration dates.

16) Preventer assemblies shall be dismantled between wells to inspect for internal corrosion and erosion and to check flange bolts.

17) Manufacturer‘s installation, operation, and maintenance (IOM) manuals should be available on the rig for all BOP equipment installed on the rig.

18) New ring gaskets shall be installed on each nipple-up at each connection, which has been parted. Ring gaskets should never be reused.

19) Studs and nuts should be checked for proper size and grade. Using the appropriate lubricant, torque should be applied in a criss-cross manner to the flange studs. All bolts should then be re-checked for the proper torque as prescribed in API Specification 6A.

20) Field welding shall not be performed on any BOP equipment. All repairs to BOP equipment must be performed at an OEM facility.

21) A Maintenance Log for each piece of BOP equipment shall be maintained. This log shall include, at a minimum, records of all service and inspections performed on the BOP. The log will travel with the Contractor-owned equipment and shall be kept in the BOP shop for Saudi Aramco-owned equipment.

22) All newly manufactured BOP equipment shall be API monogrammed.

23) A full OEM Certification of the BOP, choke manifold (including chokes), and all related equipment (i.e. closing unit, kill line valves, choke line valves, coflex hoses, etc.) shall be required at contract start-up and contract renewal with a maximum period of 3 years between OEM re-certification.

24) The BOP should be opened, cleaned, and visually inspected after every nipple down, including servicing the manual tie-down screws.

25) Elastomers exposed to well fluids shall be changed at a maximum of every 12 months, unless visual inspection requires changing earlier. However, it is acceptable to use seal elements for 30” annulars up to 36 months (provided inspections are satisfactory, properly documented, and the expiration date of the elastomer is not exceeded). Seal elements for all other annulars (21-3/4” and smaller) shall be replaced no later than every 12 months, as per policy.

26) All BOP stacks and accumulators must have documentation of last inspection and certification.

WELL CONTROL MANUAL



2.0 Testing of Blowout Prevention Equipment

The objective of BOP equipment testing is to eliminate all leaks and to determine that the equipment will perform under unplanned pressure conditions. This is accomplished by verifying:

Ø Specific functions are operationally ready Ø Pressure integrity of installed BOP equipment Ø Compatibility between control system and BOP equipment 2.1 General Pressure Testing Requirements

All BOP equipment pressure tests shall be conducted in accordance with the following guidelines.

1) Rig crews must be alerted when pressure test operations are underway. Only necessary personnel shall remain in the test area.

2) All tests shall be performed using clear water.

3) The low-pressure test of each piece of BOP equipment shall be conducted at a pressure of 300 psi.

4) The high-pressure test is specified in the following sections, by BOP class.

5) The low-pressure test shall be performed first. DO NOT test to the high- pressure and then bleed down to the low pressure. The higher pressure could initiate a seal after the pressure is lowered and thereby misrepresent the low-pressure test.

6) BOP equipment (including blind rams and shear blind rams) shall be pressure tested as follows:

• When installed • Before drilling out each string of casing • Following the disconnection or repair of any wellbore pressure seal in

the wellhead/BOP stack (limited to the affected components only) • Not to exceed 14 days (± 2 days)

7) All valves located downstream of the valve being tested shall be placed in the OPEN position.

8) OPEN casing valves to the atmosphere when using a test plug to test the BOP stack to prevent possible leaks from rupturing the casing.

9) OPEN annular valves when testing to prevent pack-off leaks from pressuring up outer casing strings.

10) Vent the cup tester through the drillpipe when testing the upper 60 feet of casing to prevent possible leaks from rupturing the casing or applying pressure to the open hole.

WELL CONTROL MANUAL



11) Test all valves on the wellhead individually to their rated working pressure on

installation (using a VR plug) and to 80% of casing burst on subsequent pressure tests, with a cup tester at located + 90’.

12) Casing rams shall be tested to the maximum anticipated surface pressure (refer to Section K, 6.0 for specific test pressures), with a joint of casing connected to a test plug with appropriate cross-over.

13) Variable Bore Rams (VBR) shall be tested with all sizes of pipe in use, excluding drill collars and bottom-hole tools.

14) DO NOT close annular preventers on open hole or pipe with ESP cable (or wireline) for pressure tests. Annulars shall only be closed in these situations in an emergency. Annulars shall be tested with the smallest OD pipe to be used.

15) All pressure tests must be held for a minimum duration of ten (10) minutes with no observable pressure decline.

16) Only authorized personnel shall go in the test area to inspect for leaks when the equipment is under pressure.

17) Tightening or repair work shall be done only after pressure has been released and all parties have agreed that there is no possibility of trapped pressure.

18) A pressure test is required after the installation of casing rams or tubing rams. This test is limited to the components affected by the disconnection of the pressure containment seal. The bonnet seals and rams shall be tested using a test joint connected to a test plug, or cup tester, with appropriate crossover.

19) The initial pressure test performed on hydraulic chambers of annular preventers should be at least 1500 psi. Initial pressure tests on hydraulic chambers of rams and hydraulically operated valves should be to the maximum operating pressure recommended by the manufacturer. Test should be run on both the opening and closing chambers. Subsequent pressure tests on hydraulic chambers should be upon re-installation.

20) All pressure tests shall be conducted with a test pump. Avoid the use of rig pumps for pressure testing. Cement units are acceptable.

21) All test results must be documented on a pressure chart, with the following information,

• Date of Test • Well Name • Driller • Toolpusher • Saudi Aramco Representative

21) Test stumps are an acceptable method for pressure testing the BOP stack at the rig site. The bottom connection (and any other connection not tested) must be tested with a test plug upon installation of the BOP stack.

WELL CONTROL MANUAL



2.2 Specific Pressure Testing Requirements for Class ‘A’ 10M BOP Stack

1) The initial high-pressure test of the following equipment shall be conducted upon installation at the rated working pressure of the weakest component:

• Wellhead • Ram-Type Preventers (including fixed PR, VBR, and SBR) • Kill Line and Valves • Emergency Kill Line and Valves • Choke Line and Valves • Choke Manifold

2) Subsequent high-pressure test(s) of the above equipment shall be conducted to a pressure greater than the *maximum anticipated surface shut-in pressure.

Note: For Khuff development wells (Jilh Dolomite casing point) Initial high-pressure test is 10,000 psi (full working pressure) *Subsequent high-pressure test(s) are 8,500 psi

For Pre-Khuff wells (Jilh Dolomite casing point and below) Initial high-pressure test is 10,000 psi (full working pressure) *Subsequent high-pressure test(s) are 10,000 psi

For K1/MK1 wells only (where NU occurs above Jilh Dolomite casing point) Initial high-pressure test is 10,000 psi (full working pressure) *Subsequent high-pressure test(s) are 5,000 psi minimum

3) The high-pressure test (initial and subsequent) of the annular preventer shall be conducted at 70% of the rated working pressure.

4) All pressure tests, excluding casing tests, must be done with a test plug, due to the minimum yield strength (burst rating) of the 13-3/8” 72# and 9-5/8” 53.5# casing. Test plugs must be checked to insure the plug fits the casing head.

5) The initial high-pressure test of the upper/lower kelly cocks, inside BOP, and safety valves shall be conducted to their rated working pressure. Subsequent high-pressure test(s) shall be conducted at the maximum anticipated surface shut-in pressure.

6) Rotary hoses, standpipe, vibrator hoses, and piping to pumps shall all be tested to 5000 psi.

7) The initial pressure test on the closing unit valves, manifold, gauges, and BOP hydraulic lines shall be at the rated working pressure of the closing unit (3,000 psi). Subsequent pressure shall be performed on each well installation at the same pressure or after repairs to the hydraulic circuit.

8) At nipple up, the casing shall be tested to 80% of burst rating.

9) The casing string in use shall be tested with a cup tester to 80% burst rating every 14 days (along with the scheduled BOP test). This will provide a pressure test of the casing valves in addition to verifying casing integrity.

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2) Subsequent high-pressure test(s) of the above equipment shall be conducted to a pressure greater than the maximum anticipated surface shut-in pressure. This test pressure will be determined by the particular application (i.e. formations exposed, fracture gradient or estimated fracture gradient, casing burst rating).

3) The high-pressure test (initial and subsequent) of the annular preventer shall be conducted at 70% of the rated working pressure.

Note: A cup tester may be used if the high-pressure test does not exceed 80% of the casing burst rating.

4) The casing cup tester must be the appropriate size/weight for the application. When using this tester, care must be taken that the total load applied to the drill string (cup area times test pressure, plus the weight of the suspended drill string) does not exceed the string’s tensile limit.

5) The upper/lower kelly cocks, inside BOP, safety valves, rotary hose, standpipe, vibrator hose, and piping to pumps shall be tested to same high-pressure tests (initial and subsequent), as the BOP equipment, but not to exceed their rated working pressure.

6) The initial pressure test on the manifold and BOP hydraulic lines shall be at the rated working pressure of the closing unit (3,000 psi). Subsequent pressure shall be performed on each well installation at the same pressure or after repairs to the hydraulic circuit.


8) The casing string in use shall be tested with a cup tester to 80% burst rating every 14 days (along with the scheduled BOP test). This will provide a pressure test of the casing valves in addition to verifying casing integrity.

Note: BOP equipment may have a higher working pressure than required, due to rig equipment availability. The high-pressure test requirement in these situations shall be site-specific (limited by the WP rating of wellhead).

WELL CONTROL MANUAL






2) Any subsequent high-pressure test(s) of the above equipment shall be conducted at 2500 psi or maximum anticipated surface shut-in pressure (whichever is greater), as determined by the particular application (i.e. formations exposed, fracture gradient or estimated fracture gradient, casing burst rating).

3) The high-pressure test (initial and subsequent) of the annular preventer shall be conducted at 2100 psi (70% of the rated working pressure).



5) Test plugs must be checked to insure the plug fits the casing head.




Note: BOP equipment may have a higher working pressure than required. The high-pressure test requirement in these situations shall be site-specific (limited by the working pressure rating of wellhead).

WELL CONTROL MANUAL



2.5 Specific Pressure Testing Requirements for Class ‘B’ 3M BOP Stack


• Wellhead • Ram-Type Preventers • Kill Line and Valves • Emergency Kill Line and Valves • Choke Line and Valves • Choke Manifold





5) Test plugs must be checked to insure the plug fits the casing head.




Note: BOP equipment may have a higher working pressure than required. The high-pressure test requirement in these situations shall be site-specific (limited by the working pressure rating of wellhead).

WELL CONTROL MANUAL



2.6 Specific Pressure Testing Requirements for Class ‘C’ or ‘II’ 3M BOP Stack

1) The initial high-pressure test of the following equipment shall be conducted upon installation and at the rated working pressure of the weakest member:

• Wellhead

• Double Ram Preventer • Kill Line and Valves • Choke Line and Valves • Choke Manifold








Note: When testing a Class ‘II’ 3M Workover stack on a Power Water Injection well equipped with a ball master valve, the following must be observed:

a) Check the ball valve for leaks with wellhead pressure, from below, prior

to nippling-up the BOP stack. b) Report any observed leak for decision to spot a cement isolation plug. c) Test the blind ram on the ground against a blind flange prior to nippling-up

the BOP stack. This will provide a pressure test on the blind ram without relying on the ball valve, which may leak at higher pressure. The pipe ram and annular can be tested with a cup tester after nippling up.

WELL CONTROL MANUAL



2.7 Specific Pressure Testing Requirements for Class ‘D’ Diverter Stack

1) Activate the ‘close/open sequence’ with drillpipe or test mandrel in the diverter to verify control functions. DO NOT attempt to close the diverter on open hole except in an emergency.

2) Pump water through the diverter system at low pressure and high rates. Examine entire system for leaks, excessive vibration, and proper tie down.

3) The low-pressure test on the diverter shall be conducted upon installation and at 300 psi.

4) The high-pressure test shall be based on 80% rated working pressure of the

weakest component in the diverter system.

5) Function test the diverter daily. 3.0 Pressure Testing Procedure

The recommended pressure testing procedure for a Class ‘A’ 10,000 psi BOP hook-up is given below. This test procedure can be easily amended and made applicable for the other classes of preventer stacks. Although the actual testing sequence may vary somewhat, the ultimate objective must be achieved: To test each individual preventer, valve, and all associated lines in the BOP system from the wellbore direction at a 300 psi low-pressure and then a specified high-pressure. The pressure source is shown down the drillpipe and through a perforated sub or ported test plug (excluding blind ram or casing test); although, a BOP side outlet may be used. The annular and pipe rams are tested individually in this manner. The blind rams are tested after removing the drillpipe and applying pressure through the kill line, between closed rams and test plug.

Note: In the case of the Class ‘A’ 10,000 psi (non-tapered string, where a lower set of blind rams are positioned below the kill line), the test pressure must be applied through the side outlet of the BOP.

In order to test each individual valve on the kill line, choke line, and manifold; proceed after pressure testing the far outside valves, (all other valves open) by opening these valves and closing each inside adjacent valve, pressure testing, and working inward to the stack.

Note: The steps in the following procedure should be performed in numerical sequence. The instructions assume that at the beginning of each step, the equipment is arranged as in the end of the previous step. Therefore, if this particular procedure is not followed in sequence, erroneous test results may be obtained.

WELL CONTROL MANUAL



3.1 Function Testing and Flow Testing

Before applying test pressure to the preventers, perform the following:

1) Close and open all preventers. DO NOT CLOSE pipe rams or annular preventer on open hole.

2) Pump through the kill line, flow line, mud-gas separator, and choke lines with water to make sure none are plugged.

3.2 Fill the Stack with Water

Drain the mud from the BOP stack and fill with clear water.

3.3 Casing Test

A casing test is generally conducted at nipple-up when testing DV or float equipment. In addition, this test is required every 14 days (along with the scheduled BOP test), with the use of a cup tester, to provide a pressure test on casing head valves and verify casing integrity.

To conduct a casing test, perform the following:

1) Connect the pressure source to the kill line and open kill line valves #4 and #5.

Note: VERY IMPORTANT - Monitor valves #1, #2, #3 and #3a for leaks/well flow.

2) Open all valves and chokes on choke manifold. Close valve #7 on choke line.

3) Close outer casing head valves #1 and #3a.

4) Close the blind/shear blind rams (or upper pipe rams, if pipe in the hole).

Shear Blind Rams

Figure K.1 Casing Test

#3a

Shear Blind Rams

WELL CONTROL MANUAL



5) Pump into the well through the kill line monitoring/recording the test pressure at the test pump. For all casing strings other than drive pipe or structural casing, conduct the test to 80% of the minimum internal yield (burst) of the casing.

6) To test inner casing head valves, close valves #2 and #3 and open outer valves #1 and #3a. See Figure K.1.

Note: No manufacturer recommends opening rams, which are holding pressure. Damage to the ram rubbers, ram blocks and ram cavities may occur.

3.4 Shear Blind Ram Test (or Blind Rams for other BOP Stack Configurations)

To pressure test the Shear Blind Ram (or Blind Ram), the following is required:

1) Land test plug in the casing head and remove running tool from the wellbore.

2) Connect the pressure source to the kill line and open kill line valves #4 and #5 (see Figure K.2).

Note: Monitor valves #1, #2, #3 and #3a for well flow.

3) Open all valves and chokes on the choke manifold.

4) Open all casing head valves and close the choke line valve #7.

5) Close the shear blind rams.

Figure K.2 Shear Blind Ram Test

Shear Blind Rams

#3a

WELL CONTROL MANUAL



6) Pump into the well through the kill line. Monitor and record the test pressure at the test pump. Conduct the low-pressure test first at a pressure of 300 psi. Conduct the high-pressure test next at the pressure specified in previous requirements (Section K 2.2 for Class ‘A’ 10M).

Note: This test will also evaluate the choke line HCR valve and thereby eliminate the need for Step 3.11.

3.5 Annular Preventer

Test the annular preventer as follows: 1) Land the test plug and test joint in the casing head.

2) Connect the pressure source to the test joint at the rig floor.

3) Close the kill line HCR (valve #4) and open all other kill line valves (the kill line check valve should be crippled).

4) First, open all choke line and choke manifold valves. Then close the outermost choke manifold valves #15, #16, #17, and #18 (before buffer tank). See Figure K.3.

Figure K.3 Annular Test

Shear Blind Rams

#3a

#19

WELL CONTROL MANUAL



5) Verify that the casing head valves #2 and #3 are open. 6) Close the annular preventer and pump into the well through the test joint.

Conduct the low-pressure test first at a pressure of 300 psi. Conduct the high-pressure test next at a pressure equal to 70% of the rated working pressure of the annular preventer. Verify the accuracy of the gauge installed downstream of choke manifold valve #19 by observing the test pressure.

3.6 Upper Pipe Rams

Without changing the choke manifold or testing arrangement, immediately test the upper pipe rams as follows.

1) Close choke manifold valve #19 (see Figure K.4).

2) Close the upper pipe rams and pump into the well through the test joint. Conduct the low-pressure test first at a pressure of 300 psi. Conduct the high-pressure test next at the pressure specified in previous requirements. Confirm that choke manifold valve #19 is not leaking by observing a zero pressure indication on the downstream gauge.


Figure K.4 Upper Pipe Rams

Shear Blind Rams

#3a

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3.7 Positive-Sealing Choke Test

If the chokes are designed to be positive sealing, test them as described below; otherwise, proceed to Step 3.8. 1) Open outermost choke manifold valves #15, #16, and #18. 2) Close positive-sealing chokes (see Figure K.5).

3) Close the upper pipe rams and pump into the well through the test joint.

Conduct the low-pressure test first at a pressure of 300 psi. Conduct the high-pressure test next at the pressure specified in previous requirements.


Figure K.5 Positive-Sealing Choke Test

Shear Blind Rams

#3a

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3.8 Choke Manifold Valves (continued)

Continue testing the choke manifold valves by performing the following: 1) Open outermost choke manifold valves #15, #16, #17, and #18. 2) Open chokes. 3) Close choke manifold valves #11, #12, and #14 (see Figure K.6). 4) Close the upper pipe rams and pump into the well through the test joint.



Shear Blind Rams

Figure K.6 Choke Manifold Valves

#3a

WELL CONTROL MANUAL




Continue testing the choke manifold valves by performing the following: 1) Open choke manifold valves #11, #12, and #14. 2) Close choke manifold valves #9, #10, and #13 (see Figure K.7). 3) Close the upper pipe rams and pump into the well through the test joint.


Note: Monitor valves #1, #2, #3 and 3a for well flow.


Shear Blind Rams

#3a

WELL CONTROL MANUAL




1) Open choke manifold valves, #9, #10, and #13. 2) Close choke manifold valve #8 (see Figure K.8). 3) Close the upper pipe rams and pump into the well through the test joint.




Shear Blind Rams

#3a

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3.11 Choke Line HCR Valve

Test the choke line HCR valve by performing the following: 1) Open choke manifold valve #8. 2) Close outer choke line HCR (valve #7). See Figure K.9. 3) Close the upper pipe rams and pump into the well through the test joint.



Figure K.9 Choke Line HCR Valve

Shear Blind Rams

#3a

WELL CONTROL MANUAL



3.12 Choke and Kill Line Manual Valves Test the inner choke and kill line valves by performing the following: 1) Open choke line HCR (valve #7). 2) Close choke line manual valve #6. 3) Open kill line HCR (valve #4). 4) Close kill line manual valve #5 (see Figure K.10). 5) Close the upper pipe rams and pump into the well through the test joint.




Figure K.10 Choke and Kill Line Manual Valves

Shear Blind Rams

#3a

WELL CONTROL MANUAL



3.13 Master Pipe Rams Test the master pipe rams by performing the following: 1) Open the upper pipe rams (see Figure K.11). 2) Close the master pipe rams and pump into the well through the test joint.


Note: Monitor valves #1, #2, #3 and 3a for well flow.


#1 #2 #3

Figure K.11 Master Pipe Rams

Shear Blind Rams

#3a #3 #2 #1

WELL CONTROL MANUAL



3.14 Small Pipe Rams Test the small pipe rams by performing the following: 1) Open the master pipe rams (see Figure K.12). 2) Pull the large test joint and test plug. Run a small test joint and plug. 3) Close the small pipe rams and pump into the well through the test joint.




Figure K.12 Small Pipe Rams

Shear Blind Rams

#1 #2 #3 #3a

WELL CONTROL MANUAL



3.15 Kelly, Surface Circulating Equipment, and Safety Valves 1) Pick up kelly and install full-opening safety valve on bottom of lower kelly valve. 2) Using an adaptor, connect to an independent test pump or cement pump.

3) Open appropriate standpipe valves and all kelly valves.

4) Fill the system with water and close standpipe valve to test the standpipe, rotary

hose, swivel, and kelly.

5) Conduct the low-pressure test first at a pressure of 300 psi.

6) Conduct the high-pressure test next at the pressure specified in previous requirements.

7) By alternating closing upstream and opening downstream valves, all the kelly

valves could be tested without pressuring up again, although it may not possible to operate the upper kelly valve under pressure.

8) The inside BOP (float type) can be tested similarly by installing below the full-

opening safety valve and opening all valves through the standpipe.

3.16 Wellhead Valves Test all valves on the wellhead individually to their rated working pressure on installation (using a VR plug) and to 80% of casing burst on subsequent pressure tests, with a cup tester at located + 90’.

WELL CONTROL MANUAL



4.0 Accumulator Tests These tests are for the purpose of determining the operating condition of the accumulator and BOP system. They shall be performed every 14 days, at the same time the BOP equipment is pressure tested, and at any other time deemed necessary by the Saudi Aramco Foreman. The results shall be noted on the Saudi Aramco BOP Pressure Test Report (see Figure K.13, or Form # 2.0 in Section S of this manual). To analyse the performance of the accumulator, the results of each test should be compared with results of several previous tests. Any increase in closure or recharge time indicates an immediate need for a thorough examination of the accumulator system. The accumulator test shall include the following,

• Record the accumulator capacity and useable volume • Record the accumulator pressure • Record the pre-charge pressure and last date checked • Record the closing and opening times for each component

Note: Alternate accumulator bi-weekly tests between the main nitrogen unit (with charging system isolated) and air/electric back-up system (with bottle banks isolated).

Preventer functions should also be operated remotely to insure proper

operation of all functions from the remote stations.

The accumulator test shall also comply Saudi Aramco’s general requirements as follows:

§ Closing time for ram preventers should not exceed 30 seconds. § Closing time for annular preventers (less than 18-3/4”) should not

exceed 30 seconds. § Closing time for annular preventers (18-3/4” and larger) should not

exceed 45 seconds. § The accumulator must have enough stored fluid under pressure to

close all preventers, open the choke hydraulic control gate valve (HCR), and retain 50% of the calculated closing volume with a minimum of 200 psi above pre-charge pressure, without assistance of the accumulator pumps.

§ The accumulator-backup system shall be automatic, supplied by a

power source independent from the power source to the primary accumulator-charging system, and possess sufficient capability to close all blowout components and hold them closed.

WELL CONTROL MANUAL



Figure K.13 Saudi Aramco BOP Pressure Test Form

NOTE: HYDRIL TO BE TESTED @ 70% RATED WORKING PRESSURE WITH PIPE IN HOLE

WELL CONTROL MANUAL



Figure K.13 Saudi Aramco BOP Pressure Test Form

ALTERNATE BI-WEEKLY TESTS WITH

BOTTLE BANKS ISOLATED

CHARGING SYSYTEM ISOLATED

WELL CONTROL MANUAL



5.0 Hang-Off Limitations While Testing

Many times, a portion of the bottom-hole assembly will be hung-off below the test plug while conducting a BOP test. This is done for a variety of reasons including:

• Leaves pipe in the hole to circulate through in case the well kicks. • Shortens the trip time by not having to pull completely out of the hole.

IT MUST BE REMEMBERED however, that hanging-off weight below the test plug reduces the maximum allowable BOP test pressure. Figure K.14 shows the maximum allowable hang-load for a given BOP test pressure for the wellhead manufacturers used by Saudi Aramco. This chart should be reviewed before hanging-off and testing BOP equipment.

6.0 Test Pressure Requirements for Casing Rams

Casing rams (and annular preventer) shall be pressure tested with a test plug and casing joint to the following pressures prior to running casing or liner. The following table lists the specific test pressure for casing rams relative to casing point.

Casing Point Test Pressure Arab-D and Above 500 psi Base Jilh Dolomite 750 psi

Top of Khuff Fm. 1500 psi Khuff-D Anhydrite 1500 psi

Pre-Khuff TD 1500 psi

Figure K.14 Maximum Hanging Load for Different Bowl Sizes and BOP Test Pressures

For Gray, FMC, Cameron, and Wood Group Wellhead Equipment

Maximum Hanging Load (lbs) for Given BOP Test Pressure

Bowl Size

0 psi

1000 psi

2000 psi

3000 psi

4000 psi

5000 psi

6000 psi

7000 psi

8000 psi

9000 psi

10,000 psi

11”

580,000

580,000

580,000

580,000

580,000

580,000

543,000

466,000

389,000

312,000

235,000

13”

580,000

580,000

580,000

580,000

580,000

515,000

388,000

261,000

134,000

7,000

-

20”

580,000

580,000

580,000

580,000

580,000

580,000

-

-

-

-

-

26”

580,000

580,000

580,000

580,000

580,000

580,000

-

-

-

-

-

WELL CONTROL MANUAL

Drilling & Workover October 2002 __ SECTION L – DIVERTING OPERATIONS AND EQUIPMENT

Current Revision: October 2002 L - 1 3rd Edition Previous Revision: October 1998

Table of Contents

Introduction............................................................................................L-2 1.0 Diverting vs. Shutting-In ............................................................L-2 2.0 Diverter Systems.........................................................................L-3

2.1 Annular Preventer ............................................................................ L-4 2.2 Diverter Spool................................................................................... L-4 2.3 Diverter Valves ................................................................................. L-4 2.4 Overboard Lines............................................................................... L-5 2.5 Diverter Control Stations ................................................................. L-5 2.6 Mud-Gas Separator (MGS) ............................................................... L-7 2.7 Kill Mud............................................................................................. L-7 2.8 Pressure Testing the Diverter System............................................. L-8

2.8.1 Upon Initial Nipple-Up............................................................ L-8 2.8.2 While Drilling Ahead under Diverting Conditions..................... L-8

3.0 Diverting Procedure....................................................................L-8 4.0 Considerations while Drilling Surface Hole..............................L-9 5.0 Guidelines for Training of Crews............................................. L-10

WELL CONTROL MANUAL



Introduction The occurrence of shallow gas zones, particularly offshore, can be extremely dangerous and presents some unique well control considerations. Since the gas is shallow, any flow from the formation will reach the surface very quickly. Thus, very little time is available for detecting the kick and either shutting-in the well or diverting the flow. Many wells with shallow casing strings have insufficient integrity at the shoe to withstand the pressures imposed by shutting-in. Closing-in a shallow well with little or no shoe integrity can cause the shoe to breakdown and allow formation fluids to broach back to the surface. A broached shoe can seriously jeopardize a bottom supported rig (i.e. jack-up, platform, land rig) and its crew. For bottom supported rigs and land rigs, diverting is often the only viable alternative to shutting-in when shallow gas kicks are encountered. Diverting is a method of directing the flow from an unloading well in order to minimize physical damage to rig personnel and equipment. Diverting equipment and procedures are designed to impose as little backpressure as possible on the weak downhole formations. Diverting is not a well control procedure, per se, and a successful diverting operation is one that allows the well to bridge over or deplete itself without loss of life or equipment. 1.0 Diverting vs. Shutting-In

In many instances while drilling surface hole, the shoe integrity is insufficient to withstand the increased pressures associated with shutting-in. Therefore, if the well begins to unload, the flow must be directed such that physical damage is minimized and to afford time to allow evacuation and/or remedial action to be taken. It must be stated, however, that if there is a known producible sand, a BOP system or modified BOP system must be installed prior to the penetration of the sand. This would allow some type of proven well control procedures to be taken. To use any type of proven well control procedure, there must be enough formation integrity to allow the well to be shut in and/or backpressure applied such that the well could be killed. Three governing criteria for use of a diverter system as opposed to a BOP stack are:

• Diverter - When there is no zone of known production potential (i.e., any shallow

hydrocarbons which are encountered are expected to deplete rapidly) • Diverter - When there is not enough formation integrity to withstand the pressure of the formation fluids from broaching around a shallow casing string • BOP - When penetrating shallow productive sands (i.e., where the sand is not

expected to deplete rapidly); when drilling adjacent to another well on a platform or at a multiwell location that is capable of producing

WELL CONTROL MANUAL



2.0 Diverter Systems Diverter systems are used as a way to direct an uncontrolled flow from a shallow zone, not as a means to kill the well. To minimize the chance of human error or equipment malfunction, the system must be kept as simple as possible. The system should consist of an annular preventer, drilling (diverter) spool, two divert valves and two overboard lines (as shown in Figure L.1). The only question as to the hook up lies in the position of the diverter spool and annular preventer. The flow should be directed overboard through lines with a minimum of turns, since the greatest amount of erosion will occur at the point the flow changes direction. It has been determined that at flow velocities greater than 50 fps, fluid erosion is the major problem while diverting. In most divert cases; this flow velocity has been exceeded. To minimize the chance of premature failure caused by erosion, the lines must be kept as straight as possible and be targeted at every sharp turn.

Figure L.1 Diverter Hook-up

WELL CONTROL MANUAL



In offshore operations where the annular preventer and diverter spool are placed close to mean sea level with the work deck a considerable distance above, the normal procedure would be to use hose or flexible pipe to connect the overboard lines to the diverter spool. This results in a large distance of the line being unsupported, hanging from the barge which presents a hazard and amplifies the chance of premature failure. To eliminate this, a marine riser, with a pressure rating equal to the conductor pipe, should be utilized. This riser would bring the annular preventer and diverter spool directly to the large diameter, steel overboard lines. Unsupported diverter lines should not be installed. 2.1 Annular Preventer

A 20” 2M bag-type annular preventer should be used when possible because of its field proven dependability. When a larger bore preventer is necessary, it should be replaced with a 20” 2M preventer as soon as possible. The annular preventer must be visually inspected for damage prior to installation. All flange bolts, both top and bottom, must be used.

2.2 Diverter Spool The diverter spool must be of a pressure rating equal to or greater than that of the annular preventer, with two 6” minimum ID side outlets. No adapters or swages should be used to install the divert valves. The spool should be inspected to assure its integrity prior to installation. All bolts must be installed and new ring gaskets used to minimize the possibility of leaks.

2.3 Diverter Valves The diverter valves should be installed immediately adjacent to the diverter spool. This is to compensate for an overboard line failure, since the valve being adjacent to the diverter spool eliminates any chance of problems in piping between the spool and valve. Many valve failures have occurred due to internal rust build-up. You should verify that all diverter valves are in good condition and not rusted so that full opening or full closure is not impeded. Saudi Aramco's recommended guideline is for two 6” ID lines and full opening valves, if there are no more than two turns in the divert lines before going overboard. If there are more than two turns in the lines, 10” lines and valves are recommended. The design of diverter systems should emphasize a uniform internal diameter throughout. Any changes in internal diameter in the system will cause severe erosion problems. In addition, all divert valves should be hydraulically operated. The advantages of hydraulic operation are:

• They are consistent with the control station. • Hydraulic control lines will be less likely to be damaged during

operations because they are high pressure lines and are part of the rig. • A hydraulic actuator can develop a greater force using a smaller

chamber as compared to an air-operated valve. This will result in a more compact valve, which will be easier to handle and install.

WELL CONTROL MANUAL



The one item strongly recommended is that the pressure rating of the valves be consistent with the system. Although the divert valves will not be intended to close in the well, there is a distinct possibility that pressure may be held against a valve. For example, if a well is being diverted overboard through the port side and suddenly plugs up, the starboard valve must be able to hold and operate with this pressure being applied. In some cases, dynamic pressure surges due to a water hammer effect may create pressures in excess of static bottomhole pressures. In a study of divert situations, it was found that the single most common cause of failure in the diverter system was the malfunction of the divert valves. No evidence was found to determine whether a ball valve is more or less reliable than a gate valve but the hydraulic gate valve has been proven in field use for BOP systems. As a result, the selection of a gate valve is preferable whenever possible. Again, all valves should be routinely function tested to insure they are not rusted in position. Certain operations require a booster pump to be installed on the drive pipe close to the water level to reduce lost return problems. If this pump is being used, it must have a remote valve installed adjacent to the drive pipe with a pressure rating consistent with the system. Its operations must be tied into the diverter panel such that it will be closed automatically when the diverter is closed.

2.4 Overboard Lines The overboard lines should be of the same pressure integrity as the rest of the system for the same reason as the divert valves. If a line plugs, it must be able to withstand pressure for the time it takes to open the opposite line. The lines must be installed as straight as possible since changes in flow direction can cause significant erosional problems at the area of change. Most of the offshore rigs in use today have the capabilities of moving the derrick to allow the drilling of another well without moving the rig which could result in moving the overboard lines. If at all possible, hard piping from the divert valves to the overboard lines should be used. In the case where hard piping is not possible, flexible hoses could be used to connect the overboard lines with the divert valves. These flexible lines must be of a pressure rating consistent with the system and have API flanges built in the hose for connecting. A collapsible hose with hose clamps is not adequate. The hoses and overboard lines must be securely anchored to accommodate the severe forces to which they will be subjected.

2.5 Diverter Control Stations The component most often lacking in consistency and definition is the control station that will be used to execute the divert function. Simplicity and reliability of a diverter system demands the control station to be readily accessible and simple in operation, leaving no room for error. The system should operate as a remote station to the main accumulator system. The diverter control station should consist of two levers in a

WELL CONTROL MANUAL



panel that are labeled as to their function. One lever should be used to divert the flow overboard. When this handle is moved to Divert, the 4-way valve on the main accumulator for the annular preventer will shift to the close position, closing the annular preventer. Simultaneously, the 4-way valves on the main accumulator for both port and starboard divert valves will shift to the open position, opening both overboard lines. If at this time the need arises to close the upwind overboard line, the second lever on the control station should be used. This lever, when moved to port, will shift the starboard 4-way valve on the main accumulator to the close position and shift the port four way valve to the open position, if closed, opening the port divert valve. No combination of these handles should allow the well to be shut in. A diverter control station rigged-up this way is shown in Figure L.2. Figure L.2 Diverter Control Panel

WELL CONTROL MANUAL



Two separate diverter control stations are required; one on the rig floor, and the other station at a safe and remote distance from the rig. The diverter control stations will be air operated, supplied by the rig’s continuous air supply. As a safety precaution, the control stations should contain an air reserve bottle with adequate volume to function each operation two times, independent of rig air.

The major advantages of a separate diverter control system are:

• It has the sole function of controlling the divert operation. • It will be a permanent fixture of the rig. • Activation of the system will simply require the air supply to be turned

on. • The chance of human error in diverting a well is eliminated. • The Drilling Foreman will have a complete understanding of how the

system works no matter what rig he is on. • By using the main accumulator system, the stored energy of the system

is utilized. • The control lines from the unit to the component are high-pressure steel

lines that are permanently installed on the rig. • When drilling, each individual component is controlled by using the

handle on the main accumulator. This will allow you to do any remedial work without affecting the operations of the diverter control station.

2.6 Mud-Gas Separator (MGS)

By definition, the diverter system is used to divert the flow away from the rig. The MGS, by design, is an integral part of the rig. Thus, if the flow were directed to the MGS, it would in effect be directed to the rig. As a result, any malfunction in the MGS can and has caused considerable damage and/or loss of life. The inability of the MGS to handle high flow rates can create an extremely hazardous situation. It is recognized that under certain conditions, the availability of a MGS as part of the system could be of use in circulating raw drilling fluid, which is simply gas cut. The primary concern with using the MGS is if the flow rate becomes excessive and is not recognized, the results could be catastrophic. Also, the use of an MGS requires additional valving and controls to the diverter system. As was stated earlier, the diverter system must be kept as simple as possible. Therefore, the mud-gas separator should not be used as part of the diverter system.

2.7 Kill Mud It is the general opinion in our operations that a pit of kill mud could prove to be an asset. In the early stages of a divert situation, the pumping of a weighted mud could balance the formation and kill the well. The weight of the kill mud must be determined by testing the formation below the casing shoe or from a known fracture gradient. If a shallow casing shoe could not support the hydrostatic pressure of the kill weight mud, the entire divert operation would be in vain. Thus, the use of (or avoidance of) kill mud should be addressed in the diverter contingency plan.

WELL CONTROL MANUAL



2.8 Pressure Testing the Diverter System

Diverter systems are required to be pressure tested and function tested on a regular basis. The required tests are described below. 2.8.1 Upon Initial Nipple-Up

• Pressure test the diverter bag, vent lines, spool, and diverter valves to

200 psi. This test may be conducted with a test plug, or in conjunction with the conductor pipe pressure test before drilling out the shoe. Record the test on a test chart and make a written notation of the test in the tour report.

• Function test all equipment and circulate through the overboard lines to

ensure they are free from obstruction. Make a record of the test in the tour report.

Note: Verify that each diverter valve is functioning both fully opened and fully closed. This should be done visually.

2.8.2 While Drilling Ahead under Diverting Conditions

• Pressure test the diverter bag, spool, diverter valves, and vent lines to

200 psi at least once every seven days. This test will require a test plug. Record the test on a test chart and make a written notation of the test in the tour report.

• Function test all equipment (open and close) at least once every 24

hours. Make a written notation of the test in the tour report. 3.0 Diverting Procedure

Upon noticing the first positive indication the well is flowing: 1) Sound the alarm 2) Close the diverter, at which time both divert valves overboard will open automatically 3) Notify the Drilling Foreman and Toolpusher 4) Alert all non-essential personnel to prepare for possible evacuation 5) Shut down the pumps and check for flow through the overboard lines

WELL CONTROL MANUAL



Note: Shutting down the pumps to check for flow may result in greater influx flow rates. Continuous pumping is recommended, especially if there was a positive indicator of flow.

6) If flowing, start pumps at a fast rate (pumping mud from the active system or kill pit).

Note: The pumps should be lined up to switch over to seawater in the event all the mud is pumped away without a kill. If the situation has progressed this far, realize that ECD, the chance of the formation bridging over or depleting the reservoir are the only lines of defence that exist for controlling the divert situation.

7) Station one of the rig floor personnel to monitor the water area around the rig for

possible broaching of the blowout to the surface. 8) Eliminate all sources of ignition.

4.0 Considerations While Drilling Surface Hole

1) A diverter system should be used where there is insufficient formation integrity to

close the well in. A diverter system should not be used if there are known productive sands, which will not readily deplete. In these instances, casing must be set above the sand and blowout preventer stack installed.

2) The diverter system should be made as simple as possible in its hook-up and

operation. 3) The minimum diverter system should consist of an annular preventer, diverter

spool with two outlets of 6” minimum ID, two hydraulic valves with a minimum of 6” ID and two overboard lines with a minimum of 6” ID. All components should be consistent in their pressure rating. The overboard lines must be well anchored and as straight as possible.

4) A diverter valve should be installed on each overboard line. There should be no

additional valves or lines tied into the overboard lines downstream of the diverter valves.

5) A hydraulic valve, with a pressure rating consistent with the system, must be used

when a booster pump is installed. The valve should be hooked up such that it closes when the diverter closes.

6) Diverter systems that require long unsupported sections of pipe to connect the

divert valves with the overboard lines should be eliminated by utilizing marine risers to bring the diverter spool up to the work deck.

WELL CONTROL MANUAL



7) Hoses connecting the overboard lines with the diverter valves are not recommended.

8) Utilize two separate control stations specifically designed to control the diverter

system. These stations should be tied into the existing accumulator system. 9) A mud-gas-separator should not be tied into the diverter system. 10) Several hole volumes of kill mud should be available for emergency pumping. The

weight of the kill mud must not exceed that which would break the formation down. 11) The diverter system should be tested to 200 psi and function tested when installed. 12) A step-by-step procedure for a divert situation should be reviewed by all personnel

involved and posted on the rig floor. Drills on this procedure should be performed until the crews become proficient.

13) Consideration of drilling a pilot hole to casing point as compared to a full gauge hole

on the first pass should be made. A pilot hole will allow for higher values of ECD and should bridge over easier as compared to the full gauge hole.

5.0 Guidelines for Training of Crews

Since a diverting operation is so very critical and also difficult in that everything is happening quickly, special training for everyone in the drilling crew is required. It is the Drilling Foreman’s responsibility to see that the crews are trained and have defined responsibilities during the operation. Several items are listed below which should be included as part of the rig crew's training. 1) Go over each component of the diverter stack explaining its purpose and operation. 2) Explain the control stations (i.e., position and operation of each control valve).

Emphasize that the well is not to be shut in at any time. If manifolding does not provide for simultaneous opening of the hydraulically operated valve and closing of the annular preventer, be sure that it is understood that closing procedure is to:

• Open valves on the drilling spool • Close annular preventer

3) Explain that the pumps are not to be stopped unless so ordered. 4) Assign positions and responsibilities for each crewmember. This should be

determined by the Toolpusher. 5) Establish warning and abandon rig alarms. 6) Establish contingency plan for fluid type and fluid density to be pumped. 7) Establish evacuation procedure.

WELL CONTROL MANUAL

Drilling & Workover October 2002 __ SECTION M – TRAINING AND WELL CONTROL DRILLS

Current Revision: October 2002 M - 1 3rd Edition Previous Revision: October 1998

Table of Contents

Introduction........................................................................................... M-2 1.0 Pit Drills ...................................................................................... M-2

1.1 Equipment ....................................................................................... M-2 1.2 Frequency........................................................................................ M-2 1.3 Procedure ........................................................................................ M-3

2.0 Trip Drills .................................................................................... M-4 2.1 Frequency........................................................................................ M-4 2.2 Procedure ........................................................................................ M-4

3.0 Accumulator Drill ....................................................................... M-5 3.1 Procedure ........................................................................................ M-5

WELL CONTROL MANUAL



Introduction Shutting-in the well quickly to minimize the size of the influx is a major element of successful well control. Drilling crews can only get proficient in this action through training and practice. The Drilling Foreman should ensure that the Contract Toolpusher administers training in the areas of kick detection and shut-in procedures until proficiency is demonstrated. The training must be repetitive and frequent enough so that shutting-in the well becomes automatic whenever a kick is detected. The Drilling Foreman can judge the level of crew shut-in proficiency through the use of pit drills and trip drills. These drills should always be coordinated with the contract toolpusher. Proper drills and training can prevent panic and provide for orderly operation if a kick should occur. The following discussions describe how to conduct the drills and provide a basis for crew evaluation. 1.0 Pit Drills

The pit drill is designed to simulate an actual kick while drilling ahead and is designed as both a teaching and a testing tool. While drilling ahead, it teaches the drilling crews to be alert for positive indicators of a kick and provides practice in the proper Saudi Aramco shut-in procedures. It also defines and reinforces the assigned duties of every member of the drilling crew in well control situations. Pit drills are conducted unannounced so that realism is created and so the crews can be observed under actual operating conditions. Pit drills train the Driller to be constantly aware of the fluid level in the mud pits and the return mud flow, much as the driver of an automobile subconsciously checks his speedometer. This training is expected to prepare the driller to detect a kick at the first surface indication and with a minimum of reservoir fluid influx. He will then be able to take correct preventive action, lessening chances of disaster. Pit drills should be supervised by the Contract Toolpusher and coordinated through the Drilling Foreman.

1.1 Equipment

All equipment required for pit drills is to be installed prior to drilling and kept in good operating condition. A multi-float pit level indicator and flow show device must be available. A pre-arranged horn or siren signal is an essential part of the pit drill. At the signal, each crewmember must go immediately to his assigned post and execute his assigned duties. The Drilling Foreman should note the times required (in minutes) for various aspects of the pit drills and record them on the tour report. The number and times for these drills should be relayed to the office.

1.2 Frequency

One or more pit drills should be conducted each day until the crews become proficient; then at least twice weekly per crew, or more often if deemed advisable by the Drilling Foreman. Pit drills should be held at least one each day on offshore wells, wildcats, and wells where above-normal bottomhole pressure could exist. New drillers should be given special drills and thorough explanation of this practice. It is one of the most important safety measures that can be initiated and followed.

WELL CONTROL MANUAL



Drills are to be conducted during both routine and special operations. Typical times would be while drilling, shut down for equipment repairs, logging, waiting on orders, circulating, the Driller has gone to eat and is replaced by one of his men, the Driller is talking to someone, or any other time there is open hole and blowout preventers installed.

1.3 Procedure

1) The Toolpusher simulates the kick by raising a float in the mud pits or by

raising the arm on the flow show indicator and making a note of the time. The Drilling Foreman should assist in observing the crew and recording completion times.

2) The Driller must detect the kick and sound the alarm. The time of the alarm

should be noted. Upon hearing the alarm, all members of the drilling crew should immediately execute their assigned duties.

3) The Driller should prepare to shut in the well using the approved Saudi

Aramco Shut-in Procedure While Drilling. The Drilling Foreman should be on the rig floor to announce to the driller that the exercise is only a drill and to stop him before he actually closes the blowout preventers. The time should be noted when the driller is prepared to shut in the well.

4) Members of the drilling crew should report back to the rig floor having

completed their assigned duties. These duties may include: Driller Shut in the well (simulated) Record drillpipe pressure and casing pressure Record time Measure pit gain Check choke manifold for valve positioning and leaks Derrickman Weigh sample of mud from suction pit Check volumes of barite, gel, and water on location Floor Hand #1 Check accumulator pressures and pumps Check BOP stack for leaks and proper valve positions Turn on water jets to diesel exhausts Floor Hand #2 Assist Driller on rig floor Floor Hand #3 Assist Derrickman on mud pits

WELL CONTROL MANUAL



2.0 Trip Drills The trip drill is designed to train the drilling crews to recognize and respond to kick indications, which occur while tripping pipe. Like the pit drill, the trip drill is useful for both teaching and testing purposes. The pit drill also proves that essential detection equipment is installed and in good operating condition. The trip drill is supervised by the Contract Toolpusher with the knowledge of the Saudi Aramco Drilling Foreman. All parts of the well control system must be kept hooked up and in good condition, ready for drills.

2.1 Frequency

When a new rig is picked-up, trip drills should be conducted during each trip (both while pulling out and going into the hole) while the bit is up in the casing. When the crew becomes proficient, trip drills should be conducted at least twice weekly per crew, conditions allowing.

2.2 Procedure

1) The Toolpusher simulates the kick by raising a float in the mud pits and

making a note of the time. The Drilling Foreman should assist in observing the crew and recording completion times.




Aramco Shut-in Procedure While Tripping. This will include spacing out and stabbing/closing the full open safety valve. After the safety valve is installed and the Driller is ready to close the preventers, the Drilling Foreman should announce to the Driller that the exercise is only a drill and that it is not necessary to close the preventers. The time should be noted when the driller is prepared to shut-in the well.

4) Members of the drilling crew should proceed with their assigned duties and

report back to the rig floor upon completion. These duties may include: Driller Shut in the well (simulated) Record drillpipe and casing pressure Record time Measure pit gain Check choke manifold for valve positioning and leaks

WELL CONTROL MANUAL



Derrickman Weigh sample of mud from suction pit Check volumes of barite, gel, and water Floor Hand #1 Check accumulator pressures and pumps Check BOP stack for leaks Turn on water jets to diesel exhausts Floor Hand #2 Stab safety valve. Close safety valve Stab inside BOP. Open safety valve Assist Driller on rig floor Floor Hand #3 Assist Derrickman on mud pits

3.0 Accumulator Drill

Accumulator drills are designed to verify that the accumulator/closing system is in good working order and that it is properly sized for the particular blowout preventer stack. Accumulator performance must be proven with an accumulator drill when the blowout preventers are first installed (which verifies proper sizing), and every 14 days thereafter in conjunction with the weekly BOP pressure tests (which checks for hydraulic leaks). Results of the accumulator drill, including closing times of the rams and annular preventer, and initial final accumulator pressures are to be reported on the Blowout Preventer Test and Equipment Checklist. A notation should also be made on the tour report that an accumulator drill was conducted. Accumulator drills must be conducted when the drill pipe is not in open hole, but up in the casing. At least one joint of drillpipe must be in the hole for the pipe rams to close on. The Saudi Aramco Drilling Foreman and Contract Toolpusher should witness all accumulator drills, but the Toolpusher is responsible for the actual supervision of the drill. Use the remote station to close the preventers every other drill.

3.1 Procedure

1) Turn off all accumulator-pressurizing pumps. 2) Record the initial accumulator, manifold, and annular pressures. 3) Close all of the preventers (EXCEPT THE BLIND RAMS). Substitute a re-

opening of a pipe ram to simulate the blind ram closure when applicable. Open the HCR valve.

4) Measure and record the closing times for each preventer with a stopwatch.

WELL CONTROL MANUAL



5) Record the final accumulator, manifold, and annular pressures. 6) To pass the accumulator test, all BOPs must have closed in less than 30

seconds with at least:

• 1500 psi accumulator pressure remaining (for a 3000 psi accumulator)

Note: Equipment that does not meet these requirements either has insufficient capacity, insufficient precharge or needs repair. Closing time for annular preventers 20" and larger should not exceed 45 seconds.

7) Observe the remaining pressure for at least 5 minutes to detect any possible

am piston seal leaks. 8) Re-open the BOP and turn the accumulator pump(s) back on. 9) Record the time required to charge system back up (re-charge time).

WELL CONTROL MANUAL



Table of Contents

Introduction........................................................................................... M-2 1.0 Pit Drills ...................................................................................... M-2

1.1 Equipment ....................................................................................... M-2 1.2 Frequency........................................................................................ M-2 1.3 Procedure ........................................................................................ M-3

2.0 Trip Drills .................................................................................... M-4 2.1 Frequency........................................................................................ M-4 2.2 Procedure ........................................................................................ M-4

3.0 Accumulator Drill ....................................................................... M-5 3.1 Procedure ........................................................................................ M-5

WELL CONTROL MANUAL



Introduction Shutting-in the well quickly to minimize the size of the influx is a major element of successful well control. Drilling crews can only get proficient in this action through training and practice. The Drilling Foreman should ensure that the Contract Toolpusher administers training in the areas of kick detection and shut-in procedures until proficiency is demonstrated. The training must be repetitive and frequent enough so that shutting-in the well becomes automatic whenever a kick is detected. The Drilling Foreman can judge the level of crew shut-in proficiency through the use of pit drills and trip drills. These drills should always be coordinated with the contract toolpusher. Proper drills and training can prevent panic and provide for orderly operation if a kick should occur. The following discussions describe how to conduct the drills and provide a basis for crew evaluation. 1.0 Pit Drills

The pit drill is designed to simulate an actual kick while drilling ahead and is designed as both a teaching and a testing tool. While drilling ahead, it teaches the drilling crews to be alert for positive indicators of a kick and provides practice in the proper Saudi Aramco shut-in procedures. It also defines and reinforces the assigned duties of every member of the drilling crew in well control situations. Pit drills are conducted unannounced so that realism is created and so the crews can be observed under actual operating conditions. Pit drills train the Driller to be constantly aware of the fluid level in the mud pits and the return mud flow, much as the driver of an automobile subconsciously checks his speedometer. This training is expected to prepare the driller to detect a kick at the first surface indication and with a minimum of reservoir fluid influx. He will then be able to take correct preventive action, lessening chances of disaster. Pit drills should be supervised by the Contract Toolpusher and coordinated through the Drilling Foreman.

1.1 Equipment

All equipment required for pit drills is to be installed prior to drilling and kept in good operating condition. A multi-float pit level indicator and flow show device must be available. A pre-arranged horn or siren signal is an essential part of the pit drill. At the signal, each crewmember must go immediately to his assigned post and execute his assigned duties. The Drilling Foreman should note the times required (in minutes) for various aspects of the pit drills and record them on the tour report. The number and times for these drills should be relayed to the office.

1.2 Frequency

One or more pit drills should be conducted each day until the crews become proficient; then at least twice weekly per crew, or more often if deemed advisable by the Drilling Foreman. Pit drills should be held at least one each day on offshore wells, wildcats, and wells where above-normal bottomhole pressure could exist. New drillers should be given special drills and thorough explanation of this practice. It is one of the most important safety measures that can be initiated and followed.

WELL CONTROL MANUAL



Drills are to be conducted during both routine and special operations. Typical times would be while drilling, shut down for equipment repairs, logging, waiting on orders, circulating, the Driller has gone to eat and is replaced by one of his men, the Driller is talking to someone, or any other time there is open hole and blowout preventers installed.

1.3 Procedure

1) The Toolpusher simulates the kick by raising a float in the mud pits or by

raising the arm on the flow show indicator and making a note of the time. The Drilling Foreman should assist in observing the crew and recording completion times.




Aramco Shut-in Procedure While Drilling. The Drilling Foreman should be on the rig floor to announce to the driller that the exercise is only a drill and to stop him before he actually closes the blowout preventers. The time should be noted when the driller is prepared to shut in the well.

4) Members of the drilling crew should report back to the rig floor having

completed their assigned duties. These duties may include: Driller Shut in the well (simulated) Record drillpipe pressure and casing pressure Record time Measure pit gain Check choke manifold for valve positioning and leaks Derrickman Weigh sample of mud from suction pit Check volumes of barite, gel, and water on location Floor Hand #1 Check accumulator pressures and pumps Check BOP stack for leaks and proper valve positions Turn on water jets to diesel exhausts Floor Hand #2 Assist Driller on rig floor Floor Hand #3 Assist Derrickman on mud pits

WELL CONTROL MANUAL



2.0 Trip Drills The trip drill is designed to train the drilling crews to recognize and respond to kick indications, which occur while tripping pipe. Like the pit drill, the trip drill is useful for both teaching and testing purposes. The pit drill also proves that essential detection equipment is installed and in good operating condition. The trip drill is supervised by the Contract Toolpusher with the knowledge of the Saudi Aramco Drilling Foreman. All parts of the well control system must be kept hooked up and in good condition, ready for drills.

2.1 Frequency

When a new rig is picked-up, trip drills should be conducted during each trip (both while pulling out and going into the hole) while the bit is up in the casing. When the crew becomes proficient, trip drills should be conducted at least twice weekly per crew, conditions allowing.

2.2 Procedure

1) The Toolpusher simulates the kick by raising a float in the mud pits and

making a note of the time. The Drilling Foreman should assist in observing the crew and recording completion times.




Aramco Shut-in Procedure While Tripping. This will include spacing out and stabbing/closing the full open safety valve. After the safety valve is installed and the Driller is ready to close the preventers, the Drilling Foreman should announce to the Driller that the exercise is only a drill and that it is not necessary to close the preventers. The time should be noted when the driller is prepared to shut-in the well.

4) Members of the drilling crew should proceed with their assigned duties and

report back to the rig floor upon completion. These duties may include: Driller Shut in the well (simulated) Record drillpipe and casing pressure Record time Measure pit gain Check choke manifold for valve positioning and leaks

WELL CONTROL MANUAL



Derrickman Weigh sample of mud from suction pit Check volumes of barite, gel, and water Floor Hand #1 Check accumulator pressures and pumps Check BOP stack for leaks Turn on water jets to diesel exhausts Floor Hand #2 Stab safety valve. Close safety valve Stab inside BOP. Open safety valve Assist Driller on rig floor Floor Hand #3 Assist Derrickman on mud pits

3.0 Accumulator Drill

Accumulator drills are designed to verify that the accumulator/closing system is in good working order and that it is properly sized for the particular blowout preventer stack. Accumulator performance must be proven with an accumulator drill when the blowout preventers are first installed (which verifies proper sizing), and every 14 days thereafter in conjunction with the weekly BOP pressure tests (which checks for hydraulic leaks). Results of the accumulator drill, including closing times of the rams and annular preventer, and initial final accumulator pressures are to be reported on the Blowout Preventer Test and Equipment Checklist. A notation should also be made on the tour report that an accumulator drill was conducted. Accumulator drills must be conducted when the drill pipe is not in open hole, but up in the casing. At least one joint of drillpipe must be in the hole for the pipe rams to close on. The Saudi Aramco Drilling Foreman and Contract Toolpusher should witness all accumulator drills, but the Toolpusher is responsible for the actual supervision of the drill. Use the remote station to close the preventers every other drill.

3.1 Procedure

1) Turn off all accumulator-pressurizing pumps. 2) Record the initial accumulator, manifold, and annular pressures. 3) Close all of the preventers (EXCEPT THE BLIND RAMS). Substitute a re-

opening of a pipe ram to simulate the blind ram closure when applicable. Open the HCR valve.

4) Measure and record the closing times for each preventer with a stopwatch.

WELL CONTROL MANUAL



5) Record the final accumulator, manifold, and annular pressures. 6) To pass the accumulator test, all BOPs must have closed in less than 30

seconds with at least:

• 1500 psi accumulator pressure remaining (for a 3000 psi accumulator)

Note: Equipment that does not meet these requirements either has insufficient capacity, insufficient precharge or needs repair. Closing time for annular preventers 20" and larger should not exceed 45 seconds.

7) Observe the remaining pressure for at least 5 minutes to detect any possible

am piston seal leaks. 8) Re-open the BOP and turn the accumulator pump(s) back on. 9) Record the time required to charge system back up (re-charge time).

WELL CONTROL MANUAL

Drilling & Workover October 2002 __ SECTION N – HYDROGEN SULFIDE (H2 S) CONSIDERATIONS

Current Revision: October 2002 N - 1 3rd Edition Previous Revision: October 1998

Table of Contents

Introduction............................................................................................N-2 1.0 Fact and Hazards of Hydrogen Sulfide .....................................N-2

1.1 Danger Areas....................................................................................N-2 1.2 Smell .................................................................................................N-2 1.3 Toxicity .............................................................................................N-2 1.4 Human Tolerance .............................................................................N-3 1.5 Flammability .....................................................................................N-3 1.6 Solubility...........................................................................................N-3

2.0 Symptoms, First Aid Response, and Safety Precautions .......N-3 2.1 Symptoms.........................................................................................N-3

2.1.1 Irritation Case ........................................................................N-3 2.1.2 Acute Case............................................................................N-3

2.2 First Aid ............................................................................................N-5 2.3 Safety Precautions...........................................................................N-5

3.0 Equipment, Corrosion and Mud Treatment ..............................N-6 3.1 Equipment ........................................................................................N-6

3.1.1 Ram Type Blowout Preventers...............................................N-6 3.1.2 Annular Preventer..................................................................N-6 3.1.3 Spools and Cross ..................................................................N-6 3.1.4 Gasket Materials....................................................................N-6 3.1.5 Fasteners ..............................................................................N-6 3.1.6 Valves ...................................................................................N-6 3.1.7 Chokes ..................................................................................N-7 3.1.7 Accumulator Units..................................................................N-7 3.1.8 Remote Choke Control Panel.................................................N-7

3.2 Corrosion Reduction and Mud Treatment.......................................N-7 4.0 Supervisory Responsibilities in a H2S Area.............................N-8

4.1 Personnel..........................................................................................N-8 4.1.1 Drilling Manager.....................................................................N-8 4.1.2 Drilling Superintendent...........................................................N-9 4.1.3 Wellsite Supervisor (Drilling Foreman) ..................................N-9 4.1.4 Man-in-Charge.......................................................................N-9

4.2 Overall Planning...............................................................................N-9 5.0 Additional Equipment and Safety Requirements ................... N-10 6.0 Contingency Plan...................................................................... N-11

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Introduction Drilling into areas where formations contain, or are suspected to contain, hydrogen sulfide requires that additional precautions to be taken to insure the safety of personnel and equipment. As this gas is extremely dangerous, all personnel associated with such operations must be thoroughly indoctrinated in the hazards of hydrogen sulfide. The degree of danger depends upon the concentration in the air breathed. It must be remembered that changes in atmospheric conditions, wind, gas composition, etc., can quickly increase the H2S concentration. Poor ventilation in enclosed spaces around or near a drilling rig where H2S is present can cause a dangerous concentration of H2S to occur. The American Petroleum Institute (API) defines H2S wells as those wells capable of producing atmospheric concentrations of 20 parts per million (ppm) or greater. 1.0 Facts and Hazards of Hydrogen Sulfide

1.1 Danger Areas

H2S is heavier than air and on still days tends to accumulate in low places. However, if it is sufficiently warmer than the surrounding air, H2S will rise. Thus, even personnel working in high places (such as the Derrickman), should do so with caution when there is a possibility of H2S.

1.2 Smell

H2S, in very small concentrations, smells like rotten eggs, but after one sniff in a sufficiently high concentration the sense of smell is reduced. After 2-15 minutes exposure of 100-150 ppm concentration, H2S can no longer be detected by smell. On occasion, this has caused men to die even though they were in a safe area.

1.3 Toxicity

The maximum allowable concentration of H2S for an eight-hour period is 20 ppm or 0.002% by volume. At 500-700 ppm, a person will lose consciousness and death could occur in one-half to one hour. At 1000 ppm concentration, unconsciousness occurs immediately, breathing stops and death occurs within minutes. As stated earlier, H2S is almost as poisonous as hydrogen cyanide and 5 to 6 times more dangerous than carbon monoxide.

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1.4 Human Tolerance A resistance to H2S cannot be developed by working around it, but the effect is also not cumulative. A person revived after breathing even a high concentration may not be permanently injured.

1.5 Flammability

H2S is a colorless, flammable gas; its explosive limits (percent by volume in air) are wide, 4.3% to 45.5%. In contrast, the explosive limits for natural gas range only from 4.8% to 13.5%.

1.6 Solubility

H2S is highly soluble in water and hydrocarbons such as gasoline, kerosene, and crude oil. At atmospheric pressure, water will absorb approximately three times its own volume of H2S.

2.0 Symptoms, First Aid Response, and Safety Precautions

2.1 Symptoms

2.1.1 Irritation Case Exposure to low concentrations (50 to 100 ppm) of H2S will cause coughing, eye irritation, and loss of sense of smell after 2 to 15 minutes; altered respiration, pain in the eyes and drowsiness after 15 to 30 minutes; and throat irritation after 1 hour. With prolonged exposure these symptoms gradually increase in severity, and death occurs in 8 to 48 hours.

2.1.2 Acute Case

Breathing of H2S concentrations of 500 to 1000 ppm or higher will cause almost immediate loss of consciousness. Breathing will become hard; cramps, paralysis, and loss of color are other effects. Table N.1 lists the symptoms of H2S poisoning relative to time of exposure.

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Table N.1 Toxicity of Hydrogen Sulfide to Humans H2S Concentration

0 – 2 Minutes

2 – 15 Minutes

15 – 30 Minutes

30 – 60 Minutes

50 – 100 ppm Mild conjunctivitis; respiratory tract irritation

100 – 150 ppm

Coughing; Irritation of eyes; loss of sense of smell

Disturbed respiration; pain in eyes; sleepiness

Throat irritation

150 – 250 ppm Loss of sense of smell

Throat and eye irritation

Throat and eye irritation

250 – 350 ppm Irritation of eyes; loss of sense of smell

Irritation of eyes Painful secretion of tears; weariness

350 – 450 ppm Irritation of eyes; loss of sense of smell

Difficult respiration; coughing; irritation of eyes

Increased irritation of eyes and nasal tract; pain in head; weariness

500 – 600 ppm Coughing; collapse and unconsciousness

Respiratory disturbances; irritation of eyes; collapse

Serious eye irritation; light shy palpitation of heart; a few cases of death

Severe pain in eyes and head; dizziness; trembling of extremities; great weakness and death

600 – 1500 ppm Collapse; unconsciousness and death

Collapse; unconsciousness and death

H2S Concentration 1 – 4 Hours 4 – 8 Hours 8 – 48 Hours

50 – 100 ppm

100 – 150 ppm

Salivation and mucous discharge; sharp pain in eyes; coughing

Increased symptoms

Hemorrhage and Death

150 – 250 ppm Difficulty breathing; blurred vision; light shy

Serious irritation effect


250 – 350 ppm

Light shy; pain in eyes; difficulty breathing; conjunctivitis


350 – 450 ppm

Dizziness; weakness; increased irritation; death

Death

500 – 600 ppm Death 600 – 1500 ppm Death Data secured from experiences on dogs, which have susceptibility similar to humans. Source: United States National Safety Council Data Sheet D-chem. 16

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2.2 First Aid

1) Remove victim from contaminated area into fresh air as soon as possible. 2) If breathing has stopped, start artificial respiration immediately. 3) Keep victim warm and at rest. 4) Get victim to doctor, but continue artificial respiration enroute if breathing stops. 5) If oxygen resuscitator if available, use it in lieu of artificial respiration, as

concentrated oxygen will more quickly oxidize H2S into the blood; however, begin with artificial respiration rather than wait for resuscitator.

6) For conjunctivitis (irritation of eyes), wash eyes with 1% boric acid solution,

followed by 10% Argyrol drops. Ophthalmic boric acid ointment will also give some relief.

2.3 Safety Precautions

1) Keep upwind of H2S source. 2) Keep proper air breathing apparatus on location, and school all personnel in

its operation and maintenance. H2S drills should begin prior to drilling into formations containing or possibly containing H2S, so all persons will react immediately at warning signal.

3) Have adequate H2S detection devices in key areas around drilling rig, with

responsibilities for monitoring them clearly defined. 4) Train all personnel in artificial respiration and other first aid techniques

pertaining to treating H2S poisoning. 5) Restrict drilling locations to only those persons necessary to operations.

Provide adequate warning signs at all access points around the rig.

6) Install blower fans in main areas to dissipate H2S. Keep ammonia available to neutralize contaminated areas.

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3.0 Equipment, Corrosion and Mud Treatment

3.1 Equipment

3.1.1 Ram Type Blowout Preventers The ram bodies must be heat treated and certified for H2S service by the manufacturer. The following parts must be new parts and certified for H2S service:

• Bonnet Seals (2) • Connecting Rod Seals (2) • Connecting Rod (heat treated) • Ram Packer • Ram Rear Seal

3.1.2 Annular Preventer

The body must be heat treated and certified for H2S service by the manufacturer. The rubber element can be natural rubber or Buna N; both are suitable for H2S service. The upper and lower piston and piston head seals should be new when the preventer is installed.

3.1.3 Spools and Cross The spools and crosses must be flanged, low carbon steel types certified for H2S service, with a maximum Rockwell hardness of Rc22.

3.1.4 Gasket Materials

New connected 316 stainless steel ring gaskets (API RX or BX) must be used.

3.1.5 Fasteners

Bolts are to be new, continuous thread steel with American Society for Testing Materials (ASTM) A-194 Class 2H heavy nuts. Bolting should be ASTM A-193 B-7, drawn at 1275 °F to 1325 °F to produce hardness between Rockwell Rc 25, yield strength of 80,000 psi, and a tensile strength of 100,000 psi.

3.1.6 Valves Materials for valves in sour gas (H2S) service must conform to the United States National Association of Corrosion Engineers (NACE) Standard MR-01-75 (1999 Revision). All valves must be certified for H2S service by the manufacturer and be flanged.

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3.1.7 Chokes Chokes must also conform to the general specifications in NACE Standard MR-01-75 (1999 Revision) and be flanged.

3.1.7 Accumulator Units Accumulators should be located in a safe place easily accessible to rig personnel in an emergency. When the accumulator is not permanently fixed, it should be located a safe distance upwind from the rig in the direction of the prevailing wind. Each location should be equipped with a sufficient number of remote control panels so that the BOP can be controlled from a position upwind of the prevailing wind.

3.1.8 Remote Choke Control Panel A remote choke control panel to operate the choke manifold should be set a safe distance up wind from the rig in the direction of the prevailing wind.

3.2 Corrosion Reductions and Mud Treatment

The most dramatic type of H2S corrosion is brittle failure of steel. H2S also results in a normal acid type generalized and pitting corrosion. Sources of H2S include formation water, make up water, sour crude or gas, electro-chemical reactions, degradation of sulfur-containing organic compounds, and bacterial activity.

1) The most important effects of H2S on the mechanical behavior of steel are:

• a reduction in ductility • a lowering of the fracture stress • a susceptibility to delayed brittle fracture

These effects are due to the reaction of hydrogen sulfide with steel, which produces atomic hydrogen. The hydrogen atom, smaller than the lattice structure of steel, can migrate into steel in a fashion similar to fine sand passing through a coarse sieve. When two hydrogen atoms come together within the steel lattice, a hydrogen molecule is formed, causing a 20:1 expansion. Pressure created by the expansion, added to the stress already present, can cause a brittle material to fail. Thus, higher strength steels, which exhibit brittleness, are much more susceptible to hydrogen embrittlement than are lower strength steels. 2) Tests on hydrogen-charged specimens show that:

• Steel can lose more than 90% of its ability to withstand a sustained tensile load.

• Embrittlement failure of high-strength material occurs at lower stress levels than for lower strength material. Tubular materials above

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approximately 95,000 psi strength are not recommended for H2S service.

• There is little effect on 75,000 psi or lower yield strength steel (Rc22). • Stress accelerates embrittlement failure. As corrosion inhibition

programs are expensive, they should not be undertaken unless experience has shown them to be needed. When a known or suspected H2S zone is to be penetrated, minimum protection should be a filming amine inhibitor added to the mud and applied directly to the drill pipe, inside and out. Other steps (but not all) can be taken to reduce or monitor corrosion during drilling operations, as listed below:

– Maintain the pH at 10.0 or higher (particularly with oil base and invert-emulsion muds, which have the built-in corrosion inhibition of alkaline water).

– Do not use anionic inhibitors such as chromates. – Use oxygen scavengers and bactericides only in relatively

constant volume systems (due to high cost). – Use weight loss coupons to monitor the corrosion rate and

inhibitor effectiveness, if operations are to be prolonged in a corrosive environment.

Keeping the hydrostatic pressure of the mud above the formation pressure is very important in H2S bearing formations. Between trips, drill pipe used in H2S areas should be sprayed or otherwise treated with amine inhibitor. This should also be done weekly to the outsides of the BOP stack, wellhead and choke manifold. The method and products for H2S inhibitors are varied, depending on the mud system and operating conditions. Each condition should be checked with a corrosion engineer or the product’s representative.

4.0 Supervisory Responsibilities in a H2S Area

Since H2S can be lethal, a clear-cut assignment of responsibilities is extremely important so that each man on the drilling location knows exactly what to do in an emergency. This means setting up detailed contingency plans and training programs for safety.

4.1 Personnel

The responsibilities listed below are in addition to the normal duties of the position, and cover only the requirements for safety in H2S areas. 4.1.1 Drilling Manager

The Drilling Manager has the overall responsibility for operations; approves the final drilling program, and contingency plan; and must be sure that the necessary precautions have been taken and that an emergency involving H2S will bring forth maximum response.

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4.1.2 Drilling Superintendent

The Drilling Superintendent prepares, or has prepared, a detailed drilling program, a safety program, and contingency plans for all personnel at the wellsite and surrounding residents. He closely follows the drilling operations and makes sure that all necessary precautions have been taken. Whenever possible, he makes an onsite inspection of equipment and training efforts.

4.1.3 Wellsite Supervisor (Drilling Foreman)

The Wellsite Supervisor does onsite supervision of BOP equipment, as well as its installation and testing, plus training of rigsite personnel in BOP drills and safety. He checks to be sure that all equipment has been certified for H2S service; that safety equipment, such as self-contained breathing apparatus, is available for all personnel on location (plus extra for visitors); and that corrosion inhibitors, blower fans, and all other items required for maximum safety of the drilling operation are available. He must be thoroughly familiar with the contingency plan for evacuating surrounding areas, and should assure himself that Contract Toolpushers, Drillers, and crews know their responsibilities in emergencies.

4.1.4 Man-in-Charge

The ranking Drilling and Workover man on location is the man-in-charge. This designation is essential to the proper execution of a contingency plan. He is in charge of and responsible for implementing emergency procedures. The Wellsite Supervisor will fill this job unless one of his supervisors is on location.

4.2 Overall Planning

Proper well planning in H2S areas includes the same information requirements as for normal wells plus additional precautionary plans and equipment details that must be completed prior to drilling. These special items include all area and geological information; detailed plans for special equipment installation, inspection, and testing; and safety procedures. These items should be in the contingency plan attached to the drilling program, and be understood by all concerned with the actual drilling operations. Specifications for equipment should be stated in the original bid requests to contractors, since the BOP equipment must be certified for H2S service prior to spudding the well.

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5.0 Additional Equipment and Safety Requirements In addition to the requirements set forth in 4.0 of this section, the following points should be considered:

1) Tubular goods that could possibly be exposed to H2S (surface and protective casing)

should be inspected and their hardness limited to Rc24 or less. Mill tests and records may be acceptable, if available, in lieu of inspection in the pipe yard.

2) Drill string components should be limited to maximum yield strength of 95,000 psi.

This will avoid catastrophic failure due to hydrogen embrittlement should the drilling mud be contaminated with H2S.

3) Corrosion inhibitors for drill pipe protection (i.e., filming amines) should be on

location and applied before an H2S zone is penetrated.

4) Drillpipe, safety valves, and all downhole tools should be certified for H2S service.

5) Two flare lines, manifolded to the choke manifold degasser and the mud gas separator, should be installed on opposite sides of the well, perpendicular from the well to the prevailing winds.

6) Flare stacks should have Liquid Petroleum Gas (LPG) piped to them and be

furnished with automatic igniters. In addition, a flare gun or rifle with tracer ammunition should be on location as a backup ignition source.

7) Flare and other lines subject to corrosion by H2S may be susceptible to some sulfide

stress cracking, if the steel contains residual stresses. Yield strength of steel used should be limited to approximately 95,000 psi maximum and/or a hardness of Rc22. Also, working stresses should be limited to 80 percent of the yield strength.

8) All welds and heat affected zones should be stress relieved and their hardness

limited to Rc22. The use of drill pipe for lines subject to H2S service is not recommended.

9) NACE, API, and ASTM specifications are guides for acceptable materials.

10) Breathing air supply stations, resuscitators, and SCBA units should be located

strategically, one of the latter assigned to each man on location.

11) H2S alarms will be set at 10 ppm (visual warning) and 20 ppm (audio alarm). Mask up and emergency evacuation will occur at the sound of the 10 ppm alarm. Further instructions will be provided in the H2S Contingency Plan.

12) All personnel should have earplugs, or have their drums checked for puncture by a

doctor.

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6.0 Contingency Plan A contingency plan and an evacuation plan should be prepared for each well capable of producing an atmospheric concentration of H2S in excess of 20 ppm. Copies of the plans should be maintained at the rig site and posted so that it is available to all personnel. These plans should, at a minimum, include:

1) Responsibilities of personnel, including the man-in-charge, and should define

essential and non-essential personnel;

2) Location of residences, businesses, parks, schools, mosques, roads, medical facilities, etc. in a one mile radius from the well; a larger radius may be required depending on well conditions, terrain, atmospheric conditions and concentrations of H2S;

3) Emergency telephone numbers, including emergency services (ambulance, hospital,

doctor, helicopter, etc.), government agencies, operator and contractor personnel, and service companies;

4) Emergency and warning procedures;

5) Safety equipment and supplies;

6) Training of personnel. Additional information on H2S Contingency Plans is provided in the Drilling Manual (Chapter 8C).

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Drilling & Workover October 2002 __ SECTION O – STRIPPING AND SNUBBING

Current Revision: October 2002 O - 1 3rd Edition Previous Revision: October 1998

Table of Contents

Introduction........................................................................................... O-2 1.0 Forces Involved.......................................................................... O-3

1.1 Downward Force ............................................................................. O-3 1.2 Upward Force .................................................................................. O-3 1.3 Frictional Force ............................................................................... O-3

2.0 Stripping ..................................................................................... O-4 2.1 Preparing to Strip............................................................................ O-4

2.1.1 Float Installed ....................................................................... O-4 2.1.2 Float Not Installed or Leaking................................................ O-4

2.2 Stripping through Annular Preventers........................................... O-4 2.3 Stripping through Ram Preventers................................................. O-5 2.4 Stripping Considerations................................................................ O-5 2.5 Annulus Pressure Control while Stripping .................................... O-5 2.6 Penetrating the Bubble ................................................................... O-9

3.0 Snubbing ...................................................................................O-12 3.1 Equipment ......................................................................................O-12

3.1.1 Conventional Units...............................................................O-12 3.1.2 Hydraulic Units ....................................................................O-13 3.1.3 Auxiliary Equipment .............................................................O-13

3.2 Annulus Pressure Control .............................................................O-14 3.3 Special Considerations..................................................................O-14

3.3.1 Safety..................................................................................O-14 3.3.2 Equipment Layout................................................................O-15

4.0 Lubricate and Bleed..................................................................O-16 5.0 Bullheading ...............................................................................O-16 6.0 Stripping Example Problem .....................................................O-17

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Introduction One of the most serious well control problems to be faced by the rig supervisor is to be off bottom with a gas kick in the wellbore. Due to the migration of this lighter density fluid, a plan of action must be implemented promptly and safely. Because each situation has its own peculiarities, no standard set of procedures can be applied in every case. However, the well-trained Drilling Foreman has several different techniques at his disposal. These options include:

• Volumetric Control • Stripping to Bottom • Stripping Using Volumetric Control • Snubbing to Bottom • Circulating Off Bottom through Choke • Lubricate and Bleed • Bullheading

Prior to choosing any of these options, many factors should be considered. Some of the more obvious ones include:

• How Far off Bottom is the Pipe • Current Mud Weight • Density of the Kick • Well Depth • Rate of Migration • Pressure Limitation on Casing Shoe • Potential for Stuck Pipe • Rig Crew Capabilities • Proper Equipment for Operation

And, of course, one of the most obvious questions is...

“Do I fully understand the operation I want to perform?” For many years the issue of - WHAT TO DO? - has been debated among drilling personnel in offices, in classrooms and in the field. Many times the problem at hand has several possible answers and many times it seems that there is no good answer to the problem at all. Two facts remain constant, however, no matter how severe the situation seems. First, the deeper the pipe in the wellbore, the more options become available and the better the chance for success. Secondly, time is of the utmost importance and must be efficiently used for accurate decision-making. Therefore, the Drilling Foreman must be prepared to assess the situation and respond accordingly. Stripping and snubbing are specialized operations used to trip tubulars into or out of a pressurized wellbore through the blowout preventers. The objective of these operations is to return the pipe to bottom where the hole can be circulated to remove the influx from the wellbore and provide sufficient hydrostatic pressure necessary to kill the well.

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1.0 Forces Involved

To adequately discuss stripping and snubbing, one must become familiar with the forces involved. As can be seen in Figure O.1, three main forces act on the tubulars during the operations.

1.1 Downward Force (Wb)

The downward force (Wb) is the most obvious and may be simply stated as the buoyed weight of the tubulars:

Equation O.1

Wb = Wair (489 – MWpcf) 489 Wb = Buoyed Weight (lbs) Wair = Air Weight of the Tubulars (lbs) MW = Mud Weight (pcf)

1.2 Upward Force (Fp)

The upward force on the tubulars (Fp) may be simplified as the net force exhibited by the well pressure on the cross-sectional area of the tubular in the blowout preventer, and is represented by:

Equation O.2

Fp = P (π xOD2)

4

P = Shut-in Well Pressure (psi) OD = OD of the Pipe in the BOP (in)

1.3 Frictional Force (Ff)

The third force involved is the frictional force (Ff) due to the movement of the tubular through the blowout preventer that is closed on the pipe. This force acts in the direction opposite to the direction of the pipe movement, impeding that movement. The frictional force is difficult to measure since it is a function of the closing pressure of the BOP, the type of rubber used in the preventer, the fluid used for lubrication

Figure O.1 Stripping/Snubbing Forces

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and the steel pipe roughness. This force has generally been estimated at between zero and twenty thousand pounds. However, in practice it has been customary to slack off the pipe and observe the value on the weight indicator.

2.0 Stripping

If the pipe is off bottom when a kick is taken, stripping back to bottom may be required. Stripping through BOP equipment can be accomplished by using either the annular preventers or the ram preventers. Utilizing the ram preventers requires two preventers. Saudi Aramco’s stack configurations are not designed for stripping through the ram preventers. Although it can be done, it requires using the lower ram preventer, which is the master ram of the preventer stack. Stripping through the ram preventer can easily damage the pressure seal of the ram. If the lower ram is damaged, repair work can only be performed after the well is killed. We will discuss the process of stripping through rams; however, it is not recommended as standard practice, unless a ram other than the lower is used.

If the upward force (Fp) generated by the well pressure acting on the cross-sectional area

of the pipe is greater than the weight of the drill string (Wb), it is necessary to force the pipe through the preventer. This process is called snubbing. Annular pressure control theory for snubbing operations is the same as for stripping operations.

2.1 Preparing to Strip

Assuming that the reason the pipe was off bottom was that it was being tripped, the shut-in procedure resulted in installation and closure of a full opening safety valve on the drill pipe. Therefore, if the decision is made to strip, then the following preparatory procedure is used: 2.1.1 Float Installed

1) Open safety valve and insure that the float is holding.

2) Remove the safety valve if float is holding. Once the full open safety valve goes below the rotary, it no longer functions as a safety valve and becomes an unnecessary sub.

2.1.2 Float Not Installed or Leaking

1) Install inside BOP on top of full open safety valve.

2) Open full open safety valve and check inside BOP. Leave safety valve open.

2.2 Stripping through Annular Preventers

Annular preventers are so constructed to allow drill pipe to be stripped through them and maintain a pressure seal around the pipe. To prevent premature damage to the rubber sealing while stripping, the closing hydraulic force should be reduced to a

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minimum. This minimum is reached when the bag just starts leaking a slight amount of mud while will aid in lubrication. This may be hard to monitor unless all the fluid above the closed annular is drained or removed. While stripping the tool joint through the preventer, the pressure regulator should automatically adjust the closing pressure allowing the tool to go through without undue force. The annular preventer 4-way valve should be inspected to insure that it does not contain a check valve.

2.3 Stripping through Ram Preventers

Stripping through ram preventers requires the use of two preventers. Also it is necessary to have a drilling cross with outlets between the preventers. The drilling cross with outlets is required to allow room between the rams for tool joints and to provide a means to equalize pressure across the rams. As the pipe is stripped through one set of rams the other set is opened. When a tooljoint reaches the closed rams, the other set must be closed and pressure equalized across the first set (then opened allowing the tool joint to pass). This process is repeated alternating stripping thorough one ram then the other until the pipe reaches bottom.

2.4 Stripping Considerations

If it is necessary to strip in or out of the hole, it will be necessary to have accurate pressure gauges, which read in the desired range. It may be advisable to order out a new packing element for the annular preventer. Extra safety valves and inside blowout preventers should be available. All drill pipe protectors should be removed. A method to fill the drillpipe and to monitor volumes of mud is essential. A snubbing unit will be required if the pipe is out of the hole. All personnel should thoroughly understand their assignments.

2.5 Annulus Pressure Control while Stripping

The primary idea used in stripping is knowing how much and how fast to bleed mud from the well during the procedure. In order to minimize the size of the influx, the Drilling Foreman should have a full understanding of the basic principals of bubble migration and pipe displacement. The first thing that must be determined is if the kick is migrating up the hole or not. This is vital in the decision making process as it will, along with other factors, dictate whether or not the technique of volumetric control is used during the stripping operation. This is easily determined by observing the shut-in casing pressure. If, after the wellbore has stabilized, the casing pressure starts to increase it is safe to say that the kick is migrating up the hole. Should the casing pressure remain constant (and is below the pressure needed to fracture the formation at the weak point in the hole), it is an indication that the kick is migrating very slowly or not at all. Once it is decided that migration is or is not a major factor, calculations can be made and action can be taken to begin stripping in the hole. In the event that the kick is not

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migrating up the hole matters are simplified a great deal. As pipe is lowered into the well the amount of mud to be bled is simply:

Equation O.3

Volume Bled = Pipe Capacity + Pipe Displacement

This is easily accomplished by maintaining a constant casing pressure during stripping. Alternatively, if pressures allow, a length of pipe can be run and then the volume of mud is bled. In either case it is very important that the mud volume be accurately measured.

While stripping in the hole, it is necessary to control the well to prevent a pressure increase due to displacement of mud by the drill pipe and to allow for expansion of the gas influx. This is down by bleeding off a calculated volume of mud from the annulus. The following example shows how this can be accomplished: Assume, in this example that the bit is off bottom and the influx is below the bit. The influx volume is 20 barrels; the mud weight is 75 pcf. The drill string contains a float so the drill pipe pressure cannot be read directly on a continual basis. The hole size is 9-7/8” and the drill pipe is 5” OD. The original shut-in drill pipe pressure and the shut-in casing pressure are determined to be 520 psi. They are the same because the influx is below the bit and the hydrostatic head in the drill pipe is equal to the hydrostatic head in the annulus. The influx cannot be circulated out until the drill pipe is stripped back to bottom or until the bit is below the influx. The procedure to follow in string the pipe into the hole and in controlling the well is listed in the following steps:

1) Start stripping pipe into the hole.

2) Bleed off a mud volume equal to the drill pipe displacement without allowing casing pressure to drop. This volume is the capacity of the pipe plus the displacement of the steel in the pipe. The volume bled for a 93’ stand of 5” drill pipe is:

Volume Bled = Capacity + Displacement = (93’ x 0.0178) + 0.711 = 1.66 + 0.711 = 2.4 bbls.

3) If the influx is gas the casing pressure will increase, even though mud is released to allow for the pipe displacement. This increase is due to gas migration and must be handled by the volumetric control method. Permit the casing pessure to increase approximately 200 psi. This is a safety factor to assure the BHP stays above the formation pressure.

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We will use an arbitary safety factor of 180 psi in this example: Casing Pressure = 520 + 180 = 700 psi

Note: It is possible to let the casing pressure rise simply by not bleeding off mud to allow for pipe displacement. When casing pressure reaches 700 psi, then bleeding can begin following the steps below.

4) Keep an accurate record of mud released. Maintain casing pressure at

700 psi while compensating for pipe displacement and bubble expansions. Nine (9) barrels of mud represents and expansion of 96’ for the gas in the open hole (below the bit) and is equivalent to 50 psi. Now let the casing pressure increase another 50 psi and continue this procedure until the top of the expanded gas column is reached.

It is important to note that the gas is in the open hole and not in the 9-7/8” x 5” annulus; therefore, the capacity factor for the expansion increment is the open hole capacity factor, not the annulus capacity factor.

5) When the bit enters the top of the gas column the hydrostatic head in

the annulus will be reduced because the bubble will increase in height. This will cause a rapid increase in casing pressure. This increase must be allowed in order to maintain constant BHP. In this example it is assumed that the bubble was allowed to expand in two 50 psi increments. This gives the bubble a height in the open hole of 402 ft:

Height of Gas = Volume / Cap. Factor = (20 + 9 + 9) / 0.0945 = 402 ft.

The casing pressure at this point is 800 psi. Casing Pressure = 700 + 50 + 50 = 800 psi

The pipe volume, assuming 300’ of 7” collars, will expand the bubble to a height of 641 feet. Annular Capacity (opposite collars) = 0.0471 bbl x 300’ = 14 bbl Amount of Gas

(opposite drill pipe) = 38 bbl - 14 bbl = 24 bbl

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Height of Gas = 300 ft + 24 bbl/0.0704 bbl/ft = 300 + 340.91 = 641 ft This corresponds to a decrease in hydrostatic pressure of 96 psi. Increase in Height of Gas = 641 ft - 402 ft = 239 ft

Decrease in HP = 239 ft x (mud gradient-gas gradient) = 239 x (0.53 - 0.12) = 96 psi

To compensate for this decrease in HP the casing pressure must be followed to increase 96 psi to 896 psi without bleeding off any mud in excess of the pipe volume.

6) Continue stripping in hole and bleeding off mud to allow for the pipe

volume.

7) Compensate for gas migration by allowing expansion. Remember that the gas is now in the annulus and a 50 psi pressure increment corresponds to 6-3/4 bbls of mud.

Once the gas is above the bit, it can be circulated out using the Driller’s method before stripping is continued. This would be for the person in charge of the operation to decide upon. The above example can be tabulated as shown in Table O.1.

Table O.1

Cumulative Stands Stripped

Cumulative Volume Displaced (bbls)

Cumulative Volume Bled (bbls)

Casing Pressure (psi)

1 2.4 3.0 700 2 4.8 5.2 700 - - - - - - - - - - - - - - - - - - - -

15 36.0 45.0 700

WELL CONTROL MANUAL



After 15 stands, the difference in volume bled (to maintain 700 psi casing pressure) and theoretical volume displaced is 9 barrels, or 50 psi. Therefore, let the casing pressure rise to 750 psi to compensate for the lost hydrostatic pressure, and then continue with the bleed-offs.

Table O.1 (continued)

Cumulative Stands Stripped




16 38.4 - 710 17 40.8 - 720 18 43.2 - 730 19 45.6 - 740 20 48.0 - 750 21 50.4 50.0 750 - - - - - - - - - - - - - - - - - - - -

30 72.0 81.0 750 2.6 Penetrating the Bubble

During the course of taking a kick while the pipe is off bottom several questions arise. Questions such as depth of the kick zone and location of the kick in relation to the bit need to be considered. Many times quite a few stands of pipe are pulled before the kick is detected and the kick will be below the bit. When this is the case there will be a time during the stripping operation that the drillstring will penetrate the bubble. When this happens, certain adjustments to the procedure being used must be made in order to maintain a constant bottomhole pressure. For a given kick volume, the height occupied in the open hole will be significantly less than the height occupied in the drillstring by hole annulus. As a result, in order to satisfy the basic equation given below:

Equation. O.4

BHP = HPm + HPk + SP

where: BHP = Bottomhole Pressure (psi) HPm = Hydrostatic Pressure of the Mud (psi) HPk

= Hydrostatic Pressure of the Kick Fluid (psi) SP = Surface Pressure (psi)

WELL CONTROL MANUAL



When the hydrostatic pressure changes due to a change in the height of the bubble, the surface (i.e., casing) pressure must also change. The amount of surface pressure change needed to offset the change in hydrostatic is simplified by:

Equation O.5

∆Surface Pressure = (PGM - PGG) x (∆H)

where: PGM

= Pressure Gradient of the Mud PGK = Pressure Gradient of the Kick Fluid ∆H = Kick Height in the Drillstring by Hole Annulus – Kick Height in the Open Hole

When the bubble moves into a different hole geometry, the choke will have to be adjusted so that the casing pressure rises or declines by this amount; then this new value is used as a new starting point for the rest of the stripping operation. An estimation of the point in time when the drillstring will penetrate the bubble can be made so that the Drilling Foreman will be ready to make the choke adjustment. In order to determine when this will happen, two calculations must be made. First, an estimation of the bubble migration rate (if any) can be calculated from the rise in casing pressure by:

Equation O.6

∆CP MR =

_______________

.007 x MW x Hrs

where: MR = Migration Rate (ft/hr) ∆CP = Change in Casing Pressure (psi) MW = Mud Weight (pcf) Hrs = Time of Casing Pressure Change (hrs)

Once the calculation has been made, the migration can be drawn graphically as in Figure O.2. The plot of depth vs. time can be used to determine where the bubble is in the hole at any time. Secondly, an estimation of tripping speed must be made. This is a subjective number also expressed in ft/hr. Plotting the trip speed on the same graph as the migration as in Figure O.2 shows the two lines intersecting. The point at the intersection gives not only the time when the bit penetrates the bubble but also an approximation of the depth. The problem can also be solved mathematically by:

WELL CONTROL MANUAL



Equation. O.7

DBubble - DBM T =

MR + TS

where: DBubble = Depth of the Bubble (ft) DBM = Depth of the Bit (ft) MR = Migration Rate (ft/hr) TS = Tripping Speed (ft/hr)

Either solution will yield the same result. Caution should be used however, due to the fact that this is a simplified solution to the problem. Factors such as bubble expansion, changing bubble density and others are not taken into consideration.

Figure O.2 Bubble Penetration D = Depth pipe intercepts bubble T = Time pipe intercepts bubble Bubble Depth

Dep

th x

100

0 (f

t)

D

T

Bit Depth

WELL CONTROL MANUAL



3.0 Snubbing When the net upward force is greater than the net downward force, a condition known as pipe light exists. In order to return the pipe to bottom so that the well can be killed, it is necessary to force, or snub the pipe in the hole. During snubbing operations, the pipe is pushed in the hole while the well has pressure on it. Many times the force required to push the pipe in is significant due to higher than normal well pressures. As a result, more blowout prevention equipment is usually installed. However, not all snubbing operations require elaborate hookups. Nevertheless, as in all well control situations, a few basic principals govern and should be utilized in all snubbing work.

3.1 Equipment

All snubbing units require two sets of slips for handling pipe. One set, called the traveling slips, is used to actually force the pipe into the wellbore. The second set, called stationary slips, are used to hold the pipe in place while the travelling slips are being repositioned. There are two different types of snubbing units widely used in industry today. Both types employ traveling and stationary slips.

3.1.1 Conventional Units

One of the first kinds of snubbing units used is what is known as the conventional snubber. In a conventional unit, the rig’s hoisting equipment is used in combination with the rig’s blowout prevention equipment. The stationary slips are usually attached to the BOP stack and the traveling slips are used in conjunction with a pulley system and the blocks. Raising the traveling block causes the traveling snubbers that grip the pipe to move down, forcing the pipe in the hole. After each downward stroke, the stationary snubbers

Figure O.3 Conventional Snubbing Unit

WELL CONTROL MANUAL



grip the pipe until the traveling snubbers are moved to get another bite. The procedure is repeated until the snubbing force is no longer needed. Figure O.3 shows a conventional snubbing unit hookup.

3.1.2 Hydraulic Units

Hydraulic units perform the same function as conventional units in the same manner. Once again, the two sets of slips are used in alternating fashion until the net downward force overcomes the net upward force. Hydraulic units use hydraulic pistons, or jacks, to move the traveling slips and force the pipe into the hole. These snubbers have gained popularity in recent years, as they do not require that a rig be on the well. All of the functions of the unit and BOP stack are operated from the workbasket on top of the jack. The main disadvantage of the hydraulic unit is that it takes quite a bit more time to rig up and usually requires additional blowout preventers. Figure O.4 shows a modern hydraulic snubber.

3.1.3 Auxiliary Equipment

There is a wide range of equipment that is used in conjunction with snubbing operations that should be mentioned. One of the most important is the stripping rubber that is used on many snubbing jobs. When wellbore

Figure O.4 Hydraulic Snubbing Unit

WELL CONTROL MANUAL



pressures are not too high, it is common to use a stripping rubber as the main well control device instead of stripping through the annular or ram-to-ram. The rubber is sized to the pipe being run and sits in a housing on top of the BOP. As this is one of the most important pieces of equipment on location, care should be taken to insure that the rubber and its housing are up to the specifications required of the rest of the BOP stack and that the rubber is frequently checked for wear. Many snubbing hookups have a great deal of valves and chokes rigged up in the stack. Often, these valves are hydraulically operated plug valves and the chokes are positive type chokes. Regardless of the type of valve or choke, all of the equipment should conform to Saudi Aramco and API specifications.

3.2 Annulus Pressure Control

At some point in time, the net forces will change direction and be downward. This is the condition previously referred to as pipe heavy and the snubbing force is no longer needed. This point is called the balance point and can be calculated by:

Equation O.8

Fp L = AW x BF

where: L = Length of Pipe (ft) Fp

= Upward Force (lbs) AW = Unit Air Weight of Pipe (lbs/ft)

BF = Buoyancy Factor

Sound judgement must be used when applying the equation because such factors as bubble migration and bubble penetration and their relation to casing pressure should be considered.

3.3 Special Considerations

There are many uses for hydraulic snubbing units today. In fact, many people know the equipment as hydraulic work-over rigs. As a result, the number of different well control situations that can arise from the various workover situations are too numerous to detail. However, there are guidelines which apply to almost all snubbing unit hookups.

3.3.1 Safety

One of the main responsibilities of the Saudi Aramco Drilling Foreman is to provide a safe work environment. Snubbing operations are inherently dangerous. Any time that pipe is being

WELL CONTROL MANUAL



forced into the hole, safety becomes a major concern. Several items need to be examined when planning and rigging up to perform a snubbing operation. In addition to the purpose of the snubbing operation, be it on a drilling rig or a work-over, there is an extensive list of questions that need to be addressed by the Saudi Aramco personnel involved or the snubbing contractor in order to insure a safe operation. Some of the questions to consider:

• Snubbing force required • BOP stack configuration and control station location • Escape route for personnel working in the basket • Shutdown system for any nearby producing wells • Structural support and guidelines for snubbing unit • Quantity of spare parts required • Firefighting equipment required • H2S contingency plans • Applicable governmental regulations

The best way to insure a safe snubbing operation is to do adequate planning with the snubbing contractor involved. Each snubbing contractor has their own set of safety procedures that have evolved through years of experience that should be discussed and reviewed before the job begins. API RP 54 has a few suggestions as to safety equipment used for snubbing, and should be consulted during the planning phase.

3.3.2 Equipment Layout

Another important consideration while rigging up is the equipment layout. The modern hydraulic snubbing units in use today require quite a bit of equipment to operate. As a result, in confined areas it is important that the equipment be properly located for accessibility. BOP control stations and closing units should be a sufficient distance from the well. Engines and hydraulic power packs need to be strategically located away from flow lines and the well. Pumping units for well control need to be spotted so that the snubbing unit operator can clearly see the pump operator. All flow lines and pressure release lines need to be given special attention during rigging up so that other equipment does not interfere with well control operations. API RP 54 provides some good suggestions but pre-job planning is usually the best way to optimize the wellsite space available.

Many times the snubbing unit is rigged up very high in the air. This means that communication with the Drilling Foreman on location, as well as other personnel involved in the operation, is difficult at times. Special consideration should be given to providing a means of communicating with the personnel in the snubbing basket. This will insure a much safer and efficient operation for all.

WELL CONTROL MANUAL



4.0 Lubricate and Bleed

Often during major well control situations there comes a time when gas has reached the surface. This is the point in time that the surface pressure is the highest due to reduced hydrostatic pressure in the well. When this occurs, the best way to remove the gas is by circulating. However, circulation is not always possible and the well must be lubricated. The theory involved in lubricating and bleeding is the same as that for volumetric control. Surface pressure is replaced with hydrostatic pressure by pumping mud into the well on top of the gas. The gas and mud are allowed to change place in the hole and some of the surface pressure is bled off. The ‘lubricate and bleed’ procedure is listed in the following steps. 1) Calculate the hydrostatic pressure that will be exerted by 1 barrel of mud.

2) Slowly pump a given volume of mud into the well. The amount chosen will depend on many different well conditions and may change throughout the procedure. The rise in surface pressure can be calculated by applying Boyle's Law (P1V1 = P2V2) and realizing that for every barrel of mud pumped into the well the bubble size decreases by 1 barrel.

3) Allow the gas to migrate back to the surface. This step could take quite some time and is dependent on a number of factors such as mud weight and viscosity.

4) Bleed gas from the well until the surface pressure is reduced by an amount equal to the hydrostatic pressure of the mud pumped in. It is very important to bleed only gas. If at any time during the procedure mud reaches the surface and starts bleeding, the well should be shut in and gas allowed to migrate.

5) Repeat Steps 4.2 through 4.4 until all of the gas has been bled off or a desired surface pressure has been reached.

5.0 Bullheading

Another specialized well control technique is bullheading. Bullheading has been used for a number of reasons for quite some time and is still one of the primary well control methods for certain situations. A number of questions arise when considering bullheading. Concerns such as those listed below and others should be addressed before any bullheading-type well control procedure is attempted. The important thing to remember about bullheading is that it IS NOT a constant bottomhole pressure method. As a result, there are inherent complications and dangers when using this technique.

• Casing shoe strength • Relative permeability of formations to oil, gas, water and mud • Surface pressure limitations • Pump rate • Bubble migration rate • Volume of mud to pump • Fluid weight and type used

WELL CONTROL MANUAL



6.0 Stripping Example Problem “Ali Al-Qahtani”, the Saudi Aramco Drilling Foreman, had a bad feeling about this trip. He knew when he left bottom that he was in a transition zone and that the well was stable but something just didn't feel right. After watching the crew pull 30 stands and carefully monitoring his fill-ups, Ali began to feel a little better. But when the crew started to install the pipe wiper rubber they noticed that the well was flowing. Ali had the crew stab the safety valve, quickly closed the annular preventer and recorded the following information:

Hole Size: 8-1/2” Kick Size: 15 bbl Drill Pipe: 5” NC 50 Mud Weight: 87 pcf Hole Capacity: 0.0702 bbl/ft TD: 11,500’ MD/TVD Ann. Capacity: 0.0459 bbl/ft Bit Depth: 8700’ Shoe Test: 116 pcf SICP: 450 psi Casing Shoe: 4500’ MD/TVD

Ali knew he would have to strip back to bottom to kill the well. He had the crew install the inside BOP and open the safety valve. Once he was sure that the inside BOP was holding Ali went about the business of determining his safety factor for volumetric control.

Shoe Pressure = (TVDshoe x Mud Weight x 0.007) + SICP or, = (4500 x 87 x 0.007) + 450 = 3190 psi

He knew the shoe would break down at a pressure of,

Shoe Fracture Pressure = (TVDshoe x Shoe Test x 0.007) = (4500 x 116 x 0.007) = 3654 psi

Ali realized that he had plenty of room for a 200 psi safety factor (3654 - 3190 = 463 psi). He calculated his pressure increment by dividing the safety factor by 3,

Pressure 200 psi Increment = 3

= 67 psi, or 70 psi

Ali then had to calculate his mud increment. After a moment of thought, he decided that he should use the hole capacity factor in the equation because the kick was well below the bit.

Mud PI x HCF Increment = MW x 0.007

WELL CONTROL MANUAL



Mud 70 x 0.0702 Increment = 87 x 0.007 = 8.1 bbl

Ali knew that as long as the kick was below the bit for every 8.1 bbl he bled off, the hydrostatic pressure is reduced by 70 psi. After checking the casing pressure gauge and seeing that it read only 460 psi Ali knew that he had time to do some more calculations. He realized that he needed to know when during the stripping operation he would intercept the bubble so that he could change his mud increment. Ali got with his toolpusher and they decided that the crew would strip into the hole at a rate of 1000 feet per hour. He then checked the casing gauge and saw that the casing pressure was now 530 psi. He looked at his watch and saw that it had been 10 minutes since the well had stabilized. The calculation was then easy,

Change in Casing Pressure Migration Rate = 0.007 x Mud Weight x Hours 530 - 450 = 0.007 x 87 x 0.167 = 787 ft/hr

Ali decided to use 800 ft/hr as the migration rate and 1000 ft/hr as the stripping speed. He then solved for the time of bubble penetration.

Depthbubble - Depthbit Time = Migration Rate + Trip Speed 11500 - 8700 = 800 + 1000 = 1.55 hours

So after 1-1/2 hours the bubble would be in the drillpipe by hole annulus and a different mud increment would have to be calculated.

Mud PI x ACF Increment = 0.007 x MW

WELL CONTROL MANUAL



70 x 0.0459 = 0.007 x 87

= 5.3 bbls

The volume of mud to be bled due to pipe displacement and capacity was the only calculation left for Ali. He looked up the factors in his well control manual.

Pipe Capacity = 0.0178 bbl/ft X 93 ft/stand = 1.655 bbl/stand capacity Pipe Displacement = 0.607 bbl/93 ft stand Volume to Bleed = Capacity + Displacement = 1.655 + 0.607 = 2.262 bbl/stand

Ali felt that he was now ready to strip in the hole. He looked over all of his calculations and realized that he had forgotten to include the change in surface pressure due to bubble elongation when the bit entered the bubble. The surface pressure would have to increase to make up for the lost hydrostatic when the kick entered a new hole geometry. Ali knew that he needed to decide on a reasonable gradient for the kick. He settled on 0.12 psi/ft. Calculation of the kick height in the open hole and in the annulus also had to be done.

Kick Height Kick Size in Open Hole = Hole Capacity Factor 15 bbl = 0.0702 bbl/ft = 214 ft Kick Height in Drillpipe by Hole Kick Size Annulus = Ann. Capacity Factor 15 bbl = 0.0459 bbl/ft = 327 ft

WELL CONTROL MANUAL



Ali now substituted the proper values into the equation. ∆Surface Pressure = (PGM - PGG) x (∆H) = [(87 x 0.007) - 0.12] x (327 - 214) = 55.3 psi

After stripping for approximately 1-1/2 hours not only would the mud increment change from 8.15 bbl to 5.33 bbl but the casing pressure would also need to rise by 55 psi. This would insure a constant bottomhole pressure. Ali headed for the rig floor. He read the casing pressure and saw that it was 650 psi. Ali allowed surface pressure to increase to allow for a 200 psi safety factor. After the safety meeting, Ali adjusted the pressure on his annular preventer and the crew began stripping into the hole. Ali kept the data from the stripping in a chart in his pipe book. Cumulative Stand Stripped




Volume (bbls)

Time (hrs/min)

3 650 6.8 9.1 2.3 2:18 6 650 13.6 18.2 4.6 2:35 9 650 20.4 27.3 6.9 2:52 ***Allow casing pressure to rise 70 psi pressure increment through migration. 12 720 27.2 35.2 8.0 / 0.0 3:10 15 770 34.0 42.0 8.0 / 0.0 3:27 18 770 40.8 51.1 10.3 / 2.3 3:45 21 770 47.6 63.0 15.5 / 5.2 4:03 ***Allow casing pressure to rise 70 psi pressure increment through migration. 24 840 54.4 72.0 17.7 / 2.2 4:20 27 840 61.2 84.0 23.0 / 5.3 4:37 30 840 68.0 93.0 25.1 / 2.1 4:54

Note how after 1-1/2 hours Ali let the casing pressure rise 50 psi for hole geometry change and made himself a note to change his mud increment from 8 bbl to 5 bbl. Once he got safely back on bottom, Ali circulated the kick out using the Driller's Method. He conditioned the mud and was ready to try the trip all over again.

WELL CONTROL MANUAL

Drilling & Workover October 2002 __ SECTION P – TABLES AND CHARTS

Current Revision: October 2002 P - 1 3rd Edition Previous Revision: October 1998

Table of Contents

Table P.1 Capacities and Displacement of Drillpipe..........................P-2 Table P.2 Capacities and Displacement of Drill Collars ....................P-4 Table P.3 Capacities and Displacement of ‘Hevi-Wate’ Drillpipe......P-5 Table P.4 Capacity of Hole...................................................................P-6 Table P.5 Pump Displacement.............................................................P-7 Pc Max (Part 1) for Driller's Method ......................................................P-9 Pc Max (Part 2) for Driller's Method .................................................... P-10 Pc Max (Part 1) for Engineer's Method ............................................... P-11 Pc Max (Part 2) for Engineer's Method ............................................... P-12 Volume of Gas at Surface (Driller's and Engineer's Method)........... P-13 Chart Equations for Pc Max Determination....................................... P-14

1.0 Driller’s Method Worksheet ....................................................... …P-14 2.0 Engineer’s Method Worksheet.......................................................P-14 3.0 Volume of Gas at Surface ..............................................................P-14

Theoretical Equations for Pc Max Determination............................. P-15 1.0 Engineer’s Method .........................................................................P-15 2.0 Driller’s Method..............................................................................P-15 3.0 Miscellaneous Supporting Equations ...........................................P-15 4.0 Nomenclature for Theoretical Equations ......................................P-16

Table P.6 BOP Opening and Closing Volumes ................................ P-17 Ram Type Blowout Preventers ........................................................... P-17 Koomey....................................................................................................................P-17 Hydril…....................................................................................................................P-17 Bowen Tools, Inc.....................................................................................................P-19 Cameron Iron Works ................................................................................. P-19 Guiberson Division of Dresser Industries..............................................................P-22 Shaffer.. ...................................................................................................................P-22 Annular Blowout Preventers .............................................................. P-24 Hydril……................................................................................................................ .P-24 Cameron Iron Works ...............................................................................................P-25 Shaffer.. ...................................................................................................................P-25 Regan……................................................................................................................P-25 Hydraulically Operated Valves ........................................................... P-27 Cameron Iron Works ...............................................................................................P-27 McEvoy Oilfield Equipment.....................................................................................P-27 Shaffer.. ...................................................................................................................P-28

WELL CONTROL MANUAL



Table P.1 Capacities and Displacement of Drillpipe Generalized Equations (Internal Diameter)2 (Hole Diameter)2 - (Drillpipe OD)2 Internal Capacity = ------------------------- Annular Capacity = --------------------------------------------- 1029 1029

DRILL PIPE ANNULUS Pipe Size

OD (inches)

Nominal Weight (lb / ft)

Internal Capacity (bbl / ft)

Displacement (bbl / 93 ft

stand)

Hole Diameter (inches)

Annular Capacity (bbl / ft)

2-7/8 10.4 0.0045 0.329 4-1/8 0.0085 4-1/2 0.0116 4-5/8 0.0128 4-3/4 0.0139 5-7/8 0.0255 6 0.0269 6-1/8 0.0284 6-1/4 0.0299 6-1/2 0.0330 6-3/4 0.0362

3-1/2 9.5 0.0087 0.300 4-1/2 0.0078 13.3 0.0074 0.417 4-5/8 0.0089 15.5 0.0066 0.495 4-3/4 0.0100 5-7/8 0.0216 6 0.0231 6-1/8 0.0245 6-1/4 0.0260 6-1/2 0.0291 6-3/4 0.0324 8-1/2 0.0583

4 14.0 0.0108 0.440 5-7/8 0.0180 6 0.0194 6-1/8 0.0209 6-1/4 0.0224 6-1/2 0.0255 6-5/8 0.0271 7-7/8 0.0447

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Table P.1 Capacities and Displacement of Drillpipe (continued)

DRILL PIPE ANNULUS Pipe Size

OD (inches)




stand)



4-1/2 16.6 0.0142 0.507 6-1/2 0.0214 20.0 0.0129 0.633 6-3/4 0.0246 7-7/8 0.0406 8-3/8 0.0485 8-1/2 0.0505 8-3/4 0.0547 9-1/2 0.0680 9-5/8 0.0703 9-7/8 0.0751 12-1/4 0.1261 17-1/2 0.2778

5 16.3 0.0189 0.503 8-3/8 0.0439 19.5 0.0178 0.607 8-1/2 0.0459 25.6 0.0155 0.813 8-3/4 0 0501 9-1/2 0.0634 9-5/8 0.0657 9-7/8 0 0704 12-1/4 0 1215 17-1/2 0.2733

5-1/2 21.9 0.0222 0.671 8-3/8 0.0388 24.7 0.0212 0.763 8-1/2 0.0408 8-3/4 0.0450 9-1/2 0.0583 9-7/8 0.0653 12-1/4 0.1164 17-1/2 0.2682

Note: The internal capacity, displacement, and annular capacity values listed in Table P.1 make no allowances for tool joint dimensions and should NOT be used for critical displacement operations such as cement squeezing.

WELL CONTROL MANUAL



Table P.2 Capacities and Displacement of Drill Collars

DRILL COLLAR ANNULUS Collar Size

OD (inches)




stand)



4-1/8 x 2 35 0.0039 1.18 6-1/8 0.0199

4-3/4 x 2-1/4 47 0.0049 1.58 5-7/8 0.0116 6-1/8 0.0145 6-1/2 0.0191 6-3/4 0.0224

6 x 2-1/4 83 0.0049 2.80 7-7/8 0.0253 8-1/2 0.0352 8-3/4 0.0394

6-1/4 x 2-13/16 83 0.0077 2.82 7-7/8 0.0223 8-3/8 0.0302 8-1/2 0 0323 8-3/4 0.0364

9-7/8 0.0568 6-1/2 x 2-13/16 92 0.0077 3.10 8-1/2 0.0292

8-3/4 0.0333 9-7/8 0.0537

6-3/4 x 2-13/16 101 0.0077 3.40 8-1/2 0.0259 8-3/4 0.0301 9-7/8 0.0505

7 x 2-13/16 110 0.0077 3.71 8-3/4 0.0268

9-7/8 0.0471

7-3/4 x 2-13/16 139 0.0077 4.71 9-7/8 0.0364 12-1/4 0.0875

8 x 3 147 0.0087 4.97 9-7/8 0.0326 12-1/4 0.0836 17-1/2 0.2354

9 x 3 192 0.0087 6.51 12-1/4 0.0671 17-1/2 0.2189

10 x 3 243 0.0087 8.22 12-1/4 0.0487 17-1/2 0.2004

Table P.3 Capacities and Displacement of ‘Hevi-Wate’ Drillpipe

WELL CONTROL MANUAL



‘HEVI-WATE’ DRILLPIPE ANNULUS Pipe Size

(OD) (inches)




stand)



3-1/2 25.3 0.0042 0.856 4-1/2 0.0078 4-5/8 0.0089

4-3/4 0.0100 5-7/8 0.0216 6 0.0231 6-1/8 0.0246

6-1/4 0.0261 6-1/2 0.0292

6-3/4 0.0324 8-1/2 0.0583 4 29.0 0.0065 1.006 5-7/8 0.0180 6 0.0194 6-1/8 0.0209 6-1/4 0.0224 6-1/2 0.0255 6-5/8 0.0271

4-1/2 41.0 0.0074 1.388 6-1/2 0.0214 6-3/4 0.0246 7-7/8 0.0406 8-3/8 0.0485 8-1/2 0.0505 8-3/4 0.0547 9-1/2 0.0680 9-5/8 0.0704 9-7/8 0.0751 12-1/4 0.1262 17-1/2 0.2779 5 49.3 0.0088 1.670 8-3/8 0.0439 8-1/2 0.0459 8-3/4 0.0501

9-1/2 0.0634 9-5/8 0.0657 9-7/8 0.0705 12-1/4 0.1215 17-1/2 0.2733

WELL CONTROL MANUAL



Table P.4 Capacity of Hole

Diameter of Hole (inches)

Capacity (gals / ft)

Capacity (bbls / ft)

Capacity (ft / bbl)

2-3/4 .3086 .0073 136.0661 3 .3672 .0087 114.3333

3-1/4 .4310 .0103 97.4201 4 .6528 .0155 64.3125

4-1/8 .6942 .0165 60.4738 4-1/4 .7370 .0176 56.9689 4-3/8 .7809 .0186 53.7600 4-5/8 .8262 .0197 50.8148 4-5/8 .8727 .0208 48.1052 4-3/4 .9205 .0219 45.6066 4-7/8 .9696 .0231 43.2987

5 1.0200 .0243 41.1600 5-1/4 1.1246 .0268 37.3333 5-1/2 1.2342 .0294 34.0165 5-3/4 1.3490 .0321 31.1229 5-7/8 1.4082 .0335 29.8126

6 1.4688 .0350 28.5833 6-1/8 1.5306 .0365 27.4286 6-1/4 1.5938 .0380 26.3424 6-1/2 1.7238 .0411 24.3550 6-5/8 1.7907 .0427 23.4446 6-3/4 1.8590 .0443 22.5844 7-1/2 2.2950 .0547 18.2933 7-5/8 2.3721 .0565 17.6985 7-3/4 2.4506 .0584 17.1322 7-7/8 2.5302 .0603 16.5926

8 2.6112 .0622 16.0781 8-3/8 2.8617 .0682 14.6705 8-1/2 2.9478 .0702 14.2422 8-5/8 3.0351 .0723 13.8324 8-3/4 3.1238 .0744 13.4400

9 3.3048 .0787 12.7028 9-1/4 3.4910 .0832 12.0263 9-1/2 3.6822 .0877 11.4017 9-5/8 3.7797 .0900 11.1074 9-3/4 3.8786 .0924 10.8245 9-7/8 3.9786 .0948 10.5522 12 5.8752 .1399 7.1458

12-1/8 5.9982 .1429 6.9993 12-1/4 6.1226 .1458 6.8571 12-3/8 6.2481 .1488 6.7193

15 9.1800 .2187 4.5733 17-1/2 12.4950 .2976 3.3600

WELL CONTROL MANUAL



Table P.5 Pump Displacement

DUPLEX PUMPS Barrels per Inch of Stroke

----------------------------------------------Fluid Piston Rod Diameter (inches) ---------------------------------------------

Liner Size

(inches)

1-1/2 1-3/4 1-7/8 2 2-1/4 2-3/8 2-1/2 2-3/4 3 3-1/8 3-1/4

3-1/2 0.00360 3-3/4 0.00419 0.00460 0.00398 00.0391

4 0.00482 0.00486 0.00461 0.00453 4-1/4 0.00548 0.00535 0.00528 0.00520 4-1/2 0.00619 0.00606 0.00599 0.00591 0.00574 0.00564 0.00555 0.00533 0.00510 0.00498 0.00485 4-3/4 0.00694 0.00681 0.00674 0.00666 0.00649 0.00639 0.00629 0.00608 0.00585 0.00572 0.00560

5 0.00773 0.00760 0.00753 0.00745 0.00728 0.00718 0.00708 0.00687 0.00664 0.00651 0.00638 5-1/4 0.00856 0.00843 0.00836 0.00828 0.00811 0.00801 0.00791 0.00770 0.00747 0.00734 0.00721 5-1/2 0.00943 0.00930 0.00923 0.00915 0.00898 0.00888 0.00878 0.00857 0.00834 0.00821 0.00808 5-3/4 0.01034 0.01021 0.01014 0.01006 0.00989 0.00979 0.00969 0.00948 0.00925 0.00912 0.00900

6 0.01129 0.01116 0.01109 0.01101 0.01084 0.01074 0.01064 0.01043 0.01020 0.01008 0.00995 6-1/4 0.01228 0.01215 0.01208 0.01200 0.01183 0.01174 0.01164 0.01142 0.01119 0.01107 0.01094 6-1/2 0.01332 0.01318 0.01311 0.01303 0.01296 0.01277 0.01267 0.01246 0.01222 0.01210 0.01197 6-3/4 0.01439 0.01426 0.01418 0.01411 0.01393 0.01384 0.01374 0.01353 0.01330 0.01317 0.01304

7 0.01550 0.01537 0.01530 0.01522 0.01505 0.01495 0.01485 0.01464 0.01441 0.01429 0.01416

WELL CONTROL MANUAL



Table P.5 Pump Displacement (continued)

GENERALIZED PROCEDURES

Step One: Determine “Barrels / Inch of Stroke” by using the appropriate pump table, or the following equations: (Linear Diameter)² Barrels / Inch of Stroke = --------------------------- (Triplex) 4116 2 X (Linear Diameter)² – (Rod Diameter)² Barrels / Inch of Stroke = ------------------------------------------------------------ ( Duplex) 6174

Step Two: Calculate actual pump displacement with the following formula: Pump Displacement = Barrels / Inch Stroke Volumetric (Bbls / Stroke) of Stroke X Length (Inches) X Efficiency

Note: Use Volumetric Efficiency in decimal form (e.g., 95% = 0.95)

TRIPLEX PUMPS Liner Diameter

(inches) Displacement

(bbls / inch of stroke) 3-1/2 0.002976 3-3/4 0.003416

4 0.003886 4-1/4 0.004387 4-1/2 0.004919 4-3/4 0.005480

5 0.006073 5-1/4 0.006695 5-1/2 0.007348 5-3/4 0.008031

6 0.008744 6-1/4 0.009488 6-1/2 0.010263 6-3/4 0.011067

7 0.011902

WELL CONTROL MANUAL



Figure P.1a Pc Max (Part 1) for Driller's Method

WELL CONTROL MANUAL



Figure P.1b PcMax (Part 2) for Driller's Method

WELL CONTROL MANUAL



Figure P.2a PcMax (Part 1) for Engineer's Method

WELL CONTROL MANUAL



Figure P.2b PcMax (Part 2) for Engineer's Method

WELL CONTROL MANUAL



Figure P.3 Volume of Gas at Surface (Driller's and Engineer's Method)

WELL CONTROL MANUAL



Chart Equations for PcMax Determination 1.0 Driller's Method Worksheet

(A) PcMax (Part 1) = SIDP / 2 (psi) (B) PcMax (Part 2)

[Fig. P.1a, P.Ib) = (PcMax, 1)2 + (PR) (H1) (r1) (TZ) where: PR = Reservoir Pressure (psi) H1 = Height of Bubble (ft) {Pit Gain / ACF (DP X CSG)} r1 = Pressure Gradient of OMW (psi/ft) TZ = Temperature/Gas Compressibility (Figure P.5) or = 4.03 - 0.38 ln (PR)

2.0 Engineer’s Method Worksheet

(A) PcMax (Part 1) [Fig. P.2] or = (Internal DP Cap.) (.052) (DMud Wt)

________________________________

(2) (Annulus Capacity Factor) (B) PcMax (Part 2) [Fig. P.3] or = (PR) (H1) (r2) (TZ) where: PR = Reservoir Pressure (psi) H1 = Height of Bubble (ft) {Pit Gain / ACF (DP X CSG)} r2 = Pressure Gradient of KMW (psi/ft) TZ = Temperature/Gas Compressibility (Figure P.5) or = 4.03 - 0.38 ln (PR)

3.0 Volume of Gas at Surface

[from Figures P.4a and P.4b] Vg = (Kick Size) (PR) (TZ)

___________________

PcMax where: PR = Reservoir Pressure (psi) TZ = Temperature/Gas Compressibility (Figure P.5) PcMax = Calculated Above (either Driller's or Engineer's Method)

WELL CONTROL MANUAL



Theoretical Equations for PcMax Determination

1.0 Engineer’s Method

D1 (ρ2 - ρ1) - PG (D1 (ρ2 - ρ1) - PG ) 2 PcMax = ----------------------- + ------------------------- 2 2 + (PR) (H1) (ρ2) (TZ) V = V2 - V1 PRV1TZ where: V2 = ----------- PcMax

2.0 Driller’s Method

PR - PG - Dρ1+ (PR - PG - Dρ1 ) 2 + (PR)(H1)(ρ1)(TZ) PcMax = ------------------- ----------------------------------------------- 2 2 V = V2 - V1 PRV1TZ where: V2 = ----------- PcMax

3.0 Miscellaneous Supporting Equations

VDPC (ft.) D1 = -------------- AV V1 H (ft) =

_______(if answer is equal to or less than drill collar length)

ADC

V1 - (ADC) (L) = ---------------------- + L, ft. AV (if answer above is greater than drill collar length)

WELL CONTROL MANUAL



V1 H1 (ft) =

_______ (annulus constant)

AV

PG = PDP + PMDP - PCI - PMA, psi or = .12H, psi (.12 is an average gas gradient, psi/ft)

PMA = (D-H)ρ1 or .007 (D-H) M1, psi

PMDP = Dρ1 or .007 DM1, psi PR = Dρ2 or .007 DM2, psi

ρ1 = .007 M1, psi/ft

ρ2 = .007 M2, psi/ft

VDC = LCDC, bbl

VDP = (D-L)CDC, bbl

VDPC = VDP + VDC, bbl

4.0 Nomenclature for Theoretical Equations ADC = Annular volume between drill collars and hole, bbl/ft

AV = Annular volume between drill pipe and hole, bbl/ft

CDC = Capacity of drill collars, bbl/ft

CDP = Capacity of drill pipe, bbl/ft

D = Well depth, ft

D1 = Height in annulus that mud in drill string will occupy when displaced into annulus, ft.

H = Height of gas bubble at bottom of hole, ft

H1 = Height of gas bubble using constant annulus, ft

L = Length of drill collars, ft.

M1 = Old mud weight at time of kick, lb/ft³

M2 = New mud weight required to balance formation pressure, lb/ft³

PCL = Initial shut-in casing pressure, psi

PcMAX = Maximum surface casing pressure when gas reaches surface, psi

PDP = Initial shut-in drill pipe pressure, psi

WELL CONTROL MANUAL



Table P.6 BOP Opening and Closing Volumes Ram Type Blowout Preventers Hydraulic Model Nominal Working Vertical Operating Gallons Gallons or Size Pressure Bore Pressure to to Close Open Type (Inches) (Max PSI) (Inches) (psi) Close Open Ratio Ratio

Koomey PL 7-1/16 3000 7-1/16 1500/5000 1.02 0.96 4.62:1 1.5:1 PL 7-1/16 5000 7-1/16 1500/5000 0.80 0.80 7.75:1 2.5:1 PL 7-1/16 10000 7-1/16 1500/5000 1.02 0.96 7.75:1 2.5:1 PL 11 5000 11 1500/5000 3.05 3.05 7.75:1 2.5:1 PL 11 10000 11 1500/5000 3.05 3.05 7.75:1 2.5:1 PL 13-5/8 3000 13-5/8 1500/5000 6.25 5.78 4.62:1 1.5:1 PL 13-5/8 5000 13-5/8 1500/5000 5.80 5.80 7.75:1 2.5:1 PL 13-5/8 10000 13-5/8 1500/5000 5.80 5.80 7.75:1 2.5:1 PB 7-1/16 5000 7-1/16 1500/5000 0.38 0.38 40.0:1 25.0:1 PB 11 5000 11 1500/5000 1.50 1.50 40.0:1 35.0:1 PB 11 10000 11 1500/5000 1.50 1.50 40.0:1 35.0:1 PB 13-5/8 5000 13-5/8 1500/5000 2.80 2.80 40.0:1 35.0:1 PB 13-5/8 10000 13-5/8 1500/5000 2.80 2.80 40.0:1 35.0:1 PB 13-5/8 15000 13-5/8 1500/5000 3.54 3.54 42.86:1 25.0:1 PB 18-3/4 10000 18-3/4 1500/5000 11.50 11.50 20.0:1 25.0:1 PB 18-3/4 15000 18-3/4 1500/5000 11.50 11.50 30.0:1 30.0:1

Hydril Manual 7-1/16 3000 7-1/16 3000 Max. 1.00 0.93 4.8:1 1.5:1 Lock 7-1/16 5000 7-1/16 3000 Max. 1.00 0.93 4.8:1 1.5:1 Pipe 7-1/16 10000 7-1/16 3000 Max. 1.90 2.00 7.7:1 1.7:1 7-1/16 15000 7-1/16 3000 Max. 3.70 3.40 7.1:1 6.6:1 9 3000 9 3000 Max. 1.90 1.90 4.5:1 2.6:1 9 5000 9 3000 Max. 1.90 1.90 4.5:1 2.6:1 11 3000 11 3000 Max. 3.30 3.20 6.0:1 2.0:1 11 5000 11 3000 Max. 3.30 3.20 6.0:1 2.0:1 11 10000 11 3000 Max. 5.20 5.00 6.9:1 2.4:1 11 15000 11 3000 Max. 8.80 8.10 7.2:1 3.24:1 13-5/8 3000 13-5/8 3000 Max. 5.40 4.90 4.8:1 2.1:1 13-5/8 5000 13-5/8 3000 Max. 5.40 4.80 4.8:1 2.1:1 13-5/8 10000 13-5/8 3000 Max. 11.80 11.80 10.2:1 3.8:1 20-3/4 3000 20-3/4 3000 Max. 8.10 7.20 4.75:1 0.98:1 21-1/4 2000 21-1/4 3000 Max. 8.10 7.20 4.75:1 0.98:1 21-1/4 5000 21-1/4 3000 Max. 17.50 16.60 10.2:1 1.9:1

WELL CONTROL MANUAL



Hydraulic Model Nominal Working Vertical Operating Gallons Gallons or Size Pressure Bore Pressure to to Close Open Type (Inches) (Max PSI) (Inches) (psi) Close Open Ratio Ratio

Hydril (continued) Manual 11 3000 11 3000 Max. 5.50 6.00 5.6:1 4.2:1 Lock 11 5000 11 3000 Max. 5.50 5.00 5.6:1 4.2:1 Shear 11 10000 11 3000 Max. 8.80 8.20 11.7:1 4.0:1 11 15000 11 3000 Max. 8.80 8.10 7.2:1 3.24:1 13-5/8 3000 13-5/8 3000 Max. 11.50 11.20 10.1:1 4.7:1 13-5/8 5000 13-5/8 3000 Max. 11.50 11.20 10.1:1 4.7:1 13-5/8 10000 13-5/8 3000 Max. 11.80 11.80 10.2:1 3.8:1 20-3/4 3000 20-3/4 3000 Max. 17.20 16.30 10.14:1 2.2:1 21-1/4 2000 21-1/4 3000 Max. 17.20 16.30 10.14:1 2.2:1 21-1/4 5000 21-1/4 3000 Max. 17.50 16.60 10.2:1 1.9:1 MPL 7-1/16 3000 7-1/16 3000 Max. 1.20 0.93 5.4:1 1.5:1 Pipe 7-1/16 5000 7-1/16 3000 Max. 1.20 0.93 5.4:1 1.5:1 7-1/16 10000 7-1/16 3000 Max. 2.00 1.80 8.2:1 1.7:1 7-1/16 15000 7-1/16 3000 Max. 3.90 3.40 7.6:1 6.6:1 11 10000 11 3000 Max. 5.70 5.00 7.6:1 2.4:1 11 15000 11 3000 Max. 9.30 8.10 7.6:1 3.24:1 13-5/8 3000 13-5/8 3000 Max. 5.90 4.90 5.2:1 2.1:1 13-5/8 5000 13-5/8 3000 Max. 5.90 5.20 5.2:1 2.1:1 13-5/8 10000 13-5/8 3000 Max. 12.90 11.80 10.6:1 3.8:1 13-5/8 15000 13-5/8 3000 Max. 12.60 11.00 7.74:1 3.56:1 16-3/4 10000 16-3/4 3000 Max. 15.60 14.10 10.6:1 2.41:1 18-3/4 10000 18-3/4 3000 Max. 17.10 15.60 10.6:1 1.9:1 18-3/4 15000 18-3/4 3000 Max. 19.40 16.70 7.27:1 2.15:1 20-3/4 3000 20-3/4 3000 Max. 18.00 16.30 10.6:1 0.98:1 21-1/4 2000 21-1/4 3000 Max. 18.00 16.30 10.6:1 0.98:1 21-1/4 5000 21-1/4 3000 Max. 19.30 16.60 10.6:1 1.9:1 MPL 11 3000 11 3000 Max. 6.00 5.00 6.0:1 4.2:1 Shear 11 5000 11 3000 Max. 6.00 5.00 6.0:1 4.2:1 11 10000 11 3000 Max. 9.30 8.20 12.4:1 4.0:1 11 15000 11 3000 Max. 9.30 8.10 7.6:1 3.24:1 13-5/8 3000 13-5/8 3000 Max. 12.00 11.20 10.6:1 4.7:1 13-5/8 5000 13-5/8 3000 Max. 12.00 11.20 10.6:1 4.7:1 13-5/8 10000 13-5/8 3000 Max. 12.90 11.80 10.6:1 3.8:1 13-5/8 15000 13-5/8 3000 Max. 12.60 11.00 7.74:1 3.56:1 16-3/4 10000 16-3/4 3000 Max. 15.60 14.10 10.6:1 2.4:1 18-3/4 10000 18-3/4 3000 Max. 17.10 15.60 10.6:1 1.9:1 18-3/4 15000 18-3/4 3000 Max. 19.40 16.70 7.27:1 2.15:1 20-3/4 3000 20-3/4 3000 Max. 18.00 16.30 10.6:1 2.2:1 21-1/4 2000 21-1/4 3000 Max. 18.00 16.30 10.6:1 2.2:1 21-1/4 5000 21-1/4 3000 Max. 19.30 16.60 10.6:1 1.9:1

WELL CONTROL MANUAL




Bowen Tools, Inc. 51922 2-1/2 Sgl 5000 2-1/2 1000 0.17 0.14 7.9:1 51923 2-1/2 Sgl 10000 2-1/2 1600 0.26 0.18 7.9:1 51924 2-1/2 Twin 5000 2-1/2 900 0.35 0.27 7.9:1 60701 2-1/2 Twin 10000 2-1/2 1600 0.52 0.36 7.9:1 50460 2-9/16 Sgl 15000 2-9/16 1200 0.30 0.30 8.18:1 70051 2-9/16 Sgl 20000 2-9/16 800 0.87 0.93 23.8:1 51926 3 Sgl 5000 3 600 0.27 0.22 13.2:1 51927 3 Sgl 10000 3 1200 0.27 0.22 13.2:1 51928 3 Twin 5000 3 600 0.53 0.43 13.2:1 51929 3 Twin 10000 3 1200 0.53 0.43 13.2:1 61040 4 Sgl 5000 4 500 0.93 0.78 15.3:1 61044 4 Sgl 10000 4 1000 0.93 0.78 15.3:1 61048 4 Twin 5000 4 500 1.86 1.55 15.3:1 61050 4 Twin 10000 4 1000 1.86 1.55 15.3:1 47034 4-1/16 Sgl 10000 4-1/16 1000 0.43 0.34 13.6:1 60467 4-1/16 Sgl 15000 4-1/16 1250 0.69 0.74 16.2:1 70630 4-1/16 Twin 15000 4-1/16 1250 1.38 1.48 16.2:1 61053 4 1/2 Sgl 3000 4 1/2 400 0.90 0.81 15.3:1 66174 4 1/2 Sgl 5000 4 1/2 555 1.83 1.64 15.3:1 61055 4 1/2 Sgl 10000 4 1/2 1000 0.90 0.81 15.3:1 61507 4 1/2 Twin 5000 4 1/2 500 1.79 1.61 15.3:1 61060 4 1/2 Twin 10000 4 1/2 1000 1.79 1.61 15.3:1 51938 5-1/2 Sgl 3000 5-1/2 300 1.23 1.05 20.8:1 63642 7-1/16 Sgl 10000 7-1/16 900 1.02 1.10 16.2:1 70466 7-1/16 Twin 10000 7-1/16 900 2.04 2.20 16.2:1 60615 7-5/8 Sgl 5000 6-1/2 900 1.75 1.74 10.9:1 70399 7-5/8 Twin 5000 6-1/2 1800 3.50 3.48 10.9:1

Cameron Iron Works, Inc. U 6 3000 7-1/16 1500/5000 1.22 1.17 6.9:1 2.3:1 U 6 5000 7-1/16 1500/5000 1.22 1.17 6.9:1 2.3:1 U-Shear 6 5000 7-1/16 1500/5000 1.54 1.48 6.9:1 2.3:1 U 7-1/16 10000 7-1/16 1500/5000 1.22 1.17 6.9:1 2.3:1 U 7-1/16 15000 7-1/16 1500/5000 1.22 1.17 6.9:1 2.3:1 U 10 3000 11 1500/5000 3.31 3.16 7.3:1 2.5:1 U 10 5000 11 1500/5000 3.31 3.16 7.3:1 2.5:1 U-Shear 10 5000 11 1500/5000 4.23 4.03 7.3:1 2.5:1 U 11 10000 11 1500/5000 3.31 3.16 7.3:1 2.5:1 U-Shear 11 10000 11 1500/5000 4.23 4.03 7.3:1 2.5:1 U 11 15000 11 1500/5000 5.54 5.42 9.9:1 2.2:1 U 12 3000 13-5/8 1500/5000 5.54 5.20 7.0:1 2.3:1 U 13-5/8 5000 13-5/8 1500/5000 5.54 5.42 7.0:1 2.3:1 U-Shear 13-5/8 5000 13-5/8 1500/5000 6.78 6.36 7.0:1 2.3:1

WELL CONTROL MANUAL




Cameron Iron Works (continued) U 13-5/8 10000 13-5/8 1500/5000 5.54 5.42 7.0:1 2.3:1 U-Shear 13-5/8 10000 13-5/8 1500/5000 6.78 6.36 7.0:1 2.2:1 U 13-5/8 15000 13-5/8 1500/5000 11.70 11.28 6.6:1 8.9:1 U 16-3/4 3000 16-3/4 1500/5000 10.16 9.45 6.8:1 2.3:1 U 16-3/4 5000 16-3/4 1500/5000 10.16 9.45 6.8:1 2.3:1 U-Shear 16-3/4 5000 16-3/4 1500/5000 12.03 11.19 6.8:1 1.9:1 U 18-3/4 10000 18-3/4 1500/5000 21.20 23.10 7.4:1 3.7:1 U 20 3000 20-3/4 1500/5000 8.40 7.90 7.0:1 1.3:1 U-Shear 20 3000 20-3/4 1500/5000 9.35 8.77 7.0:1 1.2:1 U 21-1/4 2000 21-1/4 1500/5000 8.40 7.90 7.0:1 1.3:1 U-Shear 21-1/4 2000 21-1/4 1500/5000 9.35 8.77 7.0:1 1.2:1 U 21-1/4 7500 21-1/4 1500/5000 20.41 17.78 5.5:1 3.0:1 U-Shear 21-1/4 7500 21-1/4 1500/5000 23.19 20.20 6.5:1 2.3:1 U 21-1/4 10000 21-1/4 1500/5000 26.54 24.14 7.2:1 4.1:1 U-Shear 21-1/4 10000 21-1/4 1500/5000 30.15 27.42 7.2:1 3.1:1 U 26 2000 26-3/4 1500/5000 10.50 9.84 7.0:1 1.0:1 U 26 3000 26-3/4 1500/5000 10.50 9.84 7.0:1 1.0:1 U-Blind 13-5/8 5000 13-5/8 1500/2500 11.60 10.90 14.0:1 2.3:1 with 13-5/8 10000 13-5/8 1500/2500 11.60 10.90 14.0:1 2.3:1 Shear 16-3/4 3000 16-3/4 1500/2500 10.80 11.70 9.0:1 1.4:1 Booster 16-3/4 5000 16-3/4 1500/2500 10.80 11.70 9.0:1 1.4:1 20 2000 20-3/4 1500/2500 16.80 15.70 14.0:1 1.2:1 20 3000 20-3/4 1500/2500 16.80 15.70 14.0:1 1.2:1 U II 18-3/4 10000 18-3/4 24.70 22.30 6.7:1 2.5:1 U II 18-3/4 15000 18-3/4 34.70 32.30 9.3:1 3.5:1 QRC 6 3000 7-1/16 1500/3000 0.81 0.95 7.75:1 1.5:1 QRC 6 5000 7-1/16 1500/3000 0.81 0.95 7.75:1 1.5:1 QRC 8 3000 9 1500/3000 2.36 2.70 9.05:1 1.83:1 QRC 8 5000 9 1500/3000 2.36 2.70 9.05:1 1.83:1 QRC 10 3000 11 1500/3000 2.77 3.18 9.05:1 1.21:1 QRC 10 5000 11 1500/3000 2.77 3.18 9.05:1 1.21:1 QRC 12 3000 13-5/8 1500/3000 4.42 5.10 8.64:1 1.07:1 QRC 16 2000 16-3/4 1500/3000 6.00 7.05 8.64:1 .62:1 QRC 18 2000 17-3/4 1500/3000 6.00 7.05 8.64:1 .62:1 QRC 20 2000 17-3/4 1500/3000 6.00 7.05 8.64:1 .62:1 SS 6 3000 7-1/16 1500/3000 0.80 0.70 3.8:1 1.0:1 SS 6 5000 7-1/16 1500/3000 0.80 0.70 3.8:1 1.0:1 SS 8 3000 9 1500/3000 1.50 1.30 3.9:1 1.0:1 SS 8 5000 9 1500/3000 1.50 1.30 3.9:1 1.0:1 SS 10 3000 11 1500/3000 1.50 1.30 3.9:1 1.0:1 SS 10 5000 11 1500/3000 1.50 1.30 3.9:1 1.0:1 SS 12 3000 13-5/8 1500/3000 2.90 2.50 3.7:1 1.0:1 SS 14 5000 13-5/8 1500/3000 2.90 2.50 3.7:1 1.0:1

WELL CONTROL MANUAL




Cameron Iron Works (continued) Type F 6 3000 7-1/16 500/1500 1.50 2.30 4.5:1 with 6 5000 7-1/16 500/1500 1.50 2.30 4.5:1 Type W2 7 10000 7-1/16 500/1500 1.50 2.30 4.5:1 Operator 7 15000 7-1/16 500/1500 1.50 2.30 4.5:1 8 3000 9 500/1500 2.80 3.70 2.5:1 8 5000 9 500/1500 2.80 3.70 2.5:1 10 3000 11 500/1500 2.80 3.70 2.5:1 10 5000 11 500/1500 2.80 3.70 2.5:1 11 10000 11 500/1500 2.80 3.70 2.5:1 12 3000 13-5/8 500/1500 4.10 5.30 2.0:1 14 5000 13-5/8 500/1500 4.10 5.30 2.0:1 16 2000 16-3/4 500/1500 5.00 6.00 2.0:1 16 3000 16-3/4 500/1500 5.00 6.00 2.0:1 20 2000 20-1/4 500/1500 5.00 6.00 2.0:1 20 3000 20-1/4 500/1500 5.00 6.00 2.0:1

Type F 6 3000 7-1/16 500/1500 2.30 3.05 4.5:1 with 6 5000 7-1/16 500/1500 2.30 3.50 4.5:1 Type W 7 10000 7-1/16 500/1500 2.30 3.50 4.5:1 Operator 7 15000 7-1/16 500/1500 2.30 3.50 4.5:1 8 3000 9 500/1500 3.70 4.60 2.5:1 8 5000 9 500/1500 3.70 4.60 2.5:1 10 3000 11 500/1500 3.70 4.60 2.5:1 10 5000 11 500/1500 3.70 4.60 2.5:1 11 10000 11 500/1500 3.70 4.60 2.5:1 12 3000 13-5/8 500/1500 6.80 8.10 2.0:1 14 5000 13-5/8 500/1500 6.80 8.10 2.0:1 16 2000 16-3/4 500/1500 7.60 9.10 2.0:1 16 3000 16-3/4 500/1500 7.60 9.10 2.0:1 20 2000 20-1/4 500/1500 7.60 9.10 2.0:1 20 3000 20-1/4 500/1500 7.60 9.10 2.0:1

Type F 6 3000 7-1/16 250/1500 3.97 3.46 4.9:1 with 6 5000 7-1/16 250/1500 3.97 3.46 4.9:1 Type L 7 10000 7-1/16 250/1500 3.97 3.46 4.9:1 Operator 7 15000 7-1/16 250/1500 3.97 3.46 4.9:1 8 3000 9 250/1500 6.85 6.19 3.44:1 8 5000 9 250/1500 6.85 6.19 3.44:1 10 3000 11 250/1500 6.85 6.19 3.44:1 10 5000 11 250/1500 6.85 6.19 3.44:1 11 10000 11 250/1500 6.85 6.19 3.44:1 12 3000 13-5/8 250/1500 10.30 9.38 2.3:1 14 5000 13-5/8 250/1500 10.30 9.38 2.3:1 16 2000 16-3/4 250/1500 11.71 10.66 2.3:1 16 3000 16-3/4 250/1500 11.71 10.66 2.3:1 20 2000 20-1/4 250/1500 11.71 10.66 2.3:1 20 3000 20-1/4 250/1500 11.71 10.66 2.3:1

WELL CONTROL MANUAL




Type F 6 3000 7-1/16 1000/5000 0.52 1.50 1.5:1 with 6 5000 7-1/16 1000/5000 0.52 1.50 1.5:1 Type H 7 10000 7-1/16 1000/5000 0.52 1.50 1.5:1 Operator 7 15000 7-1/16 1000/5000 0.52 1.50 1.5:1 8 3000 9 1000/5000 0.90 1.80 1.0:1 8 5000 9 1000/5000 0.90 1.80 1.0:1 10 3000 11 1000/5000 0.90 1.80 1.0:1 10 5000 11 1000/5000 0.90 1.80 1.0:1 11 10000 11 1000/5000 0.90 1.80 1.0:1 12 3000 13-5/8 1000/5000 1.52 2.70 2.3:1 14 5000 13-5/8 1000/5000 1.52 2.70 2.3:1 16 2000 16-3/4 1000/5000 1.73 3.08 2.3:1 16 3000 16-3/4 1000/5000 1.73 3.08 2.3:1 20 2000 20-1/4 1000/5000 1.73 3.08 2.3:1 20 3000 20-1/4 1000/5000 1.73 3.08 2.3:1

Guiberson Division of Dresser Industries Hc 6 3000 7-3/8 2000 1.10 0.94 6.5:1 1.0:1 Hyd. Cyl. 8 2000 9 -1/16 2000 1.10 0.94 6.5:1 1.0:1

Shaffer LWS w/ 4-1/16 10000 4-1/16 1500/3000 0.59 0.52 8.45:1 4.74:1 Manual 6 5000 6 1500/3000 1.19 0.99 4.45:1 1.82:1 Lock 7-1/16 10000 7-1/16 1500/3000 6.35 5.89 10.63:1 19.4:1 7-1/16 15000 7-1/16 1500/3000 6.35 5.89 10.63:1 19.4:1 8 5000 8 1500/3000 2.58 2.27 5.57:1 3.00:1 10 3000 10 1500/3000 1.74 1.45 4.45:1 1.16:1 10 5000 10 1500/3000 2.98 2.62 5.57:1 2.09:1 11 10000 11 1500/3000 8.23 7.00 7.11:1 3.44:1 12 3000 12 1500/3000 4.35 5.30 8.16:1 1.74:1 13-5/8 5000 13-5/8 1500/3000 4.35 5.30 8.16:1 1.74:1 13-5/8 10000 13-5/8 1500/3000 11.56 10.52 10.85:1 3.48:1 16-3/4 5000 16-3/4 1500/3000 13.97 12.71 10.85:1 3.61:1 20 2000 21-1/4 1500/3000 5.07 4.46 5.57:1 .78:1 20 3000 21-1/4 1500/3000 5.07 4.46 5.57:1 .78:1

LWP 6 3000 7-1/16 1500/3000 0.55 0.51 —— —— Series 8 3000 9 1500/3000 7.80 6.86 —— ——

LWP 6 3000 7-1/16 1500/3000 0.55 0.51 4.0:1 2.50:1 Type 8 3000 9 1500/3000 0.77 0.68 4.0:1 1.81:1 SL and 11 10000 11 1500/3000 8.23 7.00 7.11:1 3.44:1 LWS 13-5/8 5000 13-5/8 1500/3000 4.35 5.30 8.16:1 1.74:1 Posilock 13-5/8 5000 13-5/8 1500/3000 11.56 10.52 10.85:1 3.48:1 13-5/8 10000 13-5/8 1500/3000 10.58 10.52 7.11:1 3.48:1 13-5/8 15000 13-5/8 1500/3000 11.56 10.52 7.11:1 2.14:1

WELL CONTROL MANUAL




Shaffer (continued) LWP 16-3/4 5000 16-3/4 1500/3000 13.97 12.60 11.85:1 2.45:1 Type 16-3/4 10000 16-3/4 1500/3000 14.47 12.50 7.11:1 2.06:1 SL and 18 3/4 10000 18 3/4 1500/3000 15.30 13.21 7.11:1 1.83:1 LWS 18-3/4 15000 18-3/4 1500/3000 14.62 13.33 Posilock 20 2000 21-1/4 1500/3000 7.80 6.86 8.16:1 1.15:1 20 2000 21-1/4 1500/3000 16.88 15.35 10.85:1 2.52:1 20 3000 21-1/4 1500/3000 7.80 6.86 8.16:1 1.15:1 20 3000 21-1/4 1500/3000 16.88 15.35 10.85:1 2.52:1 21-1/4 10000 21-1/4 1500/3000 16.05 13.86 7.11:1 1.63:1

Sentinel 6 3000 7-1/16 1500/3000 0.29 0.28 —— ——

Type 6 3000 7-1/16 1500/3000 2.75 2.30 6.0:1 2.57:1 B and E 6 5000 7-1/16 1500/3000 2.75 2.30 6.0:1 2.57:1 8 3000 9 1500/3000 2.75 2.30 6.0:1 1.89:1 8 5000 9 1500/3000 2.75 2.30 6.0:1 1.89:1 10 3000 11 1500/3000 3.25 2.70 6.0:1 1.51:1 10 5000 11 1500/3000 3.25 2.70 6.0:1 1.35:1 12 3000 13-5/8 1500/3000 3.55 2.90 6.0:1 1.14:1 14 5000 13-5/8 1500/3000 3.55 2.90 6.0:1 1.14:1 16 2000 15-1/2 1500/3000 3.65 3.00 6.0:1 1.05:1

WELL CONTROL MANUAL



Annular Blowout Preventers Hydraulic Model Nominal Working Vertical Operating Gallons Gallons Secondary or Size Pressure Bore Pressure to to Volume Type (Inches) (Max PSI) (Inches) (psi) Close Open (Gallons)

Hydril Company GK 6 3000 7-1/16 1500 2.85 2.24 GK 6 5000 7-1/16 1500 3.86 3.30 GK —— 10000 7-1/16 1500 9.42 11.20 GK —— 15000 7-1/16 1500 11.20 10.90 GK —— 20000 7-1/16 1500 10.90 7.20 GK 8 3000 9 1500 4.33 3.41 GK 8 5000 9 1500 6.84 5.80 GK —— 10000 9 1500 15.90 11.95 GK 10 3000 11 1500 7.43 5.54 GK 10 5000 11 1500 9.81 7.98 GK —— 10000 11 1500 25.10 18.97 GK —— 10/15000 11 1500 26.67 20.45 GK 12 3000 13-5/8 1500 11.36 8.94 GK —— 5000 13-5/8 1500 17.98 14.16 GK —— 10000 13-5/8 1500 37.18 26.50 GK 16 2000 16-3/4 1500 17.46 12.59 GK 16 3000 16-3/4 1500 21.02 15.80 GK —— 5000 16-3/4 1500 28.70 19.93

GL —— 5000 13-5/8 1500 19.76 19.76 8.24 GL —— 5000 16-3/4 1500 33.80 33.80 17.30 GL Dual —— 5000 16-3/4 1500 33.80 33.80 17.30 GL —— 5000 18 3/4 1500 44.00 44.00 20.00 GL Dual —— 5000 18 3/4 1500 44.00 44.00 20.00 GL —— 5000 21-1/4 1500 58.00 58.00 29.50

GX 11 10000 11 1500 17.88 17.88 GX 11 15000 11 1500 24.14 24.14 GX 13-5/8 10000 13-5/8 1500 24.14 24.14 GX 13-5/8 15000 13-5/8 1500 34.00 34.00 GX 18-3/4 10000 18-3/4 1500 58.00 58.00

MSP 6 2000 7-1/16 1500 2.85 1.98 MSP 8 2000 9 1500 4.57 2.95 MSP 10 2000 11 1500 7.43 5.23 MSP 20 2000 20-3/4 1500 31.05 18.93 MSP 20 2000 21-1/4 1500 31.05 18.93 MSP 20 2000 HL21-1/4 1500 31.75 19.25 MSP 29-1/2 500 29-1/2 1500 60.00 —— MSP 30 1000 30 1500 87.60 27.80

WELL CONTROL MANUAL



Hydraulic Model Nominal Working Vertical Operating Gallons Gallons Secondary or Size Pressure Bore Pressure to to Volume Type (Inches) (Max PSI) (Inches) (psi) Close Open (Gallons)

Cameron Iron Works A 6 5000 7-1/16 1500 2.20 1.90 A 6 10000 7-1/16 1500 4.00 3.10 A 6 15000 7-1/16 N.A. N.A. N.A. A 11 5000 11 1500 7.80 6.50 A 11 10000 11 1500 12.10 10.50 A 11 15000 11 N.A. N.A. N.A. A 13-5/8 5000 13-5/8 1500 15.50 13.90 A 13-5/8 10000 13-5/8 1500 21.50 18.70 A 16-3/4 5000 16-3/4 1500 33.00 29.00

D 6 5000 7-1/16 3000 1.69 1.39 D 7-1/16 10000 7-1/16 3000 2.94 2.55 D 10 5000 11 3000 5.65 4.69 D 11 10000 11 3000 10.15 9.06 D 13-5/8 5000 13-5/8 3000 12.12 10.34 D 13-5/8 10000 13-5/8 3000 18.10 16.15

Shaffer

Spherical 6 3000 7-1/16 1500 4.57 3.21 BOP 6 5000 7-1/16 1500 4.57 3.21 7-1/16 10000 7-1/16 1500 17.11 13.95 8 3000 9 1500 7.23 5.03 8 5000 9 1500 11.05 8.72 10 3000 11 1500 11.00 6.78 10 5000 11 1500 18.67 14.59 11 10000 11 1500 30.58 24.67 12 3000 13-5/8 1500 23.50 14.67 13-5/8 5000 13-5/8 1500 23.58 17.41 13-5/8 10000 13-5/8 1500 40.16 32.64 16-3/4 5000 16-3/4 1500 33.26 25.61 18 3/4 5000 18 3/4 1500 48.16 37.61 20 2000 21-1/4 1500 32.59 16.92 21-1/4 5000 21-1/4 1500 61.37 47.76

Regan K 3 3000 3 3000 0.50 K 4 3000 4 3000 0.80 K 7 3000 6 1/4 3000 1.60 K 8 5/8 3000 7 7/8 3000 4.10 K 9 5/8 3000 8 7/8 3000 5.70 K 10 3/4 3000 10 3000 7.60 K 11 3/4 (old) 3000 10 7/8 3000 11.10 K 11 3/4 (new) 3000 11 1/8 3000 10.30 K 13 3/8 3000 12 3/8 3000 15.30 K 13 3/4 3000 13 3/4 3000 19.90

WELL CONTROL MANUAL



Hydraulic Model Nominal Working Vertical Operating Gallons Gallons Secondary or Size Pressure Bore Pressure to to Volume Type (Inches) (Max PSI) (Inches) (psi) Close Open (Gallons)

Regan (continued) K 16 3000 15 3/8 3000 25.00 K 18 5/8 3000 17 1/2 3000 29.50 KFD 16 500 10 1000 3.00 KFD 18 3/4 500 10 1000 3.00 KFD 20 500 10 1000 3.00 KFD 22 500 10 1000 3.00 KFD 24 500 10 1000 3.00 KFDJ 27 1/2 2000 10 2500 3.00

KFL 13-5/8 3000 13-5/8 Well + 500 19.50 KFL 13-5/8 5000 13-5/8 Well + 500 22.00 KFL 13-5/8 10000 13-5/8 Well + 500 24.50 KFL 16-3/4 3000 16-3/4 Well + 500 25.75 KFL 16-3/4 5000 16-3/4 Well + 500 29.00 KFL 16-3/4 10000 16-3/4 Well + 500 31.50 KFL 20 2000 20-3/4 Well + 500 28.50 KFL 20 3000 20-3/4 Well + 500 32.00 KFL 20 5000 20-3/4 Well + 500 35.00 KFL 30 1000 28 Well + 500 47.50 KFL 30 2000 28 Well + 500 52.00 KFL 30 1000 26-1/2 Well + 500 51.50 KFL 30 2000 26-1/2 Well + 500 56.00

Torus 6 3000 7-1/16 3000 4.50 Torus 6 6000 7-1/16 3000 4.50 Torus 8 3000 9 3000 8.25 Torus 8 6000 9 3000 8.25

WELL CONTROL MANUAL



Hydraulically Operated Valves

Hydraulic Model Line Working Bore Operating Gallons Gallons or Size Pressure Size Pressure to to Type (Inches) (Max PSI) (Inches) (psi) Close Open

Cameron Iron Works HCR 4 3000 4 1500 0.52 0.61 HCR 4 5000 4 1500 0.52 0.61 HCR 6 3000 7 1500 1.95 2.25 HCR 6 5000 7 1500 1.95 2.25

F 2 960-3000 1 13/16 1500/5000 0.10 0.10 F 2 5000-15000 1 13/16 1500/5000 0.16 0.16 F 2 960-3000 2-1/16 1500/5000 0.10 0.10 F 2 5000-15000 2-1/16 1500/5000 0.16 0.16 F 2-1/2 960-3000 2-9/16 1500/5000 0.13 0.13 F 2-1/2 5000-15000 2-9/16 1500/5000 0.20 0.20 F 2-1/2 960-3000 2-9/16 1500/5000 0.20 0.20 F 2-1/2 15000 2-9/16 1500/5000 0.40 0.40 F 3 960-2000 3-1/8 1500/5000 0.15 0.15 F 3 3000-5000 3-1/8 1500/5000 0.24 0.24 F 3 10000 3-1/8 1500/5000 0.28 0.28 F 3 15000 3-1/8 1500/5000 0.49 0.49 F 4 2000-5000 4-1/8 1500/5000 0.30 0.30 F 4 10000 4-1/8 1500/5000 0.59 0.59 F 6 2000-5000 6-1/8 1500/5000 0.84 0.84

DV 4 3000 4 1500 1.10 0.80 DV 4 5000 4 1500 1.10 0.80 DV 6 3000 7 1500 3.60 2.10 DV 8 3000 9 1500 5.60 2.40 DV 10 3000 11 1500 11.40 5.70 DV 10 5000 11 1500 11.40 5.70 DV 12 3000 13-5/8 1500 22.70 11.80

McEvoy Oilfield Equipment

AC Valve 2 2000 2500 0.11 0.13 w/ U-1 2 3000 2500 0.11 0.13 Hyd. 2 5000 2500 0.11 0.13 Oper. 2 10000 2500 0.20 0.21 2-1/2 2000 2500 0.23 0.26 2-1/2 3000 2500 0.23 0.26 2-1/2 5000 2500 0.23 0.26 2-1/2 10000 2500 0.42 0.45 3 2000 2500 0.25 0.30 3 3000 2500 0.46 0.51

WELL CONTROL MANUAL




McEvoy Oil Field Equipment (continued) AC Valve 3 5000 2500 0.46 0.51 w/ U-1 4 2000 2500 0.62 0.69 Hyd. 4 3000 2500 0.62 0.69 Oper. 4 5000 2500 0.98 1.04

C Valve 2 5000 2-1/16 1500 0.10 0.11 with 2-1/2 5000 2-9/16 1500 0.12 0.13 RM-1 3 5000 3-1/8 1500 0.23 0.25 Actuator 4 5000 4-1/8 1500 0.44 0.50

E Valve 1-13/16 10000 1-13/16 1500 0.08 0.09 with 2-1/16 10000 2-1/16 1500 0.16 0.18 RM-1 2-9/16 10000 2-9/16 1500 0.30 0.33 Actuator 3-1/16 10000 3-1/16 1500 0.36 0.37 4-1/16 10000 4-1/16 1500 1.00 1.07

EDU and 3 5000 3-1/16 2500 0.47 0.52 EU Valve 3-1/16 10000 3-1/16 2500 0.47 0.52 with U-1 Actuator

Shaffer Flo-Seal 2 Reg. 2000 1-11/16 3000 0.20 0.20 2 2000 2-1/16 3000 0.20 0.20 2 Reg. 3000 1-11/16 3000 0.20 0.20 2 3000 2-1/16 3000 0.20 0.20 2 Reg. 5000 1-11/16 3000 0.20 0.20 2 5000 2-1/16 3000 0.20 0.20 2-1/16 10000 2-1/16 3000 0.40 0.40 2-1/16 15000 2-1/16 3000 0.40 0.40 2-1/2 2000 2-9/16 3000 0.30 0.30 2-1/2 3000 2-9/16 3000 0.30 0.30 2-1/2 5000 2-9/16 3000 0.30 0.30 3 2000 3-1/8 3000 0.30 0.30 3 3000 3-1/8 3000 0.30 0.30 3 5000 3-1/8 3000 0.30 0.30 3-1/16 10000 3-1/16 3000 0.60 0.60 4 3000 4-1/16 3000 0.80 0.80 4 5000 4-1/16 3000 0.80 0.80 4-1/16 10000 4-1/16 3000 1.30 1.30 6 3000 7-1/16 3000

WELL CONTROL MANUAL




Shaffer (continued) Flo-Seal 2 Reg. 2000 1-11/16 3000 0.30 0.30 with 2 2000 2-1/16 3000 0.30 0.30 Ramlock 2 Reg. 3000 1-11/16 3000 0.30 0.30 2 3000 2-1/16 3000 0.30 0.30 2 Reg. 5000 1-11/16 3000 0.30 0.30 2 5000 2-1/16 3000 0.30 0.30 2-1/16 10000 2-1/16 3000 0.40 0.40 2-1/16 15000 2-1/16 3000 0.40 0.40 2-1/2 2000 2-9/16 3000 0.30 0.30 2-1/2 3000 2-9/16 3000 0.30 0.30 2-1/2 5000 2-9/16 3000 0.30 0.30 3 2000 3-1/8 3000 0.40 0.40 3 3000 3-1/8 3000 0.40 0.40 3 5000 3-1/8 3000 0.40 0.40 3-1/16 10000 3-1/16 3000 0.60 0.60 4 3000 4-1/16 3000 0.80 0.80 4 5000 4-1/16 3000 0.80 0.80 4-1/16 10000 4-1/16 3000 0.80 0.80 6 3000 7-1/16 3000

CB 3 5000 3-1/8 3000 0.00 0.45 Subsea 3-1/16 10000 3-1/16 3000 0.00 0.50 Failsafe Long Sea Chest

CB 3 5000 3-1/8 3000 0.43 0.45 Subsea 3-1/16 10000 3-1/16 3000 0.45 0.50 Failsafe Short Sea Chest

Type DB 3 3000 3-1/8 3000 0.30 0.30 3 5000 3-1/8 3000 0.30 0.30 3-1/16 10000 3-1/16 3000 0.60 0.60 4 3000 4-1/16 3000 0.80 0.80 4 5000 4-1/16 3000 0.80 0.80 4-1/16 10000 4-1/16 3000 1.30 1.30 6 3000 7-1/16 3000 2.00 2.00

WELL CONTROL MANUAL

Drilling & Workover October 2002 __ SECTION Q – WELL CONTROL EQUATIONS

Current Revision: October 2002 Q - 1 3rd Edition Previous Revision: October 1998

WELL CONTROL

EQUATIONS

WELL CONTROL MANUAL



1. Pressure (psi)

Force (lb) __________ = psi

Area (in2) 2. Pressure Gradient (psi/ft) 0.007 x Mud Weight (pcf) = (psi/ft) 3. Hydrostatic Pressure (psi)

a. 0.007 x Mud Weight (pcf) x True Vertical Depth, TVD (ft) = psi Hydrostatic Pressure (psi) b. Mud Weight (pcf) = ______________________________________

0.007 x True Vertical Depth, TVD (ft)

Hydrostatic Pressure (psi) c. True Vertical Depth, TVD (ft) = _____________________________

0.007 x Mud Weight (pcf) 4. Equivalent Density (pcf)

Pressure (psi) _______________ = pcf

0.007 x TVD (ft)

5. Formation Pressure (psi) Hydrostatic Pressure in Drill Pipe (psi) + SIDPP (psi) = psi 6. Density to Balance Formation (pcf) Kill Mud Weight, KMW (pcf) =

SIDPP (psi) ________________ + Original Mud Weight (pcf) = pcf

0.007 x TVD (ft)

WELL CONTROL MANUAL



7. Equivalent Mud Weight, EMW (pcf)

Leak-Off Pressure (psi) _____________________________ + Leak-Off Mud Wt (pcf) = pcf

0.007 x Casing Shoe TVD (ft) 8. Maximum Allowable Surface Pressure, MASP (psi) (based on casing burst)

Casing Internal Yield (psi) x .80 (safety factor) = psi 9. Maximum Initial Shut-In Casing Pressure, MISICP (psi)

Upon initial closure only-based on formation breakdown @ shoe. For IWCF, written as MAASP.

[ EMW (pcf) - Present Mud Wt (pcf) ] x 0.007 x Shoe TVD (ft) = psi 10. Initial Circulating Pressure (psi)……… (ENGINEER’S & DRILLER’S METHODS) SIDPP (psi) + Slow Pump Rate Pressure, SPRP (psi) = psi 11. Final Circulating Pressure (psi)………. (ENGINEER’S METHOD)

Kill Mud Wt (pcf) SPRP (psi) x _________________________ = psi

Original Mud Wt (pcf) 12. Equivalent Circulating Density, ECD (pcf)

Annular Pressure Loss (psi) _____________________________ + Mud Wt (pcf) = pcf

0.007 x TVD Bit (ft) 13. Gas Pressure and Volume Relationship - Boyle’s Law P1V1 = P2V2

The pressure (P1, psi) of a gas bubble times its volume (V1, bbl) in one part of the hole equals its pressure (P2, psi) times its volume (V2, bbl) in another.

This disregards the effects of temperature (T) and gas compressibility (z).

WELL CONTROL MANUAL



14. Pump Output (bbl/min)

bbl strokes bbl ______ x ________ = ______

stroke min min 15. 100% Triplex Pump Capacity (bbl/stroke)

[ Liner ID (in) ]2 Stroke Length (in) bbl ______________ x _________________ x 3 = _______

1029 12 stroke 16. Surface To Bit Strokes (strokes) Drill String Internal Volume(bbl) = strokes bbl/stroke 17. Circulating Time (min) Volume (bbl) = min Pump Output (bbl/min) 18. Open Hole Capacity Factor (bbl/ft) [ Open Hole Diameter (in) ]2 = bbl

1029 ft 19. Pipe Capacity Factor (bbl/ft) [ Pipe Inside Diameter (in) ]2 = bbl

1029 ft

WELL CONTROL MANUAL



20. Annulus Capacity Factor, ACF (bbl/ft) [ Open Hole Diameter (in) ]2 - [ Pipe Outside Diameter (in) ] 2 = bbl

1029 ft or [ Casing Inside Diameter (in) ]2 - [ Pipe Outside Diameter (in) ] 2 = bbl

1029 ft 21. Pipe Displacement (bbl/ft) (disregarding tool joints) [ Pipe Outside Diameter (in) ]2 - [ Pipe Outside Diameter (in) ] 2 = bbl

1029 ft 22. Total Pipe Displacement (bbl/ft) (disregarding tool joints) [ Pipe Outside Diameter (in) ]2 = bbl

1029 ft 23. Height of Influx (ft) Pit Gain (bbl) = ft Annulus Capacity Factor (bbl/ft) 24. Pressure Gradient of Influx (psi/ft) (bit on bottom)

Pressure Gradient of Mud (psi/ft) -

−

(ft)Influx of Height

(psi) SIDPP(psi) SICP =

ftpsi

25. Rate of Kick Rise (ft/hr) (well shut-in)

Change in SICP (psi) = ft 0.007 x Mud Wt (pcf) x Elapsed Time for Change in SICP (hr) hr

WELL CONTROL MANUAL



26. Weight per Foot of Drill Collars (lb/ft)

2.67 x [ ] [ ]ft

lb (in) ID - (in) OD 22 =

27. Force (lb) Pressure (psi) x Area (in2) = lb 28. Area (in2) π x [ Diameter (in) ]2 = in2, where π = 3.142 4 29. Degrees API (@ 600F)

OAPI = 141.5 - 131.5 Specific Gravity 30. Specific Gravity (@ 600F) Specific Gravity = 141.5___ [oAPI + 131.5] 31. Mud Weight from Specific Gravity (pcf) Mud Weight = Specific Gravity x 62.4 pcf 32. Hang-Off Weight (lb) Weight of Block + Kelly Weight + Weight of Compensator + Air Weight of Drill Pipe (KB to Hang-Off Ram) + 10,000 lbs _____________

= Weight on Indicator after Hang-Off (lb)

WELL CONTROL MANUAL



33. Barite Requirement For Weight-up (100 lb sx)

Barite (sxs) = Volume to Weight-Up (bbls) x

KWM - 262.0

MW in Increase x 15

34. Cutting Back or Weighting Up One Fluid with Another to Obtain Desired Fluid

Density

Volume of Mixing Fluid to Add (bbls) =

Vol. of Starting Fluid (bbls) x

(pcf) WtFluid Mixing - (pcf) WtFluid Desired

(pcf) WtFluid Desired - (pcf) WtFluid Starting

35. Final Density of a Mixture of Fluid (pcf)

Final Fluid Wt (pcf) =

[ Fluid Wt 1 (pcf) x Volume Fluid 1 (cf) ] + [ Fluid Wt 2 (pcf) x Volume Fluid 2 (cf) ] Volume fluid 1 (cf) + Volume Fluid 2 (cf)

(where cf = 5.62 x bbls)

36. Final Density of a Mixture of Fluid and a Solid (pcf) Final Fluid Density (pcf) =

[ Fluid Density (pcf) x Volume Fluid (cf) ] + Weight of Solid Added (lb)

Volume Fluid (cf) +

(pcf) Solid ofDensity True

(lb) AddedSolid of Weight

37. Weight of Solid to Add to a Fluid to Obtain Desired Fluid Weight (lb)

Weight of Solid to Add (lb) = Volume of Starting Fluid (cf) x True Density of Solid (pcf)

x

(pcf) WtFluid Desired - (pcf) Solid ofDensity True

(pcf) WtFluid Starting - (pcf) WtFluid Desired

WELL CONTROL MANUAL



VOLUMETRIC CONTROL EQUATIONS

38. Pressure Increment, PI (psi)

PI = Safety Factor (psi) = psi 3

39. Fluid Increment, MI (bbl)

MI = PI (psi) x Annulus Capacity Factor (bbl/ft) = bbl 0.007 x Mud Wt (pcf) 40. Rate of Bubble Rise, ROR (ft/hr) (see Equation 25 above)

ROR = Change in Casing Pressure (psi)__________ = ft 0.007 x Mud Wt (pcf) x Elapsed Time for Change (hr) hr 41. Time to Bubble Penetration, BPT (hr)

BPT = Depth of Bubble (ft) – Depth of Bit (ft) = hr ROR (ft/hr) + Stripping Speed (ft/hr) LUBRICANT AND BLEED EQUATION 42. Pressure That Can be Bled Off after Lubricating in a Given Volume of Fluid (psi)

Volume Lubricated (bbl) x 0.007 x Fluid Wt (pcf)_ = psi Capacity Factor (bbl/ft)

WELL CONTROL MANUAL



STRIPPING AND SNUBBING EQUATIONS STRIPPING

43. Pressure Area Force, Fp (lb) Fp = π x [ OD (in) ]2 x Well Head Pressure (psi)

4

44. Buoyed Weight of Tubulars, W (lb) W = WAIR (lb) x

489

(pcf) WtMud - 489

[ OD (in) ]2

45. Barrels to Bleed per Stand (bbls/stand) Bbl/Stand = ___________ x Stand Length (ft) 1029 46. Volumetric Control Considerations

Pressure Increment, PI (psi) (see Equation 37 above) Fluid Increment, MI (bbl) (see Equation 38 above) Surface Pressure Increase due to Penetration of the Bubble, SPINCR (psi) ( ) ( ) psi PG- PG x L- L GASMUD (OH) kk(DPxOH) =

Open Hole Kick Length, Lk (OH) (ft) Kick Volume at Penetration (bbl) LK(OH) = ________________________________

ACFOH (bbl/ft)

DP by Hole Kick Length, Lk (DPx OH) (ft) Kick Volume at Penetration (bbl) LK(DPxOH) = ________________________________

ACFDPXOH (bbl/ft) Rate of Bubble Rise, ROR (ft/hr) (see Equation 40 above) Time of Bubble Penetration, BPT (hrs) (see Equation 41 above)

WELL CONTROL MANUAL



SNUBBING 47. Snub Force, SF (lb) SF = Fp + Friction Force – W 48. Neutral Point SF = 0; Fp = W

W (lb) 49. Effective String Weight, WE (lb/ft) WE (lb/ft) = ______ L (ft) 50. Calculating Effective String Weight and Change in Effective String Weight

after Filling

a) Effective String Weight no Fluid in the workstring: WE (Effective String Wt, lb/ft) = String Wt (lb/ft) – [ OD (in) ]2 x Fluid Wt WELL (pcf) 183.3

Note: WE and String Wt both have units of lb/ft. For example, the string weight of 2-7/8” tubing normally would be 6.5 lb/ft.

b) Increase in the Effective String Weight after the pipe is filled with the same

Fluid Weight that is in the well: ∆ WE (lb/ft) = [ ID (in) ]2 x Fluid Wt WELL (pcf) 183.3

c) Increase in the Effective String Weight after the pipe is filled with a different Fluid Weight than the Fluid Weight that is in the well:

∆ WE (lb/ft) = [ ID (in) ]2 x Fluid Wt FILL (pcf) 183.3

d) After filling the pipe, the Effective String Weight will be:

WE (AFTER FILLING) (lb/ft) = WE + ∆ WE = String Wt (lb/ft) - [ OD (in) ]2 x Fluid Wt WELL (pcf) + [ ID (in) ]2 x Fluid Wt (pcf) 183.3 183.3

In this case, note that Fluid Wt in the last term above will be Fluid WtWell if filled with the same fluid, or Fluid Wtfill if filled with a different fluid weight.

WELL CONTROL MANUAL



51. Predicting the Neutral Point Combining Equations 47 and 48 above gives an equation for the length L (ft) or

pipe that must be run into the well to reach the Neutral Point: W (lb) Fp (lb) = W (lb) and WE (lb/ft) = _______ L (ft) Fp (lb) L (ft) = __________

WE (lb/ft)

a) The Neutral Point occurs in unfilled pipe when the length of pipe run into

the well is:

L (ft) = Fp (lb) ________________

String Wt (lb/ft) – [ OD (in) ]2 x Fluid WtWELL (pcf) 183.3

b) The Neutral Point occurs in filled pipe when the length of pipe run into the well is:

L (ft) = Fp (lb) _______________________________________

String Wt (lb/ft) – [ OD (in) ]2 x Fluid WtWELL (pcf) + [ ID (in) ]2 x Fluid Wt (pcf) 183.3 183.3

In this case, note that Fluid Wt in the final denominator term above will be Fluid WtWELL if filled with the same fluid, or Fluid WtFILL if filled with a different fluid weight.

WELL CONTROL MANUAL



ACCUMULATOR SIZING 52. Bottle Capacity Required (gals) Bottle Vol. (gals) = Volume Fluid Required (gals)_________________ Precharge Pressure Precharge Pressure ____________________________ - ____________________________

Minimum Operating Pressure Maximum Operating Pressure 53. Volume Useable Fluid Available (gals)

Volume Useable Fluid (gals) =

Precharge Pressure Precharge Pressure Bottle Volume x ____________________________ - _____________________________

Minimum Operating Pressure Maximum Operating Pressure

WELL CONTROL MANUAL

Drilling & Workover October 2002 SECTION R - WELL CONTROL POLICIES

Current Revision: October 2002 R - 1 3rd Edition Previous Revision: June 2001

Table of Contents

Well Control Certification Certification Requirements.................................................................. R - 5

BOP Equipment Requirements API Monogram .................................................................................... R - 5 OEM Certification ................................................................................ R - 5 Visual Inspection ................................................................................. R - 5 Elastomer Replacement...................................................................... R - 6 Maintenance Log................................................................................. R - 6 Elastomer Verification ......................................................................... R - 6 Spare Requirements on Rigsite .......................................................... R - 6 Connection Requirements................................................................... R - 7 Locking Devices for Rams .................................................................. R - 7

BOP Elastomer Ratings for H2S and Temperature Annulars .............................................................................................. R - 7 Fixed Rams......................................................................................... R - 7 Variable Bore Rams............................................................................ R - 7 Shear Blind Rams ............................................................................... R - 8

Use of Diverters Onshore Wells .................................................................................... R - 8 Offshore Wells .................................................................................... R - 8

Use of Shear Blind Rams Applications Requiring SBR ................................................................ R - 8 Size of Emergency Kill Line................................................................. R - 8

Emergency Kill Line Hook-Up (Onshore)............................................................................. R - 9 Hook-Up (Offshore)............................................................................. R - 9 Valves.................................................................................................. R - 9

Kill Line Hook-Up .............................................................................................. R - 9 Valves.................................................................................................. R - 9 Pressure Rating .................................................................................. R - 9

Connections on Kill, Emergency Kill, and Choke Lines Connection Requirements................................................................. R - 10 Use of Targeted Tees ....................................................................... R - 10 Use of Heavy Duty Elbows................................................................ R - 10 Use of Chiksans ................................................................................ R - 10 Use of Weco Connections ................................................................ R - 10

Minimum Bore on Kill, Emergency Kill, and Choke Lines Bore Requirements ........................................................................... R - 11

WELL CONTROL MANUAL



Utilizing Flexible Hose

For Choke Line, Kill Line, or Emergency Kill Line ............................ R - 11 Choke Manifolds

Specifications .................................................................................... R - 12 Workover Operations (3M)................................................................ R - 12

Flare Lines Oil Wells (Onshore)........................................................................... R - 12 Gas Wells (Onshore) ........................................................................ R - 12

Accumulators Manufacturer ..................................................................................... R - 13 Fluid Requirements ........................................................................... R - 13 Pre-Charge Requirements ................................................................ R - 13 Closing Requirements....................................................................... R - 13

Back-up Charging System ................................................................ R - 13 Location............................................................................................. R - 13

Pressure Testing BOP Equipment Frequency of Pressure Test.............................................................. R - 14 Minimum Duration of Pressure Test ................................................. R - 14 Pressure Test Fluid ........................................................................... R - 14 Low Pressure Test ............................................................................ R - 14 High Pressure Test ........................................................................... R - 14 Pressure Test Requirements on Deep Gas Wells ............................ R - 14 Pressure Testing Annular.................................................................. R - 15 Use of Test Stump ............................................................................ R - 15 Pressure Testing Wellhead Valves ................................................... R - 15 Documenting Pressure Test Charts.................................................. R - 15 Pressure Testing Higher WP Equipment than Required .................. R - 15 Pressure Testing Accumulator Hydraulic Lines ................................ R - 15

Leak between BOP Stack and Casing Head .................................... R - 16 Drill Pipe Float

Running a Drill Pipe Float.................................................................. R - 16 Gas Busters

Minimum Size Requirements for Oil Rigs ......................................... R - 16 Minimum Size Requirements for Gas Rigs ....................................... R - 17 Encountering Loss Circulation

Loss of Returns in Hydrocarbon-Bearing Zone................................. R - 17 Maintaining Minimum Overbalance

General Requirements for Drilling and WO Applications .................. R - 17 Drilling the Arab-C Reservoir with Water .......................................... R - 18 Reducing Mud Weight to Free Differentially Stuck Pipe ................... R - 18

Isolating Khuff Reservoir Setting Casing at Top of Khuff Formation......................................... R - 18

Tapered String Working with a Tapered String.......................................................... R - 18

WELL CONTROL MANUAL



Space Out Data

Recording Space Out Data ............................................................... R - 18 Slow Pump Rate Data

Recording Slow Pump Rate Data ..................................................... R - 19 Tripping Pipe

Pulling Out of Hole ............................................................................ R - 19 Running In Hole................................................................................. R - 19

Performing Flow Checks While Drilling ..................................................................................... R - 19 While Tripping ................................................................................... R - 20 Displacing to Brine on Horizontal Wells ............................................ R - 20

Shutting In Well Shutting In Well without Flow Checking ............................................ R - 20 While Drilling ..................................................................................... R - 20 While Tripping ................................................................................... R - 21 With BHA across BOP Stack ............................................................ R - 21

Failure of Upper Pipe Rams During a Well Kill Operation Recommended Action....................................................................... R - 21

BOP Configuration When Running Casing Running Casing w/ Class ‘B’ 3M Stack ............................................. R - 21 Running Casing w/ Class ‘A’ 3M or 5M Stack................................... R - 22 Running Casing or 7” Liner w/ Class ‘A’ 10M Stack (w/o SBR) ........ R - 22 Running Casing w/ Class ‘A’ 10M Stack (w/ SBR)............................ R - 22 Running 7” Liner w/ Class ‘A’ 10M Stack (w/ SBR)........................... R - 22 Running 4-1/2” Liner w/ Class ‘A’ 10M Stack.................................... R - 22 Running 4-1/2” Pre-Perforated Liner w/ Class ‘A’ 10M Stack ........... R - 23 Shut-In on 4-1/2” Pre-Perforated Liner w/ Class ‘A’ 10M Stack ........ R - 23

Changing Rams or Installing Casing Rams Isolation Policy .................................................................................. R - 23

Pressure Testing Casing Rams ........................................................ R - 24 Installing Casing Slips

With Multi-Stage Cementing ............................................................. R - 24 BOP Configuration when Running Production Tubing

Running 5-1/2” or 5-1/2”x 4-1/2” w/ Class ‘A’ 10M Stack .................. R - 24 Running Dual Strings Simultaneously w/ Class ‘A’ 5M Stack ........... R - 25 BOP Configuration when Running Production Tubing/Packer Running Tubing/Packer Simultaneously w/ Class ‘A’ 3 or 5M Stack R - 25

Removing BOP Stack or Production Tree Isolation Policy for Low GOR Oil Wells ............................................. R - 25 Isolation Policy for High GOR Oil Wells ............................................ R - 25 Isolation Policy for Gas Wells............................................................ R - 25 Isolation Policy for WIW Wells .......................................................... R - 26

WELL CONTROL MANUAL



Rigging Down on High GOR Wells w/ SSSV

RD Procedure (w/ Little Clearance between Rig and Tree) .............. R - 26 Platform Well Security Prior to Workover Operations Required Number of Mechanical Barriers of Isolation ...................... R - 26 Running or Pulling Tubing and ESP Cable w/ Workover Rig BOP Configuration ............................................................................ R - 27 Pressure Testing Annulars................................................................ R - 27 Shut-In Procedure ............................................................................. R - 27

BOP Configuration When Running Test String Running 3-1/2” Test String w/ Class ‘A’ 10M Stack (w/o SBR) ......... R - 27 Running 3-1/2” Test String w/ Class ‘A’ 10M Stack (w/ SBR) ........... R - 27 Running 3-1/2” Test String w/ Class ‘A’ 5M Stack ............................ R - 28

Rigging Up Surface Well Test Equipment Installing Surface Lines Upstream of Test Manifold.......................... R - 28 Installing Surface Lines Downstream of Test Manifold ..................... R - 28

Pressure Testing with Nitrogen Surface Well Test Equipment (Gas Wells) ....................................... R - 28 Lubricator (Gas Wells) ...................................................................... R - 28

Running Electric Line Electric Line BOP Requirements for Open Hole ............................... R - 29 Electric Line BOP Requirements for Cased Hole ............................. R - 29 Shut-In on Drill Pipe while Logging with Side-Entry Sub ................... R - 29 Fishing Procedure for Stuck Logging Tool in Open Hole.................. R - 30

Running Coiled Tubing CT BOP Requirements for Low Pressure Wells ............................... R - 30 CT BOP Requirements for High Pressure Wells .............................. R - 30

WELL CONTROL MANUAL



The well control policies described in this section represent operations and specifications that are routinely referenced. These policies (as well as the equipment standards and procedures throughout this Well Control Manual) are considered mandatory. Any deviation from these requirements must be approved by the General Manager, Drilling and Workover. Compliance shall be the responsibility of the Saudi Aramco Drilling Foreman (or Liaisonman) as directed by the Drilling Superintendent. Changes in this 3rd Edition of the Saudi Aramco Well Control Manual are indicated by a bold vertical line in the right margin, opposite the revision. WELL CONTROL CERTIFICATION CERTIFICATION REQUIREMENTS

POLICY ALL SAUDI ARAMCO FOREMEN AND LIAISONMEN, CONTRACT TOOLPUSHERS, DRILLERS, AND ASSISTANT DRILLERS SHALL HAVE CURRENT WELL CONTROL CERTIFICATION (EITHER WELL CAP OR IWCF ARE ACCEPTABLE).

BOP EQUIPMENT REQUIREMENTS API MONOGRAM

POLICY ALL NEWLY MANUFACTURED BOP EQUIPMENT SHALL BE API MONOGRAMMED.

OEM CERTIFICATION

POLICY A FULL OEM CERTIFICATION OF THE BOP, CHOKE MANIFOLD (INCLUDING CHOKES) AND ALL RELATED EQUIPMENT (I.E. CLOSING UNIT, KILL LINE VALVES, CHOKE LINE VALVES, COFLEX HOSE ETC.) SHALL BE REQUIRED AT CONTRACT START-UP AND CONTRACT RENEWAL WITH A MAXIMUM PERIOD OF 3 YEARS BETWEEN OEM RECERTIFICATION.

VISUAL INSPECTION

POLICY THE BOP SHALL BE OPENED, CLEANED AND VISUALLY INSPECTED AFTER EVERY NIPPLE DOWN, INCLUDING SERVICING THE MANUAL LOCK SCREWS.

ELASTOMER REPLACEMENT

POLICY ELASTOMERS EXPOSED TO WELL FLUIDS SHALL BE REPLACED AT A MAXIMUM OF EVERY 12 MONTHS, UNLESS VISUAL INSPECTIONS INDICATE CHANGING EARLIER. NOTE: SEAL ELEMENTS FOR 30” ANNULAR PREVENTERS MAY BE

USED UP TO 36 MONTHS (PROVIDED INSPECTIONS ARE SATISFACTORY, PROPERLY DOCUMENTED, AND THE EXPIRATION DATE OF THE ELASTOMER IS NOT EXCEEDED).

WELL CONTROL MANUAL



MAINTENANCE LOG

POLICY A MAINTENANCE LOG FOR EACH PIECE OF BOP EQUIPMENT SHALL BE MAINTAINED. THIS LOG SHALL INCLUDE (AT A MINIMUM) RECORDS OF ALL SERVICE AND INSPECTIONS PERFORMED ON THE BOP. THE LOG WILL TRAVEL WITH CONTRACTOR-OWNED EQUIPMENT AND SHALL BE KEPT IN THE BOP SHOP FOR SAUDI ARAMCO-OWNED EQUIPMENT.

ELASTOMER VERIFICATION

POLICY ALL RIGS SHALL MAINTAIN A LOG BOOK OF BOP SCHEMATICS DETAILING THE COMPONENTS INSTALLED IN EACH RAM CAVITY.

THE LOG BOOKS SHALL CONTAIN THE PART NUMBER, DESCRIPTION AND INSTALLATION DATE OF RAM BLOCKS, TOP SEALS, RAM OR ANNULAR PACKERS AND BONNET/DOOR SEALS. TO BE WITNESSED AND CO-SIGNED BY THE TOOLPUSHER AND THE SAUDI ARAMCO DRILLING FOREMAN/ LIAISONMAN.

SPARE REQUIREMENTS ON THE RIGSITE

POLICY AT LEAST ONE SPARE SET OF RAM SEALS (TOP SEALS AND PACKER RAMS) FOR ALL RAMS, INCLUDING PACKER RAMS FOR EACH SIZE TUBING OR DRILLPIPE TO BE USED, BONNET OR DOOR SEALS, CONNECTING ROD SEALS, PLASTIC PACKING FOR RAM SHAFT SECONDARY SEALS, RING GASKETS TO FIT FLANGE CONNECTIONS, AND A SPARE SEAL ELEMENT FOR THE ANNULAR PREVENTER MUST ON THE RIGSITE. RAM BLOCKS SHOULD NOT BE DRESSED UNTIL READY TO USE.

CONNECTION REQUIREMENTS

POLICY ALL BOP EQUIPMENT WITH WORKING PRESSURE OF 3,000 PSI AND ABOVE SHALL HAVE FLANGED, WELDED, INTEGRAL, OR HUBBED CONNECTIONS ONLY.

A GRAYLOC CLAMP IS A HUBBED CONNECTION AND IS ACCEPTABLE FOR ALL PRESSURE APPLICATIONS. VIBRATOR HOSES ON RIG PUMPS SHALL HAVE MOLDED END CONNECTIONS. THREADED OR SEAL WELDED CONNECTIONS ARE NOT ACCEPTABLE.

WELL CONTROL MANUAL



LOCKING DEVICES FOR RAMS

POLICY ALL RAM PREVENTERS SHALL BE EQUIPPED WITH MANUAL OR AUTOMATIC LOCKING DEVICES, WHICH MUST BE LOCKED WHENEVER THE RAMS ARE CLOSED TO CONTROL THE WELL.

A HAND CRANK/WRENCH OR HAND WHEEL SYSTEM ARE ACCEPTABLE

MANUAL DEVICES. AUTOMATIC DEVICES (AS SHAFFER POSI-LOCKS) ARE ALSO ACCEPTABLE.

BOP ELASTOMER RATINGS FOR H2S AND TEMPERATURE ANNULAR UNITS

POLICY MINIMUM ACCEPTABLE RATINGS 3,000 PSI STACK 2.5% H2S AND 1800 F

5,000 PSI STACK 2.5% H2S AND 1800 F 10,000 PSI STACK 2.5% H2S AND 1800 F CAMERON, SHAFFER, AND HYDRIL ARE ACCEPTABLE MANUFACTURERS.

FIXED RAM PREVENTERS


5,000 PSI STACK 10.0% H2S AND 2500 F 10,000 PSI STACK 20.0% H2S AND 3000 F CAMERON, SHAFFER, AND HYDRIL ARE ACCEPTABLE

MANUFACTURERS. VARIABLE BORE RAMS


5,000 PSI STACK 10.0% H2S AND 2500 F 10,000 PSI STACK 20.0% H2S AND 2500 F VARIABLE BORE RAMS (VBR) ARE OPTIONAL FOR TAPERED STRING APPLICATIONS ON CLASS ‘A’ BOP STACKS. HOWEVER, THE VBR MUST MEET THE MINIMUM SPECIFICATIONS. ONLY FIXED RAMS SHALL BE USED IN THE MASTER PIPE RAM POSITION. CAMERON’S EXTENDED RANGE HIGH TEMPERATURE VBR-II PACKER (3-1/2” TO 5-7/8” PIPE SIZES) FOR THE CAMERON 13-5/8” U TYPE BLOWOUT PREVENTER IS ACCEPTABLE FOR 3M AND 5M APPLICATIONS. THE VBR WAS SUCCESSFULLY TESTED TO 250 DEGREES F WITH A CAMLAST ELASTOMER RATED FOR 20% H2S.

WELL CONTROL MANUAL



SHEAR BLIND RAMS


5,000 PSI STACK 10.0% H2S AND 2500 F 10,000 PSI STACK 20.0% H2S AND 3000 F BOTH CAMERON AND SHAFFER ARE ACCEPTABLE MANUFACTURERS.

USE OF DIVERTERS

NIPPLING UP DIVERTERS ONSHORE

POLICY A CLASS ‘D’ DIVERTER STACK SHALL BE INSTALLED ON THE CONDUCTOR AND/OR NEXT CASING STRING FOR ALL EXPLORATION WELLS AND DEVELOPMENT WELLS IN THE SHALLOW GAS AREA OR AREAS WHERE OFFSET DATA INDICATES SHALLOW GAS WELLS.

ALL OTHER ONSHORE AREAS DO NOT NEED A DIVERTER.

NIPPLING UP DIVERTERS OFFSHORE

POLICY A CLASS ‘D’ DIVERTER STACK SHALL BE INSTALLED ON THE CONDUCTOR OF ALL OFFSHORE EXPLORATION WELLS AND WELLS WHERE OFFSET DATA INDICATES POSSIBLE SHALLOW GAS.

THE DIVERTER LINES MUST HAVE THE CAPABILITY OF DISCHARGING BELOW THE BOTTOM OF THE HULL DUE TO H2S.

USE OF SHEAR BLIND RAMS APPLICATIONS REQUIRING SHEAR BLIND RAMS

POLICY SHEAR BLIND RAMS SHALL BE UTILIZED FOR THE FOLLOWING D&WO APPLICATIONS

1) CLASS ‘A’ 10M STACKS (ALL DEEP GAS WELLS) 2) OFFSHORE CLASS ‘A’ 5M (ALL OFFSHORE WELLS) 3) ONSHORE CLASS ‘A’ 5M (ALL WELLS WITH > 10% H2S) 4) GAS CAP WELLS (EITHER 3M OR 5M CLASS ‘A’ STACKS) 5) POPULATED AREAS

THE SHEAR BLIND RAMS SHALL BE INSTALLED IN THE RAM LOCATION IMMEDIATELY ABOVE THE DRILLING CROSS.

SIZE OF EMERGENCY KILL LINE

POLICY THE EMERGENCY KILL LINE SHALL BE 3” ON ALL RIGS WHICH ARE UTILIZING SHEAR BLIND RAMS.

RIGS UTILIZING A 3M OR 5M CLASS ‘A’ BOP STACK WITH SHEAR BLIND

RAMS SHALL CHANGE FROM A 2” TO 3” EMERGENCY KILL LINE. WHEN CONNECTING TO A 2” WELLHEAD OUTLET, THE LINE SHALL BE

3” AND MANUAL VALVE 2”.

WELL CONTROL MANUAL



EMERGENCY KILL LINE

HOOK-UP (ONSHORE)

POLICY THE EMERGENCY KILL LINE SHALL BE AN INDIVIDUAL LINE WITH FLANGED STEEL PIPING (OF THE SAME RATED WORKING PRESSURE AS THE BOP STACK) CONNECTED TO THE WELLHEAD AND EXTENDING TO THE END OF THE CATWALK.

HOOK-UP (OFFSHORE)

POLICY THE EMERGENCY KILL LINE SHALL BE AN INDIVIDUAL 5M LINE WITH THE CAPABILITY OF BEING CONNECTED TO THE CEMENT MANIFOLD THROUGH THE CHOKE MANIFOLD AS SHOWN IN SECTION J (FIGURE 18A) OR THROUGH A DEDICATED LINE FROM THE RIG FLOOR CEMENT MANIFOLD. A 3” ID, 5M COFLEX (COFLON LINED) HOSE SHALL BE RUN BETWEEN THE FIXED PIPING AND APPLICABLE CASING SPOOL.

VALVES

POLICY VALVE ARRANGEMENTS ARE DESCRIBED IN SECTION J. ALL VALVES SHALL BE THE SAME RATED WORKING PRESSURE AS THE BOP STACK.

A CHECK VALVE IS NOT REQUIRED IN THE EMERGENCY KILL LINE

(WHICH WILL ALLOW MONITORING ANNULUS PRESSURE BELOW THE MASTER RAM).

KILL LINE HOOK-UP

POLICY THE PRIMARY KILL LINE SHALL BE CONNECTED TO EITHER THE STAND PIPE OR DIRECTLY TO THE MUD PUMPS FOR ALL PRESSURE APPLICATIONS.

FOR STAND PIPE CONNECTIONS ON 10M APPLICATIONS, AN

ISOLATION VALVE IS REQUIRED BETWEEN THE KILL LINE (10M) AND THE STAND PIPE MANIFOLD (5M).

VALVES

POLICY VALVE ARRANGEMENTS ARE DESCRIBED IN SECTION J. ALL VALVES SHALL BE THE SAME RATED WORKING PRESSURE AS THE BOP STACK.

PRESSURE RATING

POLICY THE KILL LINE SHALL HAVE THE SAME PRESSURE RATING AS THE BOP STACK, INDEPENDENT OF WHETHER THE KILL LINE IS CONNECTED TO THE STAND PIPE OR THE MUD PUMPS.

WELL CONTROL MANUAL



CONNECTIONS ON KILL, EMERGENCY KILL, AND CHOKE LINES CONNECTION REQUIREMENTS

POLICY ALL LINES SHALL CONSIST OF STEEL PIPING WITH FLANGED, WELDED, INTEGRAL, OR HUBBED CONNECTIONS ONLY.

COFLEX HOSE (COFLON LINED) MAY BE USED IN LIEU OF OR

COMBINATION WITH STEEL LINE FOR KILL OR EMERGENCY KILL LINE IN ALL PRESSURE APPLICATIONS (SEE ADDITIONAL DETAILS UNDER FLEXIBLE HOSES BELOW).

USE OF TARGETED TEES

POLICY ALL FABRICATED STEEL PIPING SHALL BE STRAIGHT, AS POSSIBLE, WITH TARGETED TEES OR BLOCK-TEE ELBOWS AT THE TURNS. ALL TEES MUST BE TARGETED WITH RENEWABLE BLIND FLANGES.

WELDED TEES ARE NOT ACCEPTABLE.

USE OF HEAVY DUTY ELBOWS

POLICY ONLY TARGETED OR BLOCK-TEE ELBOWS WITH RENEWABLE BLIND FLANGES ARE ACCEPTABLE.

USE OF CHIKSANS

POLICY CHIKSANS ARE NOT ACCEPTABLE FOR KILL LINE, EMERGENCY KILL LINE, OR CHOKE LINE (WASHOUTS IN THE PACKING ELEMENT OF THE SWIVEL CAN DEVELOP DURING LONG TERM USE).

USE OF WECO CONNECTIONS

POLICY WECO CONNECTIONS (OTHER THAN THE REMOTE CONNECTIONS AT THE END OF THE CATWALK) ARE NOT ACCEPTABLE FOR KILL LINE, EMERGENCY KILL LINE, OR CHOKE LINE (LEAKS IN THE LIP SEAL OF THE WECO CONNECTION CAN OCCUR WITH GAS, CO2, AND HT/HP SITUATIONS).

INTEGRAL OR WELDED WECO FIGURE 1502 CONNECTIONS ARE

ACCEPTABLE DOWNSTREAM OF THE BUFFER TANK FOR ALL LAND APPLICATIONS, PROVIDED THEY ARE MONOGRAMMED TO API 6A. WECO FIGURE 1502 CONNECTIONS ON THE WELL TEST LINE (DOWNSTREAM OF THE CHOKE MANIFIOLD) ARE NOT ACCEPTABLE FOR OFFSHORE OPERATIONS.

FIGURE 602 CONNECTIONS ARE NOT ALLOWED ON ANY DRILLING

OR WORKOVER OPERATION.

WELL CONTROL MANUAL



MINIMUM BORE ON KILL, EMERGENCY KILL, AND CHOKE LINES

BORE REQUIREMENTS

POLICY THE MINIMUM BORE SIZE FOR KILL, EMERGENCY KILL, AND CHOKE LINES SHALL BE THE SAME SIZE AS THE BORE OF THE WELD NECK FLANGE USED IN THE PRESSURE APPLICATION, AS INDICATED BELOW.

KILL LINE:

NOMINAL SIZE WORKING PRESSURE (PSI) MINIMUM BORE 2-1/16" 3M AND 5M 1.72” 2-1/16" 10M 2.09”

EMERGENCY KILL LINE:

NOMINAL SIZE WORKING PRESSURE (PSI) MINIMUM BORE 2-1/16" 3M AND 5M 1.72” 3-1/8” 3M 2.93” 3-1/8” 5M 2.65”

3-1/16" 10M 3.09”

CHOKE LINE:

NOMINAL SIZE WORKING PRESSURE (PSI) MINIMUM BORE 3-1/8” 3M 2.93” 3-1/8” 5M 2.65”

4-1/16" 10M 4.09”

ALL LINES SHALL BE WELDED AND PRESSURE TESTED AS PER API SPECIFICATION 6A.

UTILIZING FLEXIBLE HOSE

FOR KILL LINE, EMERGENCY KILL LINE, OR CHOKE LINE

POLICY COFLEX FLEXIBLE STEEL HOSE (OR A COMBINATION FLEXIBLE HOSE AND HARD LINE) MAY BE USED FOR KILL LINE OR EMERGENCY KILL LINE ON 3M, 5M, AND 10M PSI APPLICATIONS AND CHOKE LINE ON 3M AND 5M PSI APPLICATIONS, IF THE FOLLOWING REQUIREMENTS ARE SATISFIED,

§ COFLON LINED AND MONOGRAMMED TO API SPECIFICATION

16C. HOSES CURRENTLY IN THE FIELD, NOT MONOGRAMMED, MAY CONTINUE TO BE USED FOR THE REMAINING SERVICE LIFE. HOWEVER AS HOSES ARE REPLACED, THEY MUST BE MONOGRAMMED

§ ALL OTHER COMPONENTS OF THE HOSE AND END-FITTINGS IN POSSIBLE CONTACT WITH WELLBORE FLUIDS MEET NACE STANDARD MR-01-75 (LATEST REVISION)

§ ALL END-FITTINGS SHALL BE FLANGED, WELDED, INTEGRAL, OR HUBBED CONNECTIONS (WHICH ARE MOLDED TO THE HOSE AND MONOGRAMMED TO API SPECIFICATION 6A)

§ RE-CERTIFICATION BY OEM EVERY 3 YEARS

WELL CONTROL MANUAL



§ CERTIFIED FOR DRILLING SERVICE (NO WEEP HOLES)

§ PROPERLY SUPPORTED/ANCHORED, WHERE NECESSARY, WHEN USED AS CHOKE LINE

§ NUMBER OF CONNECTIONS MINIMIZED WHEN FLEXIBLE HOSE IS USED IN COMBINATION WITH HARD LINE

§ SAME WORKING PRESSURE (OR GREATER) AS BOP STACK

THE USE OF HARD LINE FOR CHOKE LINE IS REQUIRED ON HIGH PRESSURE GAS WELLS (10M) AND OPTIONAL FOR OIL WELL APPLICATIONS.

CHOKE MANIFOLDS SPECIFICATIONS

POLICY ALL CHOKE MANIFOLDS AND PIPING SHALL MEET SOUR SERVICE NACE MR-01-75 (LATEST REVISION) AND API SPECIFICATION 6A. ALL VALVES AND CHOKES SHALL BE MONOGRAMMED TO API 6A AND MADE TO THE SPECIFIC REQUIREMENTS LISTED IN SECTION J, AS PER PRESSURE APPLICATION.

NOTE: IT IS ACCEPTABLE TO CONVERT API MONOGRAMMED ‘DD’

VALVES TO ‘EE’ UNDER API 6A, SECTION 11.

WORKOVER OPERATIONS (3M)

POLICY ALL WORKOVER RIGS USING A 3,000 PSI CHOKE MANIFOLD SHALL USE THE MANIFOLD CONFIGURATION DESCRIBED IN SECTION J 4.0.3.

THIS MANIFOLD INCLUDES ONE 3” MINIMUM CHOKE LINE, TWO 3” MINIMUM FLARE LINES, A MANUAL ADJUSTABLE CHOKE AND A REMOTE HYDRAULIC CONTROLLED ADJUSTABLE CHOKE.

FLARE LINES OIL WELLS

POLICY TWO (2) 3-1/2” EUE FLARE LINES, EACH APPROXIMATELY 400 FEET IN LENGTH, ARE REQUIRED ON ONSHORE OIL WELLS.

GAS WELLS

POLICY FOUR (4) 4-1/2” LTC GAS FLARE LINES AND ONE (1) 3-1/2” EUE LIQUID FLARE LINE, EACH APPROXIMATELY 1000 FEET IN LENGTH, ARE REQUIRED ON ONSHORE GAS WELLS.

NOTE: ELBOWS AND CHIKSANS ON THE FLARE LINE ARE SUSCEPTIBLE TO EROSION (ALL WELLS) AND WASHOUTS AND ARE NOT ACCEPTABLE (BECAUSE OF THE POTENTIAL FOR HIGH FLUID VELOCITIES). THE FLARE LINE, AS WITH THE CHOKE LINE, SHALL BE AS STRAIGHT AS POSSIBLE, WITH TARGETED OR BLOCK-TEE ELBOWS AT TURNS, AS REQUIRED.

USING DRILL PIPE FOR FLARE LINE IS NOT RECOMMENDED BECAUSE OF THE DIFFICULTY OF PROPERLY MAKING UP THE CONNECTIONS ON THE GROUND.

WELL CONTROL MANUAL



ACCUMULATOR CLOSING UNITS MANUFACTURER

POLICY THE BRAND OF CLOSING UNIT USED BY THE DRILLING CONTRACTOR IS NOT DICATED BY SAUDI ARAMCO; HOWEVER, THE CLOSING UNIT MUST MEET THE FOLLOWING REQUIREMENTS.

FLUID REQUIREMENTS

POLICY THE ACCUMULATOR SHALL STORE ENOUGH FLUID UNDER PRESSURE TO CLOSE ALL PREVENTERS (AND HOLD CLOSED), OPEN THE HCR TO CHOKE, AND RETAIN 50% OF THE CALCULATED CLOSING VOLUME WITH A MINIMUM OF 200 PSI ABOVE PRE-CHARGE PRESSURE WITHOUT ASISTANCE FROM THE CHARGING SYSTEM.

PRE-CHARGE REQUIREMENTS

POLICY THE ACCUMULATOR SHALL BE PRE-CHARGED WITH NITROGEN AS PER MANUFACTURER’S SPECIFICATIONS/RECOMMENDATIONS.

THE MINIMUM PRE-CHARGE PRESSURE FOR A 3,000 PSI WORKING

PRESSURE ACCUMULATOR UNIT IS 1,000 PSI. PRECHARGE PRESSURE SHALL BE CHECKED PRIOR TO CONNECTING

THE CLOSING UNIT TO THE BOP STACK (OR ANY TIME THE ACCUMULATOR MUST BE COMPLETELY DE-PRESSURIZED).

CLOSING REQUIREMENTS

POLICY THE ACCUMULATOR SHALL BE CAPABLE OF CLOSING EACH RAM WITHIN 30 SECONDS.

CLOSING TIME SHALL NOT EXCEED 30 SECONDS FOR ANNULARS

SMALLER THAN 18-3/4” AND 45 SECONDS FOR ANNULARS PREVENTERS OF 18-3/4” OR LARGER.

BACK-UP CHARGING SYSTEM

POLICY THE ACCUMULATOR BACK-UP CHARGING SYSTEM SHALL BE AUTOMATIC, SUPPLIED BY A POWER SOURCE INDEPENDENT FROM THE POWER SOURCE TO THE PRIMARY ACUMULATOR-CHARGING SYSTEM, AND POSSESS SUFFICIENT CAPABILITY TO CLOSE ALL BOP COMPONENTS AND HOLD THEM CLOSED.

LOCATION

POLICY THE ACCUMULATOR SHALL BE LOCATED AT A REMOTE LOCATION, AT LEAST 60 FEET DISTANCE FROM THE WELLBORE AND 100 FEET FOR GAS WELLS.

WELL CONTROL MANUAL



PRESSURE TESTING BOP EQUIPMENT FREQUENCY OF PRESSURE TEST

POLICY BOP EQUIPMENT MUST BE PRESSURE TESTED AS FOLLLOWS 1) WHEN INSTALLED

2) BEFORE DRILLING OUT EACH CASING STRING 3) FOLLOWING THE DISCONNECTION OR REPAIR OF ANY

WELLBORE PRESSURE SEAL IN THE WELLHEAD/BOP STACK (LIMITED TO THE AFFECTED COMPONENTS ONLY)

4) ATLEAST ONCE EVERY TWO WEEKS (+ 2 DAYS) MINIMUM DURATION OF PRESSURE TEST

POLICY ALL PRESSURE TESTS SHALL BE HELD FOR A MINIMUM DURATION OF 10 MINUTES WITH NO OBSERVABLE PRESSURE DECLINE.

PRESSURE TEST FLUID

POLICY ALL PRESSURE TESTS SHALL BE PERFORMED USING WATER. LOW PRESSURE TEST

POLICY A LOW PRESSURE TEST TO 300 PSI SHALL BE CONDUCTED ON EACH PIECE OF BOP EQUIPMENT BEFORE THE HIGH PRESSURE TEST.

HIGH PRESSURE TEST

POLICY THE HIGH PRESSURE TEST SHALL BE DETERMINED BY THE FOLLOWING,

INITIAL PRESSURE TEST

1) FULL WORKING PRESSURE, IF TEST PLUG IS USED 2) 80% OF CASING BURST, IF CUP TESTER IS USED

SUBSEQUENT PRESSURE TEST(S)

1) GREATER THAN MAXIMUM ANTICIPATED SURFACE PRESSURE, IF A TEST PLUG IS USED

2) 80% OF CASING BURST, IF CUP TESTER IS USED PRESSURE TEST REQUIREMENTS FOR CLASS ‘A’ 10,000 PSI BOP STACK ON DEEP GAS WELLS

POLICY FOR KHUFF WELLS (JILH DOLOMITE CASING POINT) 1) FULL WORKING PRESSURE (10,000 PSI) WHEN INSTALLED 2) PRESSURE TEST TO 8,500 PSI THEREAFTER FOR PRE-KHUFF WELLS (JILH DOLOMITE CASING POINT AND BELOW)

1) FULL WORKING PRESSURE (10,000 PSI) WHEN INSTALLED 2) PRESSURE TEST TO 10,000 PSI THEREAFTER

FOR K1/MK1 WELLS (WHERE NU OCCURS ABOVE JILH DOLOMITE CP)

1) FULL WORKING PRESSURE (10,000 PSI) WHEN INSTALLED 2) PRESSURE TEST TO MAXIMUM ANTICIPATED SURFACE

PRESSURE (5,000 PSI MINIMUM) THEREAFTER

WELL CONTROL MANUAL



PRESSURE TESTING ANNULAR PREVENTER

POLICY ANNULAR PREVENTERS SHALL BE TESTED TO 70% OF THE RATED WORKING PRESSURE UPON INSTALLATION AND ALL SUBSEQUENT TESTS.

USE OF TEST STUMP

POLICY TEST STUMPS ARE AN ACCEPTABLE METHOD OF PRESSURE TESTING THE BOP STACK AT THE RIGSITE. THE BOTTOM CONNECTION (AND ALL OTHER CONNECTIONS NOT TESTED) MUST BE TESTED WITH A TEST PLUG UPON INSTALLATION OF THE BOP STACK.

PRESSURE TESTING WELLHEAD VALVES

POLICY TEST ALL VALVES ON THE WELLHEAD INDIVIDUALLY TO THEIR RATED WORKING PRESSURE ON INSTALLATION (USING A VR PLUG) AND TO 80% OF CASING BURST ON SUBSEQUENT PRESSURE TESTS, WITH A CUP TESTER LOCATED AT + 90’.

DOCUMENTING PRESSURE TEST CHARTS

POLICY PRESSURE CHARTS SHOULD INCLUDE THE FOLLOWING, 1) DATE OF TEST 2) WELL NAME 3) DRILLER 4) TOOLPUSHER 5) SAUDI ARAMCO REPRESENTATIVE

A STAMP OR LABEL ON THE CHART MAY BE USED TO PROVIDE THIS INFORMATION.

PRESSURE TESTING HIGHER WORKING PRESSURE BOP EQUIPMENT THAN REQUIRED FOR THE WELL BEING DRILLED (OIL WELLS ONLY)

POLICY HIGHER WORKING PRESSURE EQUIPMENT USED ON A NON-GAS WELL, REQUIRING A LOWER PRESSURE RATING, SHALL BE TESTED TO THE LOWER PRESSURE REQUIREMENTS.

EXAMPLE: IF A 5,000 PSI BOP STACK IS USED ON A CLASS ‘B’

3,000 PSI WELL APPLICATION, THEN PRESSURE TESTS SHALL BE AS REQUIRED FOR A 3,000 PSI STACK.

PRESSURE TESTING ACCUMULATOR HYDRAULIC LINES

POLICY MANIFOLD AND BOP HYDRAULIC LINES SHALL BE PRESSURE TESTED TO 3,000 PSI UPON INSTALLATION TO ENSURE PRESSURE INTEGRITY AT HIGHER PRESSURES.

THIS PRESSURE TEST IS MANDATORY FOR ALL RIGS.

WELL CONTROL MANUAL



LEAK IN FLANGE OR RING GASKET BETWEEN BOP STACK AND CASING HEAD (WHILE TESTING BOP STACK)

POLICY FOR LEAK IN 9-5/8” CASING HEAD 1) SET RBP 100’ ABOVE CASING SHOE (GAS WELLS ONLY) 2) SET RTTS/STORM VALVE AT + 200’ (W/ + 3000’ OF KILL STRING) 3) REMOVE BOP STACK AND REPAIR LEAK 4) RE-INSTALL BOP STACK AND PRESSURE TEST

5) RETRIEVE RTTS/STORM VALVE 6) RETRIEVE RBP (GAS WELLS ONLY)

FOR LEAK IN 13-3/8” CASING HEAD 1) SET BP 100’ ABOVE CASING SHOE (GAS WELLS ONLY) 2) SET RTTS/STORM VALVE AT + 200’ (W/ + 3000’ OF KILL STRING) 3) REMOVE BOP STACK AND REPAIR LEAK 4) RE-INSTALL BOP STACK AND PRESSURE TEST 5) RETRIEVE RTTS/STORM VALVE

6) DRILL OUT BP (GAS WELLS ONLY)

FOR LEAK IN 18-5/8” CASING HEAD 1) RIH AND SET CEMENT PLUG AT 500 – 200’. POH 2) REMOVE BOP STACK AND REPAIR LEAK 3) RE-INSTALL BOP STACK AND PRESSURE TEST

4) DRILL OUT CEMENT PLUG DRILL PIPE FLOAT GENERAL REQUIREMENTS

POLICY A DRILL PIPE FLOAT SHALL BE RUN AT ALL TIMES (EXCEPT WHEN PLANNED OPERATIONS PRECLUDE RUNNING A FLOAT; AS TESTING, TREATING, OR SQUEEZING).

A PORTED FLOAT IS NOT RECOMMENDED AS THESE PORTS CAN BE EASILY PLUGGED AND SOMETIMES WASHOUT.

GAS BUSTERS

OIL RIGS

POLICY MINIMUM SEPARATOR SIZE REQUIREMENTS FOR OIL RIGS § SEPARATOR DIAMETER OF 36” § SEPARATOR HEIGHT OF 15’ § MUD LEG OF 7’ § ONE 8” DIAMETER GAS VENT LINE

NOTE: VENT LINE SHALL BE FLANGED OR CLAMPED STEEL LINE ONLY, WITH A MINIMUM LENGTH OF 240’ FROM THE GAS BUSTER (ONSHORE WELLS). THE FLARE PIT SHALL BE POSITIONED AWAY FROM THE RESERVE/WASTE PITS TO PREVENT IGNITION OF ANY WASTE HYDROCARBONS.

AN EXISTING GAS BUSTER (WITH DIFFERENT HEIGHT OR DIAMETER) MAY COMPLY IF IT’S CAPACITY IS 17.5 BBLS OR GREATER.

WELL CONTROL MANUAL



GAS RIGS

POLICY MINIMUM SEPARATOR SIZE REQUIREMENTS FOR GAS RIGS § SEPARATOR DIAMETER OF 36” § SEPARATOR HEIGHT OF 30’ § MUD LEG OF 7’ § TWO 8” DIAMETER GAS VENT LINES

NOTE: VENT LINES SHALL BE FLANGED OR CLAMPED STEEL LINE

ONLY, WITH A MINIMUM LENGTH OF 240’ FROM THE GAS BUSTER (ONSHORE WELLS). THE FLARE PIT SHALL BE POSITIONED AWAY FROM THE RESERVE/WASTE PITS TO PREVENT IGNITION OF ANY WASTE HYDROCARBONS.

AN EXISTING GAS BUSTER (WITH DIFFERENT HEIGHT OR DIAMETER) MAY COMPLY IF IT’S CAPACITY IS 35 BBLS OR GREATER.

ENCOUNTERING LOSS CIRCULATION

LOSS OF RETURNS IN A HYDROCARBON-BEARING ZONE

POLICY IF LOSS CIRCULATION IS ANTICIPATED IN A POTENTIAL HYDROCARBON-BEARING ZONE, RUN LARGE JET NOZZLES AND BHA WITHOUT MUD MOTOR (IF POSSIBLE).

§ IF LOSS CIRCULATION IS ENCOUNTERED, ATTEMPT TO

REGAIN WITH (2) *LCM PILLS AND/OR CEMENT PLUGS

* FOR ARAB-D OPEN-HOLE PRODUCERS USE ACID SOLUBLE LCM AND NO CEMENT PLUGS (UNLESS SPECIFICALLY REQUIRED)

§ IF UNABLE TO REGAIN CIRCULATION, CONTINUE DRILLING

WITH MUD CAP TO NEXT CASING POINT

THE ONLY EXCEPTION TO THIS POLICY IS EXPERIENCING COMPLETE LOSS CIRCULATION IN THE ARAB-D RSVR ON A KHUFF/PRE-KHUFF [K2] WELL, WHERE CIRCULATION MUST BE REGAINED BEFORE CONTINUING DRILLING TO THE JILH DOLOMITE CASING POINT.

MAINTAINING MINIMUM OVERBALANCE

GENERAL REQUIREMENTS FOR OVERBALANCE FOR DRILLING & WORKOVER APPLICATIONS

POLICY A MINIMUM OVERBALANCE SHALL BE MAINTAINED ON ALL WELLS AS INDICATED BELOW,

§ 100 PSI OVERBALANCE ON WATER RESERVOIRS § 200 PSI OVERBALANCE ON OIL WELLS § 300 PSI OVERBALANCE ON GAS WELLS

WATER FLOWS, AS ARAB-C, MAY BE DRILLED WITH FLOW IF HYDROCARBONS, H2S, OR HIGH RATES ARE NOT ENCOUNTERED.

WELL CONTROL MANUAL



DRILLING THE ARAB-C RESERVOIR WITH WATER

POLICY DRILL ARAB-C RESERVOIR WITH WATER……….IF WELL KICKS, SHUT-IN AND CIRCULATE BOTTOMS-UP THROUGH CHOKE USING THE ‘DRILLER’S’ METHOD.

§ IF HYDROCARBON INFLUX, H2S, OR ‘HIGH RATE’ SALTWATER FLOW, KILL WELL AND CONTINUE DRILLING WITH MUD

§ IF ‘LOW RATE’ SALTWATER FLOW, CONTINUE DRILLING

WITH THE WELL FLOWING TO CASING POINT AND MUD UP PRIOR TO RUNNING CASING

REDUCING MUD WEIGHT LESS THAN PORE PRESSURE EQUIVALENT WHEN ATTEMPTING TO FREE DIFFERENTIALLY STUCK PIPE

POLICY NEVER REDUCE MUD WEIGHT LESS THAN PORE PRESSURE WHEN ATTEMPTING TO FREE DIFFERENTIALLY STUCK PIPE.

AVOID PUMPING LARGE VOLUMES OF DIESEL TO FREE STUCK PIPE IN A GAS ZONE.

GAS SOLUBILITY IN DIESEL CAN MASK A KICK INFLUX. ISOLATING KHUFF RESERVOIR SETTING CASING AT THE TOP OF THE KHUFF FORMATION

POLICY SET CASING AT TOP OF KHUFF FORMATION ONLY ON CRITICAL WELLS WITH,

§ ABNORMAL LOWER JILH PRESSURE § HIGH DIFFERENTIAL PRESSURE BETWEEN LOWER JILH

AND KHUFF RESERVOIRS § HIGHLY DEVIATED WELL PROFILE § PROXIMITY TO FACILITIES OR POPULATED AREAS

TAPERED STRING WHEN WORKING WITH A TAPERED STRING

POLICY ALWAYS BE IN A POSITION TO HAVE AT LEAST ONE STAND OF EITHER SIZE PIPE AVAILABLE TO PICK UP.

SPACE OUT DATA RECORDING SPACE OUT DATA

POLICY SPACE OUT DATA SHALL BE CLEARLY VISIBLE IN THE DOG HOUSE AND RECORDED IN THE IADC TOUR BOOK EACH TIME THE RIG PERFORMS A BOP DRILL.

WELL CONTROL MANUAL



SLOW PUMP RATE DATA RECORDING SLOW PUMP RATE DATA

POLICY SLOW PUMP RATE SHALL BE RECORDED IN THE IADC TOUR BOOK 1) TOURLY 2) AFTER A MUD WEIGHT CHANGE 3) AFTER A BIT NOZZLE OR BHA CHANGE 4) AFTER EACH 500’ OF DEPTH 5) AFTER A DRILLING OR COMPLETION FLUID TYPE CHANGE 6) WHENEVER MUD PROPERTIES SIGNIFICATELY CHANGE

ALL FLOW CHECKS SHALL BE 15 MINUTES.

TRIPPING PIPE PULLING OUT OF HOLE

POLICY THE FOLLOWING PROCEDURE IS REQUIRED WHEN POH 1) ENSURE A FULL OPENING SAFETY VALVE, INSIDE BOP,

CLOSING WRENCH, AND CROSSOVER SUBS ARE ON RIG FLOOR

2) RECORD DATA ON TRIP SHEET EVERY 5 STANDS FOR DP, 2 STANDS FOR HWDP, AND EVERY STAND FOR DC

3) COMPARE DATA TO EXPECTED DISPLACEMENT VALUES

AVOID PULLING A WET STRING WHENEVER POSSIBLE.

RUNNING IN HOLE

POLICY THE FOLLOWING PROCEDURE IS REQUIRED WHEN RIH 1) ENSURE FULL OPENING SAFETY VALVE, INSIDE BOP,

CLOSING WRENCH, AND CROSSOVER SUBS ARE ON RIG FLOOR

2) RUN IN HOLE APPROXIMATELY ONE MINUTE PER STAND 3) RECORD DATA ON TRIP SHEET EVERY 5 STANDS FOR DP,

2 STANDS FOR HWDP, AND EVERY STAND FOR DC 4) COMPARE DATA TO EXPECTED DISPLACEMENT VALUES 5) FILL DRILL PIPE EVERY 10 TO 20 STANDS

USE THE TRIP TANK WHEN RUNNING CASING.

PERFORMING FLOW CHECKS PERFORMING FLOW CHECKS WHILE DRILLING

POLICY A FLOW CHECK SHALL BE PERFORMED WHENEVER 1) DECREASE IN PUMP PRESSURE 2) INCREASE IN PUMP STROKES 3) DECREASE IN MUD WEIGHT 4) INCREASE IN CHLORIDES 5) GRADUAL INCREASE IN DRILL RATE 6) DRILLING BREAK


WELL CONTROL MANUAL



PERFORMING FLOW CHECKS WHILE TRIPPING

POLICY A FLOW CHECK SHALL BE PERFORMED 1) WHEN THE HOLE IS NOT TAKING THE CORRECT AMOUNT

OF FLUID 2) BEFORE PUMPING A SLUG 3) * BEFORE PULLING OUT OF THE HOLE 4) * AFTER PULLING 5 TO 10 STANDS 5) WHEN BIT ENTERS CASING SHOE 6) * PRIOR TO PULLING LAST 5 STANDS 7) PRIOR TO PULLING THE BHA

* INDICATES ADDITIONAL FLOW CHECKS REQUIRED WHEN A HYDROCARBON ZONE IS OPEN.


DISPLACING TO BRINE ON HORIZONTAL WELLS

POLICY THE FOLLOWING SHALL BE REQUIRED 1) A BRINE DENSITY THAT WILL PROVIDE THE SAME

OVERBALNCE (AT BOTTOMHOLE TEMPERATURE) AS MUD WEIGHT UTILIZED

2) MEASUREMENT OF BRINE DENSITY IN/OUT TO VERIFY THAT BOTH ARE THE SAME AT SAME TEMPERATURE

3) A MINIMUM OF ONE HOUR TO WAIT/OBSERVE WELL AFTER DISPLACING TO BRINE

4) PUMPING OUT OF THE HOLE FOR MINIMIZED SWABBING, CONTINUED FILL-UP, AND IMPROVED GAS DISPLACEMENT IN THE HORIZONTAL OPEN HOLE

SHUTTING IN WELL SHUTTING IN WELL WITHOUT A FLOW CHECK

POLICY IMMEDIATE ACTION SHOULD BE TAKEN TO SHUT IN WELL WHENEVER 1) INCREASE IN PIT GAIN 2) INCREASE IN FLOW RATE

SHUTTING IN WELL WHILE DRILLING

POLICY SHUT-IN PROCEDURE (HARD SHUT–IN) 1) SPACE OUT (SPOT TOOL JOINT) 2) STOP MUD PUMPS 3) CLOSE ANNULAR OR UPPER RAM PREVENTER 4) CONFIRM WELL IS SHUT IN AND FLOW HAS STOPPED 5) OPEN HCR

WELL CONTROL MANUAL



SHUTTING IN WELL WHILE TRIPPING

POLICY SHUT-IN PROCEDURE (HARD SHUT–IN) 1) STAB FULL OPEN SAFETY VALVE 2) CLOSE SAFETY VALVE 3) SPACE OUT (SPOT TOOL JOINT) 4) CLOSE ANNULAR OR UPPER RAM PREVENTER 5) CONFIRM WELL IS SHUT IN AND FLOW HAS STOPPED 6) OPEN HCR

DO NOT ATTEMPT TO RUN IN HOLE WITH THE WELL FLOWING.

SHUTTING IN WELL WITH BHA ACROSS BOP STACK

POLICY SHUT-IN PROCEDURE (HARD SHUT–IN) 1) SET SLIPS 2) INSTALL CROSSOVER TO FULL OPEN SAEFTY VALVE 3) STAB FULL OPEN SAFETY VALVE 4) CLOSE SAFETY VALVE 5) CLOSE ANNULAR 6) CONFIRM WELL IS SHUT IN AND FLOW HAS STOPPED 7) OPEN HCR 8) INSTALL INSIDE BOP 9) OPEN SAFETY VALVE 10) REDUCE CLOSING PRESSURE ON ANNULAR AND STRIP-IN

A STAND OF DRILLPIPE

IN THE EVENT OF A FAILURE IN THE ANNULAR (WITH BHA ACROSS BOP STACK) AND UNCONTROLLED FLOW, THE BHA SHOULD BE DROPPED AND WELL SHUT IN WITH THE BLIND RAMS.

FAILURE OF UPPER PIPE RAMS DURING A WELL KILL OPERATION RECOMMENDED ACTION

POLICY RECOMMENDED ACTION TO INCLUDE 1) CLOSE MASTER PIPE RAMS

2) REPAIR UPPER PIPE RAMS 3) CLOSE UPPER PIPE RAMS 4) OPEN MASTER PIPE RAMS 5) VERIFY UPPER PIPE RAMS ARE HOLDING 6) CONTINUE WITH WELL KILL

BOP CONFIGURATION WHEN RUNNING CASING RUNNING CASING OR LINER WITH CLASS ‘B’ 3000 PSI BOP STACK

POLICY BOP CONFIGURATION SHALL CONSIST OF THE FOLLOWING ANNULAR : USED AS CASING RAMS TOP RAM : BLIND RAMS

MASTER PIPE : DRILL PIPE RAMS

WELL CONTROL MANUAL



RUNNING CASING WITH CLASS ‘A’ 3,000 OR 5,000 PSI BOP STACK (WITH OR WITHOUT SBR)

POLICY FOR: BOP CONFIGURATION SHALL CONSIST OF THE FOLLOWING SHORT LINERS (< 2000’) ANNULAR : USED AS CASING RAMS

TOP RAM : PIPE RAMS MIDDLE RAM : BLIND RAMS (OR SHEAR BLIND RAMS)

MASTER PIPE : PIPE RAMS POLICY FOR: BOP CONFIGURATION SHALL CONSIST OF THE FOLLOWING LONG LINERS (>2000’) ANNULAR : LONG STRINGS TOP RAM : CHANGE PIPE RAMS TO CASING RAMS MIDDLE RAM : BLIND RAMS (OR SHEAR BLIND RAMS) MASTER PIPE : PIPE RAMS

HAVE XO (CASING x DP) ON DRILL FLOOR. RUNNING CASING OR 7” LINER WITH CLASS ‘A’ 10,000 PSI BOP STACK (WITHOUT SBR)

POLICY BOP CONFIGURATION SHALL CONSIST OF THE FOLLOWING ANNULAR : TOP RAM : PIPE RAMS MIDDLE RAM : CHANGE BLIND RAMS TO CASING RAMS TOP MASTER : BLIND RAMS BTM MASTER : PIPE RAMS

HAVE XO (CASING x 5” DP) ON DRILL FLOOR. RUNNING CASING WITH CLASS ‘A’ 10,000 PSI BOP STACK (WITH SBR)

POLICY BOP CONFIGURATION SHALL CONSIST OF THE FOLLOWING ANNULAR : TOP RAM : CHANGE PIPE RAMS TO CASING RAMS

MIDDLE RAM : SHEAR BLIND RAMS TOP MASTER : BLIND RAMS BTM MASTER : PIPE RAMS

HAVE XO (CASING x 5” DP) ON DRILL FLOOR.

RUNNING 7” LINER WITH CLASS ‘A’ 10,000 PSI BOP STACK (WITH SBR)

POLICY BOP CONFIGURATION SHALL CONSIST OF THE FOLLOWING ANNULAR : USED AS CASING RAMS TOP RAM : PIPE RAMS MIDDLE RAM : SHEAR BLIND RAMS

TOP MASTER : BLIND RAMS BTM MASTER : PIPE RAMS

HAVE XO (CASING x 5” DP) ON DRILL FLOOR.

RUNNING 4-1/2” LINER WITH 3-1/2” DP, 5” DP, AND 10,000 PSI CLASS ‘A’ STACK (W/ OR W/O SBR) POLICY BOP CONFIGURATION SHALL CONSIST OF THE FOLLOWING ANNULAR : USED AS CASING RAMS TOP RAM : 5” PIPE RAMS MIDDLE RAM : BLIND RAMS (OR SHEAR BLIND RAMS)

WELL CONTROL MANUAL



TOP MASTER : 3-1/2” PIPE RAMS BTM MASTER : 5” PIPE RAMS

HAVE XO’S (4-1/2” LNR x 3-1/2” DP) AND (3-1/2” DP x 5” DP) ON DRILL FLOOR.

RUNNING 4-1/2” PRE-PERFORATED LINER WITH 3-1/2” DP, 5” DP, AND 10,000 PSI CLASS ‘A’ BOP STACK

POLICY BOP CONFIGURATION SHALL CONSIST OF THE FOLLOWING ANNULAR : TOP RAM : 5” PIPE RAMS MIDDLE RAM : BLIND RAMS (OR SHEAR BLIND RAMS) TOP MASTER : 3-1/2” PIPE RAMS BTM MASTER : 5” PIPE RAMS

HAVE XO’S (4-1/2” LNR x 3-1/2” DP) (3-1/2” DP x 5” DP) ON DRILL FLOOR.

SHUTTING IN ON 4-1/2” PRE-PERFORATED LINER WITH 3-1/2” DP, 5” DP, AND 10,000 PSI CLASS ‘A’ BOP STACK

POLICY SHUT-IN PROCEDURE: 1) SET CASING SLIPS 2) INSTALL XOs TO 5” DP 3) MAKE UP A STAND OF DP AND RIH 4) STAB FULL OPEN SAFETY VALVE AND CLOSE VALVE 5) INSTALL INSIDE BOP AND OPEN SAFETY VALVE 6) SHUT 5” PIPE RAMS

7) OPEN HCR

IF THIS PROCEDURE CAN NOT BE ACCOMPLISHED DUE TO THE AMOUNT OF FLOW (OR 2-3/8” INNER STRING), THE LINER SHALL BE DROPPED (BY CLOSING PIPE RAMS, HANGING OFF, AND OPENING PIPE RAM) AND SHUTTING THE BLIND RAMS.

CHANGING RAMS OR INSTALLING CASING RAMS ISOLATION POLICY WHEN CHANGING RAMS OR INSTALLING CASING RAMS

POLICY REQUIRES 2 BARRIERS FOR ISOLATION 1) CLOSED PIPE OR BLIND RAM (MECHANICAL SHUT-OFF) 2) KILL FLUID (NON-MECHANICAL SHUT-OFF) MONITOR ANNULUS USING WELLHEAD VALVES.

IF THE BOTTOM MASTER RAM IS TO BE CHANGED, A PACKER AND STORM VALVE WITH KILL STRING IS REQUIRED FOR A MECHANICAL BARRIER. A TEST PLUG OR TUBING HANGER/BPV SHOULD NOT BE USED AS A MECHANICAL BARRIER IN THIS APPLICATION.

WELL CONTROL MANUAL



PRESSURE TESTING CASING RAMS

POLICY CASING RAMS (AND ANNULAR PREVENTER) SHALL BE PRESSURE TESTED WITH A TEST PLUG AND CASING JOINT TO THE FOLLOWING PRESSURES PRIOR TO RUNNING CASING OR LINER,

CASING POINT TEST PRESSURE

ARAB-D AND ABOVE 500 PSI BASE JILH DOLOMITE 750 PSI TOP OF KHUFF FM. 1500 PSI KHUFF-D ANHYDRITE 1500 PSI PRE-KHUFF TD 1500 PSI

INSTALLING CASING SLIPS WITH MULTI-STAGE CEMENTING

POLICY SET CASING SLIPS AS FOLLOWS 1) DISPLACE 1ST STAGE CEMENT W/ MUD ( 2ND, IF 3 STAGE

JOB) 2) OPEN UPPER MOST DV 3) CIRCULATE HOLE CLEAN W/ MUD 4) WOC 4 HRS WITH WELL STATIC (OBSERVING WELL FOR

FLOW) 5) BREAK CIRCULATION EVERY HOUR TO PREVENT CEMENT

FROM SETTING UP ACROSS PORTS (IF PACKER FAILURE AND EXPANSION)

6) CIRCULATE BOTTOMS UP 7) PICKUP BOP STACK (DO NOT DROP CASING SLIPS) 8) SET CASING SLIPS PRIOR TO CEMENTING FINAL STAGE

NOTE: CONSIDER PUMPING SECOND STAGE CEMENT BEFORE

SETTING SLIPS, IF THE PACKER FAILS AND LOSS CIRCULATION IS EXPERIENCED (ESPECIALLY WITH A HYDROCARBON OR H2S ZONE OPEN). THIS SITUATION SHOULD BE REFERRED TO OPERATIONS MANAGEMENT ON A CASE BY CASE BASIS.

BOP CONFIGURATION WHEN RUNNING PRODUCTION TUBING RUNNING 5-1/2” PRODUCTION TUBING (OR 5-1/2” x 4-1/2” TUBING) AND CLASS ‘A’ 10,000 PSI BOP STACK

POLICY BOP CONFIGURATION SHALL CONSIST OF THE FOLLOWING: ANNULAR :

TOP RAM : 5-1/2” PIPE RAMS MIDDLE RAM : BLIND RAMS (OR SHEAR BLIND RAMS) TOP MASTER : 5-1/2” PIPE RAMS BTM MASTER : 5” PIPE RAMS

HAVE XO (5-1/2” x 4-1/2” TBG) ON DRILL FLOOR.

WELL CONTROL MANUAL



RUNNING DUAL STRINGS SIMULTANEOUSLY WITH CLASS ‘A’ 5,000 PSI BOP STACK


TOP RAM : DUAL RAMS MIDDLE RAM : BLIND RAMS

MASTER PIPE : DUAL RAMS

BOP CONFIGURATION WHEN RUNNING PRODUCTION TUBING AND PACKER RUNNING PRODUCTION TUBING AND PACKER SIMULTANEOUSLY WITH CLASS ‘A’ 3,000 OR 5,000 PSI BOP STACK


TOP RAM : **TUBING RAMS MIDDLE RAM : BLIND RAMS (OR SHEAR BLIND RAMS) MASTER PIPE : *DRILL PIPE RAMS

* DO NOT CHANGE THE MASTER PIPE RAMS TO TUBING RAMS (THEY SHOULD REMAIN DRILL PIPE RAMS) THIS WILL ELIMINATE THE NEED FOR RUNING A RBP AND/OR RTTS AND STORM VALVE. ** IF A TAPERED STRING IS TO BE RUN, THE UPPER PIPE RAMS SHALL BE CHANGED TO THE SIZE OF THE MAJOR SECTION OF TUBING IN THE STRING.

HAVE XO’S (TBG x DP) AND (LARGE TBG x SMALL TBG, FOR TAPERED STRINGS) ON THE DRILL FLOOR. IN CASE OF LOSS CIRCULATION, THE HOLE SHALL BE CONTINUOUSLY FILLED (BOTH TUBING AND BACKSIDE) WHILE RUNNING THE COMPLETION STRING.

REMOVING BOP STACK OR PRODUCTION TREE ISOLATION POLICY FOR LOW GOR OIL WELLS

POLICY REQUIRED BARRIERS FOR OIL WELLS (GOR < 850 SCF/BBL) 2 SHUT-OFFS (ONE MECHANICAL) FOR DETAILS REFER TO G.I. 1853.001 ISOLATION POLICY FOR HIGH GOR OIL WELLS

POLICY REQUIRED BARRIERS FOR OIL WELLS (GOR > 850 SCF/BBL) 3 SHUT-OFFS (TWO MECHANICAL)

FOR DETAILS REFER TO G.I. 1853.001 ISOLATION POLICY FOR GAS WELLS

POLICY REQUIRED BARRIERS FOR GAS WELLS 3 SHUT-OFFS (TWO MECHANICAL)

FOR DETAILS REFER TO G.I. 1853.001

WELL CONTROL MANUAL



ISOLATION POLICY FOR WATER INJECTION WELLS

POLICY REQUIRED BARRIERS FOR WIW WELLS (IF POSITIVE WHP) 2 SHUT-OFFS (ONE MECHANICAL)


REQUIRED BARRIERS FOR WIW WELLS (IF NO POSITIVE WHP) 1 SHUT-OFF


RIGGING DOWN ON HIGH GOR WELLS WITH SSSV RIG DOWN PROCEDURE (WITH LITTLE CLEARANCE BETWEEN RIG AND TREE)

POLICY PROCEDURE 1) NU AND PT TREE

2) RETRIEVE WIRELINE PLUG FROM TAIL PIPE 3) CLOSE CROWN VALVE (DO NOT RD WIRELINE UNIT) 4) OPEN WELL FOR CLEAN-UP 5) CLOSE LOWER MASTER VALVE (OBSERVE NEGATIVE TEST) 6) RIH WITH WIRELINE AND SET PLUG 7) BLEED OFF PRESSURE (OBSERVE PLUG IS HOLDING - BARRIER 1) 8) CLOSE SSSV - BARRIER 2 9) SPLIT TREE ABOVE CLOSED LOWER MASTER VALVE- BARRIER 3 10) MOVE THE RIG OUT 11) RE-INSTALL TREE ABOVE THE LOWER MASTER VALVE 12) LATER, RU WIRELINE UNIT AND RETRIEVE THE PLUG

NOTE: A BPV COULD BE INSTALLED RATHER THAN SETTING A WIRELINE PLUG.

PLATFORM WELL SECURITY REQUIREMENTS PRIOR TO WORKOVER OPERATIONS REQUIRED NUMBER OF MECHANICAL BARRIERS OF ISOLATION

POLICY ALL WELLS ON THE SAME PLATFORM SHALL BE SHUT-IN PRIOR TO WORKOVER OPERATIONS USING TWO (2) MECHANICAL METHODS OF ISOLATION,

§ BELOW SURFACE *CLOSED AND TESTED SURFACE CONTROLLED SUB-

SURFACE SAFETY VALVE § AT SURFACE CLOSED MASTER VALVE

* PRIOR TO MOVING IN A WORKOVER RIG, FIELD SERVICES WILL

CLOSE THE SUB-SURFACE SAFETY VALVES ON ALL WELLS AND DE-PRESSURIZE THE PLATFORM. IF A SUB-SURFACE SAFETY VALVE IS FOUND LEAKING, WELL SERVICES WILL REPLACE THE VALVE.

WELL CONTROL MANUAL



RUNNING OR PULLING TUBING AND ESP CABLE WITH WOROVER RIG BOP CONFIGURATION WHEN RUNNING OR PULLING TUBING AND ESP CABLE


ANNULAR : BOP STACK : BASED ON BOP CLASS

PRESSURE TESTING ANNULARS

POLICY PRESSURE TEST ANNULARS TO 1000 PSI (WITH ESP CABLE). RECENT SHOP TESTING HAS SHOWN THAT AN ANNULAR CAN HOLD 1000 PSI WITH 3-1/2” TUBING AND 1” CABLE.

SHUT-IN PROCEDURE WHEN RUNNING OR PULLING TUBING AND ESP CABLE

POLICY SHUT-IN PROCEDURE 1) SHUT-IN WELL WITH ANNULAR (UPPER) USING SAUDI ARAMCO

SHUT-IN PROCEDURE FOR TRIPPING. 2) CUT ESP CABLE WITH MECHANICAL CUTTER AT THE RIG FLOOR (A WIRE LINE MECHANICAL CUTTER MUST BE ON THE FLOOR) 3) OPEN ANNULAR AND LOWER TUBING 4) CLOSE ANNULAR (UPPER) AROUND TUBING BOP CONFIGURATION WHEN RUNNING TEST STRING RUNNING 3-1/2” TEST STRING WITH TEST HEAD AND CLASS ‘A’ 10,000 PSI BOP STACK (W/O SBR)

POLICY BOP CONFIGURATION SHALL CONSIST OF THE FOLLOWING: ANNULAR : TOP RAM : 5” PIPE RAMS (FOR STIFF JOINT) MIDDLE RAM : 3-1/2” PIPE RAMS TOP MASTER : BLIND RAMS BTM MASTER : 3-1/2” PIPE RAMS HAVE XO (3-1/2” PH6 x 3-1/2” DP) ON DRILL FLOOR. RUNNING 3-1/2” TEST STRING WITH TEST HEAD AND CLASS ‘A’ 10,000 PSI BOP STACK (WITH SBR)

POLICY BOP CONFIGURATION SHALL CONSIST OF THE FOLLOWING: ANNULAR : TOP RAM : 5” PIPE RAMS (FOR STIFF JOINT) MIDDLE RAM : SHEAR BLIND RAMS TOP MASTER : 3-1/2” PIPE RAMS BTM MASTER : 5” PIPE RAMS

CHANGE TOP 5” PIPE RAM TO 3-1/2” PRIOR TO POH WITH TEST STRING

HAVE XO (3-1/2” PH6 x 3-1/2” DP) ON DRILL FLOOR.

WELL CONTROL MANUAL



RUNNING 3-1/2” TEST STRING WITH TEST HEAD AND CLASS ‘A’ 5,000 PSI BOP STACK

POLICY BOP CONFIGURATION SHALL CONSIST OF THE FOLLOWING: ANNULAR : TOP RAM : 5” PIPE RAMS (FOR STIFF JOINT) MIDDLE RAM : BLIND RAMS MASTER RAM : 3-1/2” PIPE RAMS

HAVE XO (3-1/2” DP x 5” DP) ON DRILL FLOOR. RIGGING UP SURFACE WELL TEST EQUIPMENT INSTALLING SURFACE LINES UPSTREAM OF TEST MANIFOLD

POLICY ONLY CONNECTIONS WITH METAL-TO-METAL SEALS ARE ACCEPTABLE (API FLANGED, HUBBED, OR GRAYLOC).

WECO CONNECTIONS ARE NOT ALLOWED (LEAKS IN THE LIP SEAL

CAN OCCUR WITH GAS, CO2, AND HT/HP SITUATIONS). INSTALLING SURFACE LINES DOWNSTREAM OF TEST MANIFOLD

POLICY WECO FIGURE 1502 OR GRAYLOC CONNECTIONS ARE ACCEPTABLE (FIGURE 602 HAMMER UNIONS ARE NOT ALLOWED ON ANY SAUDI

ARAMCO DRILLING AND WORKOVER OPERATIONS). PRESSURE TESTING WITH NITROGEN SURFACE WELLTEST EQUIPMENT - GAS WELLS

POLICY TEST PROCEDURE ON GAS WELLS (W/ 10M WP SURFACE EQUIPMENT) 1) PRESSURE TEST STRING TO 8,500 PSI 2) NEGATIVE TEST SURFACE SAFETY VALVE (IF RUN) AND LOWER MASTER VALVE 3) PRESSURE TEST DOWNSTREAM OF CHOKE MANIFOLD TO 1,200 PSI WITH WATER 4) PRESSURE TEST UPSTREAM OF CHOKE MANIFOLD TO 10,000 PSI WITH WATER 5) PRESSURE TEST DOWNSTREAM OF CHOKE MANIFOLD TO 1,200 PSI WITH NITROGEN 6) PRESSURE TEST UPSTREAM OF CHOKE MANIFOLD TO 8,000 PSI (80% OF WATER PRESSSURE TEST) WITH NITROGEN LUBRICATORS - GAS WELLS

POLICY IF A LUBRICATOR IS REQUIRED ON A GAS WELL (FOR WELL TESTING, COMPLETION, OR WORKOVER OPERATIONS), THE LUBRICATOR SHALL ALSO BE TESTED WITH NITROGEN TO 80% OF WATER PRESSSURE TEST.

WELL CONTROL MANUAL



RUNNING ELECTRIC LINE

ELECTRIC LINE BOP REQUIREMENTS FOR OPEN-HOLE LOGGING APPLICATIONS

POLICY FOR OPEN-HOLE LOGGING (OVER-BALANCED CONDITION)

OIL WELLS WHEN OPEN-HOLE LOGGING, AN ELECTRIC LINE BOP IS NOT REQUIRED, PROVIDED PRIMARY WELL CONTROL (HYDROSTATIC PRESSURE > FORMATION PRESSURE) CAN BE MAINTAINED AND CONFIRMED.

GAS WELLS AN ELECTRIC LINE BOP AND LUBRICATOR IS RECOMMENDED ON ALL GAS WELLS.

LUBRICATORS USED FOR OPEN-HOLE LOGGING WITH KILL MUD IN THE HOLE REQUIRE HYDRO-TESTING ABOVE THE BLIND RAM WITH A COLUMN OF WATER (AS A MINIMUM).

ELECTRIC LINE BOP REQUIREMENTS FOR CASED HOLE APPLICATIONS (LOGGING/PERFORATING)

POLICY FOR CASED-HOLE (UNDER-BALANCED CONDITION)

WELLS WITH MAXIMUM EXPECTED WHP < 5,000 PSI 1) NIPPLE–UP 5,000 PSI WIRELINE BOP ON TESTHEAD OR

TREE 2) MINIMUM NUMBER OF RAMS = 2

3) HYDRAULIC BOP REQUIRED (MANUAL NOT ACCEPTABLE) 4) MINIMUM TEMPERATURE RATING (ELASTOMER) = 2500 F 5) REMOTE GREASE INJECTION UNIT REQUIRED 6) STUFFING BOX W/ HYDRAULIC OPERATED PACK-OFF

REQUIRED 7) BALL CHECK VALVE REQUIRED 8) TOOL CATCHER OPTIONAL 9) TOOL TRAP REQUIRED

WELLS WITH MAXIMUM EXPECTED WHP = 5,000 – 10,000 PSI 1) NU 10,000 PSI WIRELINE BOP ON TESTHEAD OR TREE

2) MINIMUM NUMBER OF RAMS = 3 3) HYDRAULIC BOP REQUIRED (MANUAL NOT ACCEPTABLE) 4) MINIMUM TEMPERATURE RATING (ELASTOMER) = 3000 F 5) REMOTE GREASE INJECTION UNIT REQUIRED 6) STUFFING BOX W/ HYDRAULIC OPERATED PACK-OFF

REQUIRED 7) BALL CHECK VALVE REQUIRED 8) TOOL CATCHER OPTIONAL 9) TOOL TRAP REQUIRED

SHUTTING IN WHILE LOGGING WITH SIDE-ENTRY SUB (WIRELINE ACROSS BOP STACK)

POLICY SHUT-IN PROCEDURE 1) CLOSE ANNULAR AROUND DRILL PIPE AND WIRELINE TO

RESTRICT FLOW 2) INSTALL WIRELINE CLAMP TO DRILL PIPE 3) CUT WIRELINE (ABOVE CLAMP) AT ROTARY TABLE WITH

MANUAL CUTTER

WELL CONTROL MANUAL



4) OPEN ANNULAR AND LOWER DP UNTIL WIRELINE IS BELOW BOP STACK

5) CLOSE ANNULAR OR UPPERMOST RAM AS PER APPROVED SHUT-IN PROCEDURE

FISHING PROCEDURE FOR STUCK LOGGING TOOL IN OPEN HOLE

POLICY STUCK NON-RADIOACTIVE TOOL 1) PULL OFF ELECTRIC LINE AT ROPE SOCKET 2) POH WITH ELECTRIC LINE 3) RIH AND ENGAGE TOOL W/ OVERSHOT ON DRILL STRING

STUCK RADIOACTIVE TOOL

1) CUT AND STRIP OVER ELECTRIC LINE W/ DRILL STRING 2) ENGAGE TOOL WITH OVERSHOT 3) PULL OFF ELECTRIC LINE AT ROPE SOCKET 4) POH WITH ELECTRIC LINE

NOTE: MAY CONSIDER STRIPPING OVER THE ELECTRIC LINE ON A NON-RADIOACTIVE TOOL IF,

§ HOLE CONDITIONS ARE POOR § LARGE HOLE SIZE COMPARED TO TOOL OD § OPEN HOLE SECTION IS NOT KNOWN TO CONTAIN

HYDROCARBONS

LOGGING COMPANIES HAVE A ‘CIRCULATING SUB’ THAT CAN BE MADE UP ON THE DRILL STRING (IN THE EVENT OF A WELL CONTROL SITUATION) TO HANG OFF THE ELECTRIC LINE AND ENABLE CIRCULATION; HOWEVER, THIS MAY BE DIFFICULT TO INSTALL WITH A STRONG FLOW UP THE DRILL PIPE.

RUNNING COILED TUBING

CT BOP REQUIREMENTS FOR LOW PRESSURE APPLICATIONS

POLICY LOW PRESSURE BOP REQUIREMENTS (< 5,000 PSI) 1) SIDE DOOR STRIPPER 2) QUAD BOP 3) FLOW TEE

TO BE USED WHEN LIFTING OR LIVENING A WELL. CT BOP REQUIREMENTS FOR HIGH PRESSURE APPLICATIONS

POLICY HIGH PRESSURE BOP REQUIREMENTS (> 5,000 PSI) 1) SIDE DOOR STRIPPER 2) SECOND SIDE DOOR OR RADIAL STRIPPER 3) QUAD BOP 4) FLOW TEE 5) SHEAR/SEAL AND PIPE/SLIP COMPI

TO BE USED WHEN FLOWING THE WELL WITH COILED TUBING IN THE HOLE.

REMARKS:

PSI

PSI

PSIPSI

THIS TEST:PREVIOUS TEST:

TYPE

COMPANY REPRESENTATIVE SIGNATURE

Revision Date: 10/20/02 Page 1 of 2Form # 2.0

LEFT RIGHT

LOW

HIGH

TIMEHIGH

LINECOCK

LOWER MANUAL

VALVE

HCR KILLUPPER

COCK VALVEVALVE VALVE LINE

LOW

VALVE VALVE VALVE LINE

ANNULAR

CHOKE

PSI

MANIFOLD

MANUAL HCR CHECK SWACO

GRADE

NOTE: HYDRIL TO BE TESTED @ 70% RATED

PSI

WORKING PRESSURE WITH PIPE IN HOLE

EMERGENCY KILL LINE

CUT-OFF

PSI

PSI

TEST OF AUXILIARY SYSTEMS AS PER SAUDI ARAMCO WELL CONTROL MANUAL

SIZE WT

ELECTRIC PUMPS

GALCAPACITY

PSI

KELLYKILL LINE CHOKE LINE

ACCUMULATOR CUT-IN

AIR PUMPS PSIPRESSURE

OPERATING PRESSURE

PRECHARGE PRESSURE DATE LAST CHECKED

VOLUMEGAL PSI

ACCUMULATOR UNIT DATA

SYSTEMS USEABLE

KILL MANUAL HCR

MUD WEIGHT: PCF

PIPE RAMS

ANNULAR

UNIT SIZE

PIPE RAMSBLIND RAMSPIPE RAMS

WT GRADE CONN

BURSTRATING

DRILL PIPE DATACUP PLUG NONE SIZE

TESTER

SIZE DEPTH DEPTH

PRESSURE TESTING BLOWOUT PREVENTERS & RELATED EQUIPMENT

WELL INFORMATION BLOWOUT PREVENTERSHOLE PRESSURE RATINGLAST CASING STRING SET

SHOE

MANIFOLD PRESSUREPRESSURE

PSI

PSI PSI

RIG:

DRILLER SIGNATURE TOOLPUSHER SIGNATURE

WELL NUMBER:

TEST DETAILS

REMARKS:

ALL BOLTS, STUDS & NUTS INSTALLED

ALL RING GASKETS ARE NEW

P.V.T. SET TO ALARM AT 10 BBLS

YES

DRILL PIPE PRESSURE GAUGE

DE-GASSER

NO

ACCUMULATOR BOTTLE AND TEST GAUGE

AND TIGHTEN PROPERLY

ANNULAR PRESSURE GAUGE

SPARE NITROGEN BOTTLES

DRILL PIPE FLOAT VALVE

YES

FILL ADAPTER FOR NITROGEN BOTTLE

DRILLER SIGNATURE TOOLPUSHER SIGNATURE COMPANY REPRESENTATIVE SIGNATURE

CHOKE MANIFOLD LINED UP FOR A HARD SHUT-IN

LOW HIGH

ARE THE BELOW ITEMS ON THE RIG AND IN GOOD WORKING ORDER:

PSI MIN MIN

LOW HIGHDURATION OF TEST

MIN

MIN

TEST PRESSUREUNIT

ALTERNATE BI-WEEKLY TESTS WITH

CLOSE OPEN CLOSE OPEN

BOP TEST IN PSI AND TIMECHARGING SYSTEM ISOLATED

SECSEC

PSISEC SECMIN

ROTATING HEAD AND STRIPPER (PACK-OFF)

STRIPPING VALVE (TIW)

DRILL PIPE BACK PRESSURE VALVE (INSIDE BOP)

SECPIPE RAMS

X-OVER: DC x DP

KELLY COCK WRENCH (S)

ADJUSTABLE CHOKES STEM AND BONNETS

MUD GAS SEPARATOR

SEC SEC

NO

SECPIPE RAMS PSI SECPSI

SECPSI MIN SECMIN SECBLIND RAMS PSISEC SECSEC SEC

SECPIPE RAMS PSI PSI MIN MIN

SEC SECSECPSI MINANNULAR PSI

BOTTLE BANKS ISOLATED

PRESSURE TESTING BLOWOUT PREVENTERS & RELATED EQUIPMENT

Revision Date: 10/20/02 Page 2 of 2Form # 2.0

THIS TEST:PREVIOUS TEST:RIG: WELL NUMBER:

REMARKS:

SEAL #SEAL #

COMPANY REPRESENTATIVE SIGNATURE

INTERNAL COMPONENTSRAMSIZE

RAMPACKER #

PIPE RAMS

UNIT

TYPE

PIPE RAMSANNULAR

SIZE SINGLE/DOUBLE

BLOWOUT PREVENTERSANNULAR PREVENTER

WELL NUMBER:

DESCRIPTION OF BLOWOUT PREVENTERS AND INTERNAL COMPONENTS

BLIND RAMS

BONNET/DOOR

WORKING PRESSURE

WORKING PRESSURE MODEL

RAM PREVENTERS

SIZE MAKE ELEMENT PART #

BLIND

PIPE

INSTALLEDCONN. ROD

SEAL #

DRILLER SIGNATURE TOOLPUSHER SIGNATURE

DATE RAM

SERIAL #

TOP

PIPE

MAKEPIPE

SERIAL #

Form # 1.0 Date: 10/20/02

PIPE RAMS

RIG:

BLOCK #

CAMERON INFORMATION SHEET 01-001 SUBJECT: Cameron High Temperature Shearing Blind Ram (SBR) Blade and Side Packers for 11” and 13-5/8” Cameron U Type Blowout Preventers

CIS 01-001 / 5-24-01 REV / HT SBRs 11 & 13 1

PURPOSE: To provide information on qualification test results and new part numbers assigned to qualified blade and side packers Qualification Requirement: API 16A 2nd Edition, Appendix C plus additional pressure hold time at elevated temperatures Test Conditions: BOP used – Cameron 13-5/8”-10,000 psi U mounted on a special test stump with internal heating system Test Fluid – Synthetic hydrocarbon motor oil (to simulate a mineral oil based drilling mud) Test Temperatures - 250°F, 300°F, and 350°F Test Pressure – 10,000 psi Test Durations – API 16A 2nd Edition, Appendix C – One hour pressure hold all test temperatures

- Cameron Requirement – An additional 8 hour pressure hold - 250°F - An additional 3 hour pressure hold - 300°F and 350°F Results – Standard Cameron Blade and Side Packers qualify to API 16A, 2nd Edition, Appendix C high temperature verification test requirements and successfully complete Cameron required additional 8 hour pressure hold test at 250°F . - High Temperature Cameron Blade and Side Packers qualify to API 16A, 2nd Edition, Appendix C high temperature verification test requirements and successfully completed Cameron required additional 3 hour pressure hold test at 300°F and 350°F .

U BOP Shearing Blind Ram U BOP H2S Shearing Blind Ram

CAMERON INFORMATION SHEET 01-001 SUBJECT: Cameron High Temperature Shearing Blind Ram (SBR) Blade and Side Packers for 11” and 13-5/8” Cameron U Type Blowout Preventers

CIS 01-001 / 5-24-01 REV / HT SBRs 11 & 13 2

Applicable Part Numbers BOP Size - Pressure Rating Description Up to 250°F & 5% H2S Up to 350°F & 35% H2S 11’-10,000 psi Blade Packer 046910-04-00-01 644834-04-00-01 Side Packer 046751-04-00-01 2164284-04 Side Packer 046752-04-00-01 2164285-04 Top Seal 644217-01-00-01 644703-01-00-01 13-5/8”-10,000 psi Blade Packer 644435-01-00-01 644834-01-00-01 Side Packer 046751-01-00-02 645427-01 Side Packer 046752-01-00-02 645428-01 Top Seal 644223-01-00-01 644707-01-00-01 For additional information contact Cameron Elastomer Technology (CET), Katy Texas or your local Cameron representative.

29501 Katy Freeway, Katy, Texas 77494 Tel: 281-391-4615 Fax: 281-391-4640

09/15/02

Spare Parts List for 13-5/8” 10M Type “U” Large Bore Shear Bonnet and Shear Rams

High Temperature and H2S Service Item Part Number Description Qty

1. 2011803-01

BONNET ASSEMBLY: LARGE BORE SHEAR, RIGHT HAND, for 13-5/8" 10M WP TYPE 'U' BOP WITH TANDEM BOOSTER, MANUAL LOCKING SCREW AND BONNET BOLTS, PER API 16A, T-20, OPERATION TEMP RATING 'BF' (0-350 DEG SERVICE), NACE, EST. NET WT. = 3,850 LBS.

1 EA

2. 2011803-02

BONNET ASSEMBLY: LARGE BORE SHEAR, LEFT HAND, for 13-5/8" 10M WP TYPE 'U' BOP WITH TANDEM BOOSTER, MANUAL LOCKING SCREW AND BONNET BOLTS, PER API 16A, T-20, OPERATION TEMP RATING 'BF' (0-350 DEG SERVICE), NACE, EST. NET WT. = 3,850 LBS.

1 EA

3. 041366-12 BONNET BOLT: for LARGE BORE SHEAR Bonnets, 13-5/8" 10M WP TYPE 'U' BOP, MODEL II 8 EA

4. 2164210-09 BONNET REBUILD KIT: for LARGE BORE SHEAR RAM, 13-5/8" 3M/5M/10M WP TYPE 'U' BOP (parts for ONE BONNET), 350 DEG SERVICE

2 EA

5. 644573-03-00-01 BONNET SEAL: for 13-5/8" 3M/5M/10M 'U' BOP, PER API 16A, TEMP CLASS "BF" (0-350 DEG SERVICE) 2 EA

6. 645077-36-00-01 SEAL, LIP: CONNECTING ROD; for 13-5/8" 3M-15M, 20-3/4" 3M, 21-1/4" 2M and 26-3/4 3M TYPE 'U' BOP, 5.505" OD X 4.008" ID X 0.938" LG, PER API 16A, TEMP CLASS "BF" (0-350 DEG SERVICE)

2 EA

7. 644781-03 RAM ASSEMBLY: H2S SHEARING BLIND; UPPER, for 13-5/8" 3M/5M/10M WP TYPE 'U' BOP, CAMRAM 350 (TM) 1 EA

8. 644781-04 RAM ASSEMBLY: H2S SHEARING BLIND; LOWER, for 13-5/8" 3M/5M/10M WP TYPE 'U' BOP, CAMRAM 350 (TM) 1 EA

9. 644581-01-00-01 INSERT BLADE: UPPER, H2S SBR, for 13-5/8" 10M WP TYPE 'U' AND 'T' BOP, PER QP-10005-01 1 EA

10. 644581-02-00-01 INSERT BLADE: LOWER, H2S SBR, for 13-5/8" 10M WP TYPE 'U' AND 'T' BOP, PER QP-10005-01 1 EA

11. 644834-01-00-01 BLADE PACKER: SBR, for 13-5/8" 3M-15M WP TYPE 'U' BOP, PER API 16A, TEMP CLASS "BF" (0-350 DEG SERVICE) 1 EA

12. 645427-01 SIDE PACKER: SBR, for 13-5/8" 3M-10M WP TYPE 'U' BOP, CAMRAM 350 (TM) 2 EA

13. 645428-01 SIDE PACKER: SBR, for 13-5/8" 3M-10M WP TYPE 'U' BOP, CAMRAM 350 (TM) 2 EA

14. 644707-01-00-01 TOP SEAL: for 13-5/8" SBR, 3M/5M/10M WP TYPE 'U' BOP, CAMRAM 350 (TM) HIGH TEMP, API 16A, TEMP CLASS "BF" 2 EA

15. 644582-01 MODIFIED SET SCREW: for 13-5/8" 10M TYPE ‘U’ UPPER SHEARING BLIND RAM, .750-10 UN-2 2 EA

16. 200231 PIN: SPIROL - .250 X 1.000 SST 18-8 2 EA

17. 2164148-02 REPAIR KIT: TANDEM SHEAR BOOSTER, COMPOSITE STYLE OR ORIGINAL STYLE, 11" 15M AND 13-5/8" 3M-10M TYPE 'U' BOP (QUANITY for 1 UNIT)

1 EA

09/15/02

Spare Parts List for 11” 10M Type “U” Large Bore Shear Bonnet and Shear Rams

High Temperature and H2S Service Item Part Number Description Qty

1. 2164067-02

BONNET ASSEMBLY: LARGE BORE SHEAR, RIGHT HAND, for 11" 10M WP TYPE 'U' BOP WITH TANDEM BOOSTER, MANUAL LOCKING SCREW AND BONNET BOLTS, API 16A, T-20, OPERATION TEMP RATING 'BF' (0-350 DEGREE SERVICE), NACE, EST. NET WT. 2,620 LBS.

1 EA

2. 2164067-01

BONNET ASSEMBLY: LARGE BORE SHEAR, LEFT HAND, for 11" 10M WP TYPE 'U' BOP, WITH TANDEM BOOSTER, MANUAL LOCKING SCREW AND BONNET BOLTS, API 16A, T-20, OPERATION TEMP RATING 'BF' (0-350 DEGREE SERVICE), NACE, EST. NET WT. 2,620 LBS.

1 EA

3. 041366-05 BONNET BOLT: for LARGE BORE SHEAR RAM, 11" 10M WP TYPE 'U' BOP, MODEL II 8 EA

4. 2164210-12 BONNET REBUILD KIT: for LARGE BORE SHEAR RAM, 11" 3M/5M/10M WP TYPE 'U' BOP (PARTS for ONE BONNET), 350 DEGREE SERVICE

2 EA

5. 644573-02-00-01 BONNET SEAL: 11" 3M/5M/10M WP TYPE 'U' BOP, API 16A, TEMP CLASS "BF" (0-350 DEGREE SERVICE) 2 EA

6. 645077-38-00-01 SEAL, LIP: CONNECTING ROD; fOR 11" 5M/10M WP TYPE 'U' BOP, - 4.867" OD x 3.383" ID x 0.688" LG, API 16A, TEMP CLASS "BF" (0-350 DEGREE SERVICE)

2 EA

7. 645011-01-00-01 RAM ASSEMBLY: H2S SHEARING BLIND; UPPER, for 11" 5M/10M WP, TYPE 'U' BOP, API 16A, TEMP CLASS 'BF' (0-350 DEGREE SERVICE)

1 EA

8. 645011-02-00-01 RAM ASSEMBLY: H2S SHEARING BLIND; LOWER, for 11" 5M/10M WP, TYPE 'U' BOP, API 16A, TEMP CLASS 'BF' (0-350 DEGREE SERVICE)

1 EA

9. 645010-01-00-01 INSERT BLADE: UPPER, H2S SBR, for 11" 5M/10M WP TYPE 'U' BOP, API 16A 1 EA

10. 645010-02-00-01 INSERT BLADE: LOWER, H2S SBR, for 11" 5M/10M WP TYPE 'U' BOP, API 16A 1 EA

11. 644834-04-00-01 BLADE PACKER: SBR, for 11" 3M-15M WP TYPE 'U' BOP, API 16A, TEMP CLASS "BF" (0-350 DEGREE SERVICE) 1 EA

12. 2164284-04 SIDE PACKER: FOLDOVER SHEAR RAM, for 11" 3M-10M WP TYPE 'U' BOP, API 16A, TEMP CLASS "BF" (0-350 DEGREE SERVICE)

2 EA

13. 2164285-04 SIDE PACKER: FOLDOVER SHEAR RAM, for 11" 3M-10M WP TYPE 'U' BOP, API 16A, TEMP CLASS "BF" (0-350 DEGREE SERVICE)

2 EA

14. 644703-01-00-01 TOP SEAL: for 11" SBR, 3M/5M/10M WP TYPE 'U' BOP, CAMRAM 350 (TM) HIGH TEMP, API 16A, TEMP CLASS "BF" 2 EA

15. 644582-01 MODIFIED SET SCREW: for 11" 10M TYPE ‘U’ UPPER SHEARING BLIND RAM, .750-10 UN-2 2 EA

16. 200231 PIN: SPIROL - .250 X 1.000 SST 18-8 2 EA

17. 2164148-03 REPAIR KIT: TANDEM SHEAR BOOSTER, COMPOSITE STYLE OR ORIGINAL STYLE WITH ST/STL END CAP, for 11" 3/5/10M TYPE 'U' BOP (QUANTITY FOR ONE UNIT)

1 EA

10/01/02

Shaffer A Varco Company

Spare Parts List for 13-5/8” 10M

Model ‘SL’ Large Bore ‘V’ Shear Rams High Temperature and H2S Service

Item Part Number Description Qty

1. 124992 BOOSTER KIT: 10” BOOSTER ASSEMBLY CONVERSION KIT FOR 13-5/8” 10M WP TYPE ‘SL’ RAM BOP, NACE (COMPLETE WITH 22 COMPONENTS).

2 EA

2. 114651 RAM SHAFT: POSLOCK FOR 13-5/8" 10M WP TYPE 'SL' BOP, NACE. 2 EA

3. 132492 RAM SHAFT SUB-ASSEMBLY (RSSA): FOR 13-5/8" 10M WP TYPE 'SL' BOP, NACE. 2 EA

4. 030102 CYLINDER O-RING: 2 EA

5. 030791 CYLINDER O-RING: 2 EA

6. 030105 CYLINDER BACK-UP RING: 2 EA

7. 030061 MANIFOLD O-RING: 8 EA

8. 030065 HINGE BRACKET O-RING: 4 EA

9. 134481 POSLOCK PISTON ASSEMBLY: FOR 13-5/8" 10M WP TYPE 'SL' BOP, NACE. 2 EA

10. RAM V-SHEAR: COMPLETE WITH 13-5/8” 10M WP ULTRATEMP ™ ELASTOMERS (350 DEGREES F AND 20% H2S) 1 EA

11. RAM RUBBER ASSEMBLY: UPPER, V-SHEAR, ULTRATEMP ™ (350 DEGREES F AND 20% H2S) 1 EA

12. RAM RUBBER ASSEMBLY: LOWER, V-SHEAR, ULTRATEMP ™ (350 DEGREES F AND 20% H2S) 1EA

CAMERON INFORMATION SHEET 02-001 SUBJECT: Cameron Extended Range High Temperature VBR-II Packers for Cameron 13-5/8” U Type Blowout Preventers

CIS 02-001 / 6-11-02 / Ext Range HT VBR-II 1

PURPOSE: To provide information on qualification test results and new part numbers assigned to 250°F - 5000 psi Extended Range HT VBR-II packers for the 13-5/8" Cameron U BOP. Qualification Requirement: API 16A 2nd Edition, Appendix C plus additional pressure hold time at elevated temperature. Test Conditions: BOP used – Cameron 13-5/8”-10,000 psi U BOP mounted on a special test stump with internal heating system. Test Fluid – Synthetic hydrocarbon oil (to simulate a mineral oil based drilling mud). Test Temperatures - 250°F Test Pressure – 5,000 psi Test Durations – API 16A 2nd Edition, Appendix C – One hour pressure hold at 250°F

- Cameron-Saudi Aramco Requirement – An additional 7-hour pressure hold at 250°F Results – Extended Range HT VBR-II Packers P/N 2164765-01 successfully completed: 1-API 16A, 2nd Edition, Appendix C high temperature verification test requirements

for one hour on both 5-7/8" and 3-1/2" pipe mandrels at 250°F and 5000 psi. 2-Cameron-Saudi Aramco requirement - an additional 7 hour pressure hold test on both 5-7/8" and 3-1/2" pipe mandrels at 250°F and 5000 psi. Total time at 250°F and 5000 psi, 16 hours. 3-API 16A fatigue test (546 closures and 78 pressure tests) at ambient temperature.

Top Seal P/N 2164807-01

Ram P/N 2164404-01 Extended Range HT VBR-II Packer P/N 2164765-01

Ram Subassembly P/N 2164806-01

250°F - 5000 psi Extended Range HT VBR-II Packer & Top Seal

CAMERON INFORMATION SHEET 02-001 SUBJECT: Cameron Extended Range High Temperature VBR-II Packers for Cameron 13-5/8” U Type Blowout Preventers

CIS 02-001 / 6-11-02 / Ext Range HT VBR-II 2

Applicable Part Numbers BOP Size Pressure Rating Description Part Number 13-5/8” 5,000 psi Ram subassembly 2164806-01 Ram 2164404-01 Ext. Range HT VBR-II Packer 2164765-01 HT/SS VBR Top Seal 2164807-01

Note: The Extended Range HT VBR-II packers and HT/SS top seals are molded using CAMLAST(tm) elastomer, which provides H2S resistance up to 35%. For additional information contact Cameron Elastomer Technology (CET), Katy Texas or your local Cameron representative.

29501 Katy Freeway, Katy, Texas 77494 Tel: 281-391-4615 Fax: 281-391-4640

Previous Issue: 30 May, 2001 Next Planned Update: 1 June, 2006 Revised paragraphs are indicated in the right margin Page 1 of 32 Primary contact: Abdullah A. Al-Ghamdi on phone 875-2724

Engineering Standard

SAES-B-062 30 September, 2001 Onshore Wellsite Safety

Loss Prevention Standards Committee Members Abdullah A. Al-Ghamdi, Chief Fire Prevention Engr., Chairman Al-Sayed, S. M., FPE, Jeddah Area Al-Sultan, S. A., LFPE, Dhahran Area Bard T. E., LFPE, Riyadh Area E.A. Ashoor, LFPE, RT Area Fadley, G. L., Editor Nolan, D. P., LFPE, Abqaiq Area

Saudi Aramco DeskTop Standards Table of Contents 1 Scope............................................................. 2 2 Conflicts and Deviations................................ 2 3 References..................................................... 2 4 Definitions...................................................... 3

5 Determination of Rupture Exposure Radius (REF)......................... 7

6 Wellsite Location............................................ 8 7 Population Analysis Procedure.................... 11 8 Well Safety Valves and Wellsite Hardware.. 12 9 Abandoned Wells......................................... 15 10 Drilling Rig Access Routes........................... 15 Appendix 1 – Procedure for Determining

Document Responsibility: Loss Prevention SAES-B-062 Issue Date: 30 September, 2001 Next Planned Update: 1 June, 2006 Onshore Wellsite Safety

Page 2 of 32

RER of Oil and Gas Wells............ 16

1 Scope

1.1 This Standard covers the minimum mandatory requirements for site layout, wellhead protection, access, and flow isolation for all wells including oil and gas production wells, hydrocarbon injection wells, observation wells, abandoned wells, suspended wells, and wellsite facilities located onshore. Water injection, disposal, and supply wells, which are open to or pass through a geological zone and could produce hydrocarbons, are also covered by this Standard.

1.2 This standard shall apply in the following circumstances:

1.2.1 All new wellsites.

1.2.2 All new wells drilled at existing wellsites.

1.2.3 Existing wells located in areas that have become populated per this Standard shall be upgraded only when a workover is required for other remedial work.

2 Conflicts and Deviations

2.1 Any conflicts between this Standard and other applicable Saudi Aramco Engineering Standards (SAESs), Saudi Aramco Materials System Specifications (SAMSSs), Saudi Aramco Standard Drawings (SASDs), or industry standards, codes, and forms shall be resolved in writing by the Company or Buyer Representative through the Manager, Loss Prevention Department of Saudi Aramco, Dhahran.

2.2 Direct all requests to deviate from the Standard in writing to the Company or Buyer Representative, who shall follow internal company procedure SAEP-302 and forward such requests to the Manager, Loss Prevention Department of Saudi Aramco, Dhahran.

3 References

All referenced specifications, standards, codes, forms, drawings, and similar material shall be of the latest issue (including all revisions, addenda, and supplements) unless stated otherwise.

3.1 Saudi Aramco References


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Saudi Aramco Engineering Procedure

SAEP-302 Instructions for Obtaining a Waiver of a Mandatory Saudi Aramco Engineering Requirement

Saudi Aramco Engineering Standards

SAES-B-064 Onshore and Nearshore Pipeline Safety

SAES-J-505 Combustible Gas and Hydrogen Sulfide in Air Detection Systems

SAES-L-022 Design of Wellhead Piping, Flowlines, Trunklines and Testlines

SAES-M-006 Fencing

Saudi Aramco Materials System Specification

45-SAMSS-005 Wellhead Equipment

Saudi Aramco Standard Drawings

AA-036247 Windsock Pole

AA-036454 Remote Controls for Onshore Wells

AB-036685 Wellhead Guard Barrier

3.2 Industry Codes and Standards

American Petroleum Institute

API RP 14B Design, Installation, Repair and Operation of Subsurface Safety Valve Systems

4 Definitions

Absolute Open Flow (AOF): In general terms, the rate of flow that would be produced by a well if the only back-pressure at the surface is atmospheric pressure.

Choke: An adjustable pressure control valve that is used to control backpressure on the well. Controlling the backpressure adjusts the production rate of the well.

Drilling Island: A well site for drilling one or more wells, normally used in populated areas to minimize land usage. A drilling island is an exclusive land use area.

Drilling Pad: A compacted area of marl located at the well site. The drilling pad is required to be level for use by drilling and workover rigs.


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Gas-Oil Ratio (GOR): The ratio of volume of gas produced from a well in a barrel of crude oil at standard conditions (14.7 psia, 15°C).

High Pressure Well: Wells where the shut-in wellhead pressure is expected to exceed 20,700 kPa (3000 psig).

Low Pressure Well: Wells where the shut-in wellhead pressure is not expected to exceed 20,700 kPa (3000 psig).

LFL: Lower flammable limit of a fuel vapor in air mixture. If a vapor/air mixture is above the LFL, a fire is likely in the presence of an ignition source.

Major Facility: The outer-most security fence, property line, or other demarcation of land-use claim of refineries, large gas treatment, NGL plants, larger oil processing facilities, and the property line of any third party manufacturing facilities (Refer to Table 1 below for examples).

Table 1 - Examples of Major Facilities

Refineries Gas Treating NGL Oil Process Terminals Non-Aramco

Jeddah Berri Juaymah Abqaiq Plants Complex

Juaymah SCEC Power Generation (formerly SCECO)

Rabigh Uthmaniyah Yanbu Safaniya Onshore GOSP Complex

Jeddah SWCC Treatment

Ras Tanura Shedgum Tanajib Plants Complex

Ras Tanura (North & South)

Commercial International Airports

Riyadh Hawiyah Shaybah Central Process Facilities

Yanbu Jubail or Yanbu Industrial Complexes

Haradh

Non-Associated Gas Fields: Areas that are developed for the primary purpose of producing natural gas. The produced gas is not a by-product of crude oil production.

Population: A grouping of people normally indicated by the existence of buildings. Separation spacing from a well shall be measured from the nearest fence or other land mark. For industrial, military, and other larger non-residential land claims, determine the spacing based on the nearest anticipated development within the confines of the fence during the anticipated period of drilling.


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Populated Area: A well is in a populated area if the population density based on counting occupied buildings exceeds 20 occupied buildings inside the 30 ppm rupture exposure radius (RER). In addition, for the purposes of this Standard, a well is in a populated area if a school, hospital, hotel, penal institution, or retail complex, whether existing or planned, is inside the 30 ppm RER of that well.

Rupture Exposure Radius (RER):

1) For toxic effects, the rupture exposure radius refers to the horizontal distance from a leak source to a specified level of hydrogen sulfide (H2S) concentration in parts per million (ppm).

2) For a flammable gas hazard, the rupture exposure radius refers to the horizontal distance from a leak source to the ½ Lower Flammable Limit (LFL).

Surface Safety Valve (SSV): An automated spring-assisted fail-safe valve installed on a wellhead to automatically shut in flow during an abnormal condition such as high or low pressure of the flowline. This can be the upper master valve, a wing valve (upstream of choke), or a production valve (downstream of the choke).

Suspension Procedure: Wireline or workover rig procedures for securing a standing well from production on a long-term basis.

Subsurface Safety Valve (SSSV): An automated valve installed below ground level in the tubing string of an oil or gas well. The SSSV is used to shut in flow during an abnormal condition. SSSVs, when required, shall be installed 60 m or more below ground level per API RP 14B.

Wellhead: The valve manifold directly at the top of the well bore. The wellhead consists of several specialized valves including the following:

a) Crown Valve: Topmost valve of the wellhead. This valve is used for wireline and coil tubing access to the well.

b) Lower Master Valve: The first valve on a wellhead. This is not a surface safety valve (SSV).

c) Upper Master Valve: A second isolation gate valve just above the Lower Master Valve on a wellhead. If this is automated, it is considered a surface safety valve (SSV).

d) Wing Valve: The valve on the side branch of the wellhead, normally located immediately upstream of the choke.


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7-1/16" 3M PSI Onshore Production Tree

SAUDI ARAMCO 3M PSI WP WOG 6M PSI TP

Figure 1 - Example of Wellhead (from 45-SAMSS-005, Figure 6)


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Wellsite: A wellsite consists of wellhead(s), associated drilling pad, a well flare/burn pit area or areas, and flare/burn pit buffer zone(s). The entire wellsite constitutes an exclusive land use area. No other uses are permitted in this area, except as allowed by this Standard. Size of the wellsite and distances between wellheads shall be specified by Drilling and Workover Engineering, Drilling Operations, E&P Facilities & Technology, and the Proponent Operating Department, on a case-by-case basis.

Well Status: Wells that are not flowing oil or gas may be described by the following terms:

a) Abandoned Well: A well that is permanently plugged with cement. This well cannot be produced again.

b) Observation Well: A well drilled to monitor reservoir conditions such as bottom-hole pressure in the reservoir.

c) Suspended Well: A well that has been shut-in on a long term basis with all productive zones isolated and production shut-off on a long-term basis.

d) Standing Well: A well that is shut-in awaiting action, such as flowline tie-in or well perforation, before it can be returned to production.

5 Determination of Rupture Exposure Radius (RER)

5.1 Three concentric circles representing the three rupture exposure radii - 30 ppm, 100 ppm hydrogen sulfide (H2S) and ½ lower flammable limit (LFL) shall be plotted from the well's proposed surface location as shown in Figure 2 below. Refer to Appendix 1 for procedures to determine the RERs.

5.2 For fields, reservoirs, or service not listed in Appendix 1, the rupture exposure radius shall be obtained from the Saudi Aramco Loss Prevention Department's Technical Services Unit. In order to calculate the RER, the following information should be provided with the request: Well composition of produced fluid (mole %), temperature (Flowing Wellhead Temperature, FWHT), and AOF for gas wells or maximum flow rate and GOR for oil wells.


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Figure 2 – RERs

A well with population inside the 30 ppm H2S RER as shown above is considered to be in a populated area if the population index is above 20 or if a school, hospital, major facility, etc, are inside the RER (see 6.3).

6 Wellsite Location

6.1 Wells that are drilled through a hydrocarbon bearing formation shall be located so that no occupied building or major facility is within the well's 100 ppm H2S or ½ LFL RER. Minimum spacing shall not be less than that stated in Table 2.

Exceptions:

Farms and other developments used primarily for agriculture.

GOSPs, manifolds, pipelines, Khuff and Jouf gas distribution facilities, and their associated utilities are allowed to be within the 100 ppm H2S circle but not within the ½ LFL RER nor closer than the minimum spacing stated in Table 2.


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Table 2 - Spacing from Oil and Gas Wells (4)

Facility Minimum Spacing from the Wellhead

Pipelines (1, 2) 60 m Overhead powerlines for site-related CP, etc. (<69 kV); site related rectifiers 100 m

Main overhead powerlines 200 m

Saudi Aramco or Government roadways (2) 100 m

Divided Limited-Access Expressways (2) 150 m

Railroads (3) 150 m

Major electrical distribution centers 450 m

Occupied buildings, major facilities 450 m

Non-well related flares and flare burn pits 450 m

Hospitals and schools 1000 m

1) The existing elevated marl pad around wellhead(s) on a wellsite shall not be crossed by a pipeline. Rig access shall not be obstructed by installation of a pipeline. In addition, the minimum spacing does not apply to flowlines that are associated with a multi-well wellsite.

2) New wells may require additional spacing from existing flowlines for wellsite construction and drilling operations. Spacing shall be increased as needed at the request of the Drilling Services or Drilling Operations Departments.

3) Spacing from the well to the closest edge of right-of-way, such as a fence. 4) Minimum spacing applies to wells drilled after March 30, 2001.

6.2 Water gravity injector, power injector and supply wells that penetrate hydrocarbon formations shall be spaced the same as hydrocarbon producing wells. Injector and supply wells that do not penetrate hydrocarbon bearing formations shall have a basic 60 m minimum spacing requirement from plant equipment, buildings, etc. Gas injection wells shall use the same location criteria as producing gas wells.

6.3 A well is in a populated area if the population density index within the 30 ppm H2S rupture exposure radius exceeds 20, or if a school, hospital, hotel, penal institution, retail shopping mall, or major facility, existing or planned, is included within the 30 ppm H2S rupture exposure radius of that well (see Figure 2).

Commentary Notes:

For purposes of this Standard, roads are not deemed to generate populated areas.

Where wells are located near areas of potential concern, such as roads, parking areas, or camp sites, the Proponent


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Operating/Engineering Department shall determine whether additional precautionary measures, such as subsurface safety valves, fencing, etc., are required.

6.4 Wells to be drilled or wells subject to workover in a populated area shall implement the following additional precautionary measures in addition to the normal drilling safety program during drilling of hydrocarbon zones. Other drilling precautionary measures may be added at the request of the Manager, Loss Prevention or the General Manager of Drilling and Workover.

Precautionary measures during drilling in a populated area:

1. Rig-site H2S monitoring systems with 24-hour safety man coverage.

2. Placement of remote H2S monitors in the vicinity of populations and nearby facilities to monitor H2S levels at those locations in an emergency.

3. An additional one-hole volume of kill-weight mud available at the drillsite for immediate use.

4. Capability of cutting the drill pipe with shear rams.

5. On-site coverage 24 hours a day by on-site foremen (minimum 2-man coverage on 12-hour shifts) with authority for immediate ignition of the well without prior approval in the event of loss of well control.

6. Capability of burning gas in a controlled release using parallel production separators and an elevated flare with continuous flare pilot (Only for wells to protect population within the 30 ppm H2S RER; the use of this equipment is not required for drilling near GOSPs, process plants or major facilities).

7. An enhanced rig-site emergency contingency action plan.

8. Other applicable safeguards as needed.

Commentary Note:

The requirements of 6.4 are not intended for non-rig flaring.

6.5 Under no circumstances shall population be exposed to over 30 ppm H2S gas concentration for more than 1 hour.

6.6 Well flare burn pits shall be subject to the same spacing from population and major facilities as well spacing. The exceptions to 6.1 shall also apply to flare burn pits. Minimum spacing shall meet Table 3.


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6.6.1 Oil wells and low-pressure gas wells shall have at least one flare while being drilled.

6.6.2 High-pressure gas well shall have two flares while being drilled.

6.6.3 Flare burn pits shall be at predominantly downwind and crosswind locations, at least 60 meters from the well (300 m for high-pressure gas wells) ranging from 60 to 270 arc degrees from true North. Flare burn pits shall be placed to point away from populations and facilities as much as possible.

6.6.4 If there are two flares, they should be a minimum of 90 degrees and a maximum of 180 degrees from each other and pointing away from populations and facilities as much as possible.

Table 3 - Spacing from Well Flare Burn Pits (3)

Facility Minimum Spacing

from Oil & Gas Flare Burn Pits

Well (1) 60 m (Oil & LP Gas) 300 m (HP Gas Well)

Existing Wellheads 60 m (Oil & LP Gas) 150 m (HP Gas Well)

Pipelines (Above Ground) 60 m

Pipelines (Buried) (2) 15 m

Main Overhead Powerlines 200 m Overhead Powerlines for Site-Related CP, etc., (<69 kV); Site Related Rectifiers 100 m

Powerlines (Buried) (2) 15 m

Saudi Aramco or Government Roadways (3) 100 m (Oil Wells and LP Gas) 200 m (HP Gas Wells)

Divided Limited-Access Expressways (3) 450 m (Oil and Gas Wells)

Railroads (3) 200 m

Population 450 m

Non-well Related Flares and Flare Burn Pits 450 m

Hospitals and Schools 1000 m

1) Spacing of the flare burn pit from the well being drilled shall be a minimum distance of 60 m from the well for an oil well and 300 m minimum for a high-pressure gas well. Wells are to be spaced a minimum of 60 m from the closest edge of a flare burn pit for an oil well or LP gas well and 150 m from a flare for a HP gas well. A minimum of 60 m buffer zone shall be maintained around the outside of each burn pit (not on the wellsite side). The edges of the burn pits shall have a 2 m high berm (minimum elevation above flare outlet center).

2) Buried CP powerlines, flowlines, and trunklines related to a wellsite shall have no other spacing restrictions provided the powerlines do not interfere with rig access or future production flare operations.

3) Spacing from the closest edge of the flare burn pit to the edge of the right-of-way.


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6.7 For existing wells in populated areas, the special precautions in 6.4 shall be used for workovers. Precautions appropriate for stimulation and wireline work on existing wells shall be as requested by the Proponent Operating Department, Drilling and Workover Services, and Loss Prevention as needed.

7 Population Analysis Procedure

7.1 The boundaries of Saudi Aramco and non-Saudi Aramco development areas, present and planned, within the rupture exposure radius of a well location shall be obtained from the Land and Lease Division of Government Affairs Services Department.

7.2 The population density index at a well location is defined as the sum of the existing density index and the virtual density index values for the site.

7.3 Buildings having more than 4 stories shall be included in the population density index as a number of equivalent buildings. The number of equivalent buildings shall be calculated by dividing the number of stories in the building by 3 and rounding up to a whole number.

7.4 To determine the existing density index for a well location, count the number of buildings lying within the rupture exposure radius of the well. The resulting whole number is the existing density index value.

7.5 For areas within the rupture exposure radius of a well which are planned for development, the virtual density index shall be calculated as follows:

7.5.1 Calculate the land area in square meters (m²) of each development which is included within the rupture exposure radius of the well.

7.5.2 Multiply the included area by 0.00075 and round up. The resulting whole number is the virtual density index for this well location.

7.6 Not to be included in these calculations are temporary buildings that will be in place for less than 6 consecutive months or that will be gone by the time the well is spudded.

8 Well Safety Valves and Wellsite Hardware

8.1 Hydrocarbon Producing and/or Hydrocarbon Injection Wells - General Requirements

8.1.1 All well installations shall be in accordance with the specifications prepared by Saudi Aramco Drilling and Workover Engineering. Refer to


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45-SAMSS-005 for the minimum requirements for Saudi Aramco oil and gas production trees, wellheads, valves and miscellaneous equipment relating to the wellhead. Naturally flowing hydrocarbon wells shall be completed in a manner that permits flow only through a tubing string equipped with a downhole packer or polished bore receptacle.

8.1.2 Requirements for wellhead piping, flowlines, trunklines, and testlines are covered in SAES-L-022.

8.1.3 All wells shall have a manual lower master valve.

8.1.4 At the discretion of the Proponent Operating Department, oil wells may be equipped with manual remote operators attached to the master valve and/or wing valve. If manual remote operators are installed on oil wells, they shall be in accordance with Standard Drawing AA-036454.

8.1.5 Any lockout device used to temporarily hold a surface safety valve (SSV) in the open position by restricting movement of the valve stem shall be constructed of fusible materials with a melting point 30°C above the higher of the flowing wellhead or maximum design ambient temperature.

8.2 Safety Valves for HP Gas Producing Wells

8.2.1 All high-pressure gas production wells shall have at least two spring-assisted failsafe surface safety valves (SSVs).

8.2.2 The two SSVs shall be triggered when an abnormally high or low pressure is sensed in the piping to the well. Fusible devices, with a set point 30°C above the higher of the flowing wellhead or maximum design ambient temperature, shall be installed on the wellhead to close the safety valves.

8.2.3 At the discretion of the Proponent Operating Department, addition of other automated valves, such as subsurface safety valves, shall be installed as requested.

8.3 Safety Valves on Oil Wells and Low Pressure Gas Wells

8.3.1 Where an oil well or low pressure gas well is in a populated area or where the associated flowline has Location Class 3 or 4 populations (as specified in Tables 1 and 2 of SAES-B-064), the wellhead shall be provided with an SSV and SSSV.


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8.3.2 For all existing oil wells and low pressure gas wells in populated areas or where areas become populated due to growth of communities, those wells shall remain active, but shall require installation of a SSV and SSSV. The upgrade shall be done only when other needs justify the use of a rig on the well.

8.3.3 The upper wellhead master valve shall be a spring-assisted fail-safe surface safety valve (SSV), triggered when an abnormally high or low pressure is sensed.

8.3.4 A subsurface safety valve (SSSV), per API RP 14B specification, shall be installed more than 60 m below ground level in oil wells. The SSSV shall be triggered when an abnormally high or low pressure is sensed.

8.3.5 A fusible device with a melting point 30°C above the higher of the flowing wellhead temperature or maximum design ambient temperature, shall be installed on the wellhead to trigger the SSV and SSSV systems.

Commentary Note:

Values for pipeline associated RERs are found in SAES-B-064, Tables 1 and 2. Location Class 3 is where the pipeline RER includes areas with a population index greater than 30. Location Class 4 is where the pipeline RER includes 4-story or greater buildings, schools, hospitals, hotels, prisons, shopping malls or similar retail complexes.

Table 4 – Well Safety Valves

Additional Drilling Precautions Automated SSV Automated SSSV

Oil/LP Gas Well – Unpopulated Area (a) No No (a) No (a)

Oil/LP Gas Well – Populated Area Yes Yes Yes

HP Gas Well No Yes, 2 SSVs (b)

PWI Well – Unpopulated Area No No No

PWI Well – Populated Area Yes No No

Note a Even if the well is in an unpopulated area, if the flowline passes through a populated

area per 8.3, an SSV and SSSV shall be required. Note b HP gas production wells shall have at least two spring-assisted failsafe SSVs.

Addition of other automated valves, such as subsurface safety valves, shall be installed where required by the Proponent Operating Department per Section 8.2.


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8.4 Hydrocarbon Injection Wells

Hydrocarbon injection well flowlines shall each be provided with a check valve in the wellhead piping.

8.5 Observation Wells

Wells shall be equipped with the relevant safety devices equivalent in function to those that would be required for a producing well unless suspended with a subsurface plug or other acceptable method.

8.6 Suspended Wells

Wells shall be suspended in accordance with Producing Engineering requirements. Suspension procedures for wells shall be documented by Producing Operations and shall be available for review.

8.7 Vehicular Crash Protection and Fencing

8.7.1 All wellheads shall be protected with a guard barrier per Saudi Aramco Standard Drawing AB-036685.

8.7.2 Wellsites in populated areas shall be enclosed by a fence meeting the specifications of SAES-M-006 (Type III). The fence shall have four lockable vehicle gates, one in each quadrant locked at all times. Keys shall be kept with the Proponent Operating Department. Two gates shall be a minimum of 18 m wide rig-access gates. The locations of these rig-access gates shall permit access to all wells on the wellsite from either gate.

8.8 A wind sock pole per Saudi Aramco Standard Drawing AA-036247 and a wind sock per SAMS Catalog Number 21-590-600 are to be permanently installed at each hydrocarbon production or injection wellsite in populated areas.

9 Abandoned Wells

The following requirements apply to a wellsite only if all its wells have been permanently plugged and if it is located in a populated area:

9.1 The perimeter of the drilling pad shall be provided with a fence (SAES-M-006, Type III) if there is no fence at the perimeter of the buffer zone.

9.2 The fence shall have one lockable vehicle gate 10 m wide.

9.3 One access route 10 m wide shall be maintained to the wellsite gate.


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10 Drilling Rig Access Routes

Two access routes shall be available to each wellsite. These shall meet the following requirements:

10.1 Each access route shall be 18 m wide, terminating at a rig access gate.

10.2 Vertical clearance over the access routes shall be 14 m minimum.

10.3 An access route shall not include grades or transverse slopes of more than 5%.

10.4 No obstruction is allowed on an access route.

10.5 The minimum radius of curvature of access routes shall be 70 m. The center point of all access route curves shall be outside the wellsite served.

10.6 One of the access routes required by paragraph 10.1 above shall have within it a prepared roadway consisting of a compacted marl running surface 0.3 m thick and 9.0 m wide with 2.5 m wide shoulders, giving a total clear road width of 14 m.

Revision Summary 30 May, 2001 Major revision. 30 September, 2001 Editorial revision to delete "Populated Area" from the heading of Section 6.


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APPENDIX 1 – Procedure for Determining RER of Oil and Gas Wells

Introduction

To allow for more cost-effective well spacing, while at the same time maintaining a safe distance between wells and exposed populations, SAES-B-062 provides variable rupture exposure radii (RER) that are based on field and well conditions (i.e., the well fluid composition and maximum potential release rate).

This appendix is based on a comprehensive analysis of RERs for Saudi Aramco oil and gas wells. Exploration and Producing Facilities and Technology Department (E&P FTD) (PRED/1-099-99) provided the data used for the RER calculations. Tables A7 and A8, at the end of this Appendix, summarize the data provide by E&P FTD. The RER calculations were made in accordance with LPD Guidelines for Determining the Consequences of Well Blowouts. Note that the information in Tables A7 and A8 are based on the latest LPD gas dispersion model PHAST (Version 6.0). The RERs may change in future updates of SAES-B-062 as a result of changes in well data or refinements in the models. If the information for the well or production zone needed is not in Appendix 1, contact the Supervisor, Technical Services Unit, Loss Prevention Department.

The following sections illustrate the use of the correlations for predicting RERs for oil and gas wells. The correlations are of the form RER = aQb, where a and b are field- specific constants and Q is based on the release rate of gas from the well. Correlations are provided for the following oil and gas fields:

Non-Associated Gas Fields

North Ghawar Areas-Ain Dar and Shedgum South Ghawar Area-Haradh

Central Ghawar Areas-Uthmaniyah Qatif

South Ghawar Area-Hawiyah Berri

Oil Fields

Abqaiq (Abqaiq Cap Gas) Haradh

Abu Hadriyah Harmaliyah

Abu Jiffan Hawiyah

Ain Dar Khurais

Berri Onshore Khursaniyah

Dammam Mazalij

Fadhili Qatif

Fazran Shedgum


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Uthmaniyah

The following sections explain and demonstrate the process of RER calculations. Worksheets for calculating RERs are provided at the end of this Appendix.

Procedure for Determining RER of Gas Wells

Sour gas wells are considered in this Standard to have three Rupture Exposure Radii (RER): a 100 ppm H2S RER (RER100 ppm), a 30 ppm H2S RER (RER30 ppm) and a ½ LFL RER (RER½ LFL). Sweet gas wells would only have a RER½ LFL. These radii are used in SAES-B-062 to determine spacing requirements. Follow these steps when determining the RER for a gas well.

1. Identify the gas field and reservoir for the well of interest (Contact Gen Supv'r., Oil or Gas Facilities & Projects Division, E&P FTD) and obtain the Absolute Open Flow (AOF) and mole fraction of hydrogen sulfide (H2S) in the gas stream. Note that the correlations included in this appendix are based upon the expected upper and lower range of AOFs and H2S content in the gas stream.

2. Determine release rate of H2S (QH2S) from the following:

QH2S = (QAOF)(xH2S)

Where xH2S = mole fraction of H2S in gas stream

QAOF = Absolute Open Flowrate of gas from the well, MMscfd

QH2S = maximum release rate of H2S, MMscfd

3. Use the constants in Table A6 to calculate RER100 ppm, RER30 ppm and RER½ LFL from the following

RER100 ppm = e(QH2Sf);

RER30ppm = g(QH2Sh);

RER½ LFL = l(QAOF)m

The AOF or H2S concentration of a gas mixture must fall within the limits presented in Table A6. If an AOF or the H2S concentration is outside the limits, then LPD/TSU will calculate RER values specifically for the well of interest (users need to supply LPD/TSU with well name, AOF, gas composition (mole%), and flowing wellhead temperature).

Example of RER for Gas Well


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As an example, consider a high-pressure gas well in the South Ghawar Area, Hawiyah. Information available indicates that the anticipated Absolute Open Flow of the well is 100 MMscfd and the H2S concentration is expected to be 3 mole%.

The following steps are necessary to determine the RER:

1. Data Requirements

The AOF and the H2S concentration are within the ranges specified in Table A6. Table A6 indicates that the appropriate constants for this field are as follows:

Table A1 - RER Constants for South Ghawar Area, Hawiyah Field (from Table A6)

RER100 ppm RER30 ppm RER½ LFL

e f g h l m

245 0.79 700 0.77 11.7 0.54

2. Calculate maximum H2S release rate

The maximum H2S release rate is given by the following:

QH2S = (QAOF)(xH2S)

= (100 MMscfd)( 3 / 100 )

=3 MMscfd of H2S

3. Calculate RERs

RER100 ppm = 245[(3).79] = 583 m

RER30 ppm = 700[(3).77] = 1,631 m

RER½LFL = 11.7[(100).54] = 141 m

The RER for this example well are in Table A2.

Table A2 - RER for Example Well

Rupture Exposure Radii Distance, m

RER100 ppm 583

RER30 ppm 1,631

RER½LFL 141


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Procedure for Determining RER of Oil Wells

Gas is flashed during a large release of crude and is then dispersed downwind. As with gas wells, oil wells have three Rupture Exposure Radii (RER): a 100 ppm H2S RER (RER100 ppm), a 30 ppm H2S RER (RER30 ppm) and a ½ LFL RER (RER½LFL). Sweet oil wells only have a RER½ LFL. These radii are used in SAES-B-062 to determine spacing requirements and to assist in determining emergency response planning and notification. Follow these steps when determining the RER for an oil well:

1. Identify the oil field and reservoir for the well of interest (Contact Gen Supv'r., Oil or Gas Facilities & Projects Division, E&P FTD) and obtain the maximum oil flow rate, Gas-Oil Ratio (GOR) and mole fraction of hydrogen sulfide (H2S) in the oil. The correlations included in this appendix are based upon the expected upper and lower range of maximum flow rates, gas-oil ratios, and H2S content in the oil.

2. Use the following equation to calculate the rate of gas flashed from the crude released at the maximum flow rate:

Qgas = (Qoil)(GOR) /1,000

Where:

Qgas = Release rate of flashed gas, MMscfd

Qoil = Maximum oil release rate, Mbpd

GOR = Gas-Oil Ratio, scf/stb

3. Calculate the concentration of H2S in the flashed gas from the following equations:

[xH2S]gas = φ[xH2S]oil

where:

φ = a(GOR)b (Note: a, b are obtained from Table A7)

Determine release rate of H2S (QH2S)

QH2S = (Qgas) ([xH2S]gas) [MMscfd of H2S]

4. Calculate RER100 ppm

RER100 ppm = e(QH2S)f (Note: e, f are obtained from Table A7)

5. Calculate RER30 ppm

RER30 ppm = g(QH2S)h (Note: g, h obtained from Table A7).

6. Calculate RER½ LFL


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RER½ LFL = l(Qgas)m (Note: l, m obtained from Table A7)

If the AOF or H2S concentration do not fall within limits of Table A7, then LPD/TSU will calculate RER values specifically for the well of interest (users need to supply LPD/TSU with well name, maximum oil flow rate, oil composition (mole%), gas-oil ratio, and flowing wellhead temperature).

Example of Oil Well RER Determination

As an example, consider an oil well that is producing Arab-D in the Khurais field. Available information indicates the well will have a maximum flow rate of 30,000 bpd, the oil will have an H2S concentration of 2.9 mole %, and the GOR is 277. What are the RER values for this well?

1. Available information

The available information is summarized below. The maximum flow rate and the H2S concentration are within the limits specified in Table A7.

Maximum Flow Rate, Mbpd 30

GOR, scf/stb 277

Mole percent of H2S in Oil 2.9%

Constants for evaluating this well are summarized in Table A3.

Table A3 - RER Constants for Khurais Field (From Table A7)

H2S in Flashed Gas RER100 ppm RER30 ppm ½ LFL

a b e f g h l m

2.2 0 1,285 0.69 2,656 0.64 47.3 0.63

2. Calculate flashed gas release rate

The flow rate of released gas may be estimated by the following:

Qgas = (30 Mbpd) x (277 scf/stb) = 8.31 MMscfd

3. Calculate the H2S concentration in flashed gas

φ = a(GOR)b = (2.2) x (277)0 = 2.2

[xH2S]gas = φ[xH2S]oil = (2.2) x (2.9 %) = 6.4%

4. Calculate H2S release rate

QH2S = (8.31 MMscfd) x (.064) = 0.53 MMscfd H2S


Page 22 of 32

5. Calculate RERs

RER100 ppm = e(QH2S)f RER100 ppm = (1285)(0.53)0.69 = 829 m

RER30 ppm = g(QH2S)h RER30 ppm = (2656)(0.53)0.64 = 1,769 m

RER½LFL = l(Qgas)m RER½LFL = (47.3)(8.3)0.63 = 180 m

Table A4 - RER for Example Oil Well

Rupture Exposure Radii Distance, m

RER100 ppm 829

RER30 ppm 1,769

RER½LFL 180

Method of Using RER Results

Saudi Aramco uses the maximum of the 30 ppm RER (100 ppm RER with additional drilling precautions) or the ½ LFL RER to establish the minimum distance between wells and population or major facilities (note that spacing can never be less than the minimums stated in Table 2 of the Standard – see Section 5 for more details). The purpose for this RER method of spacing is to minimize the possibility of exposing people to either potentially lethal or flammable vapor clouds. Table A5 summarizes the effects of hydrogen sulfide exposure to people.

Once the RER100 ppm, RER30 ppm, and RER½LFL are known, draw the RERs as circles with the well at the center (see Figure A1). For sour gas wells, the ½ LFL RER will not dominate, but it should still be drawn on the map showing RERs.


Page 23 of 32

Figure A1 - RER Circles Superimposed Over Well Site Map


Page 24 of 32

Table A5 - Effects of Hydrogen Sulfide on People

H2S Concentration

(ppm)

Effect on People

0.10 ERPG-1*: The maximum airborne concentration below which it is believed that nearly all adult males could be exposed for up to 1 hour without experiencing other than mild transient adverse health effects or perceiving a clearly defined objectionable odor.

4 Moderate odor, easily detected. 10 Time Weighted Average (TWA) exposure limitation, beginning of eye irritation.

Setting for Warning low level H2S alarm for control rooms and other indoor areas protected by air intake sensors. Saudi Aramco work permit procedures require use of SCBA for work in areas with 10 ppm or greater H2S.

15 Short Term Exposure Limit (STEL) for 15 minutes.

20 Warning High H2S Level alarm setting at Saudi Aramco plants per SAES-J-505. 30 ERPG-2*: The maximum airborne concentration below which it is believed that

nearly all adult males could be exposed for up to 1 hour without experiencing or developing irreversible or other serious health effects or symptoms that could impair their abilities to take protective action.

50 Inhalation limit for 60 minutes, threshold limit of possible eye injury. Setting for Warning High-high Level H2S alarm at Saudi Aramco plants per SAES-J-505.

70 – 150 Headaches, dizziness, sore throat and increasing stress.

100 ERPG-3*: The maximum airborne concentration below which it is believed that nearly all adult males could be exposed for up to 1 hour without experiencing or developing life-threatening health effects.

150 Loss of sense of smell.

150 – 300 Severe irritation of eyes and lungs.

300 Immediately Dangerous to Life and Health Concentration: The maximum airborne concentration to which a healthy male worker can be exposed for as long as 30 min and still be able to escape without loss of life or irreversible organ system damage.

500 Loss of sense of reasoning and balance, loss of consciousness and possible death in 30 – 60 minutes.

1,000 Immediate loss of consciousness and death within a few minutes.

* Emergency Response Planning Guideline (ERPG), American Industrial Hygiene Association.


Page 25 of 32

Table A6 – Gas Field Constants for RER Calculations

Properties Constants H2S

(mole%) AOF or Qgas (MMSCFD) 100 ppm 30 ppm ½ LFL

Field min max min max e f g h l m

Abqaiq Cap Gas 1.0 5.0 50 150 268 0.73 729 0.73 14.8 0.49

Berri 20 20 50 120 789 0.63 1894 0.64 11.7 0.49

North Ghawar (Ain Dar and Shedgum) 0.72 6.0 50 150 273 0.75 689 0.81 14.0 0.48

South Ghawar (Haradh) 0.50 2.0 50 125 242 0.71 654 0.67 14.6 0.49

South Ghawar (Hawiyah) 0.5 4.5 50 150 245 0.79 700 0.77 11.7 0.54

Qatif 7.23 11.2 50 120 376 0.74 1032 0.72 11.1 0.50

Uthmaniyah 2.28 9.27 50 175 295 0.80 855 0.76 16.1 0.46

Equations for Oil and Gas Wells: RER100 ppm = e(QH2S)f RER30 ppm = g(QH2S)h RER½LFL = l(QAOF)m

Equations for Oil Wells Only: [xH2S]gas = φ[xH2S]oil where φ = a(GOR)b

Note: All RER distances are in meters. QH2S = release rate of H2S, MMSCFD. Qgas = release rate

of gas, MMSCFD


Page 26 of 32

Table A7 – Oil Fields Constants for RER Calculations

Properties Constants

H2S (mole%) in Oil Qoil (MBD) Flash 100 ppm 30 ppm ½ LFL

Field min max min max a b e f g h l m

Abqaiq 0.93 3.19 2.9 85 11.7 -0.29 815 0.58 1,895 0.58 49.4 0.59

Abu Hadriyah 0.21 2.23 1.9 88 2.2 0 1,024 0.57 2,249 0.55 63.8 0.57

Abu Jiffan 2.58 3.61 10 50 2.5 0 1,182 0.56 2,470 0.55 51.2 0.58

Ain Dar 0.25 2.7 6.9 37 1.7 0 897 0.76 2,251 0.84 45.5 0.42

Berri 1.06 8.92 15 143 33.5 -0.48 1,152 0.53 2,474 0.52 59.1 0.59

Dammam 1.04 2.18 8 52 2.8 0 432 0.48 725 0.49 24.1 0.47

Fadhili 4.13 11.1 5 31 1.5 0 878 0.77 1,949 0.71 51.7 0.54

Fazran 0.66 2.15 4.5 27 1.8 0 273 0.25 911 0.37 38.4 0.29

Haradh 0.02 0.79 5 32 2 0 2,741 0.77 3,825 0.37 50.4 0.52

Harmaliyah 1.69 5.3 6 32 1.6 0 856 0.61 1,980 0.59 45.3 0.44

Hawiyah 0.21 1.05 5 30 2 0 1,173 0.73 2,617 0.71 48.8 0.56

Khurais 0.58 2.94 9 36 2.2 0 1,285 0.69 2,656 0.64 47.3 0.63

Khursaniyah 1.96 4.77 7 43 2 0 1,079 0.59 2,346 0.58 47.9 0.53

Mazalij 1.9 5.47 6.3 37.8 2.2 0 1,232 0.71 2,565 0.67 50.6 0.65

Qatif 3.72 11.95 4 90 1.9 0 1,708 0.34 3,488 0.32 64.6 0.55

Shedgum 0.75 1.57 9 46 1.8 0 630 0.51 1,511 0.49 50.0 0.38

Uthmaniyah 0.23 1.55 9 29 1.8 0 1,438 0.83 3,279 0.83 36.5 0.70


Page 27 of 32

Table A8 – Oil Field Data from Exploration and Producing Components (mole %)

Well Name Reservoir Range N2 CO2 H2S C1 C2 C3 i-C4 n-C4 i-C5 n-C5 C6 C7+ GOR Abqaiq Arab-D Min. 0.3 4.9 0.9 27.4 10.7 4.4 1.6 3.7 2.6 1.8 4.2 37.4 860 Abqaiq Arab-D Wt. Avg. 0.1 4.6 1.8 29.6 10.3 6.6 0.6 4.3 1.0 3.0 3.1 35.1 860 Abqaiq Arab-C Max. 0.6 5.1 3.2 6.1 4.7 7.4 1.2 5.1 2.1 3.5 4.6 56.6 135 Abu Hadriyah Arab-A&B Min. 0.2 1.0 0.2 3.5 2.9 6.7 1.4 5.4 2.2 3.9 4.3 68.3 57 Abu Hadriyah Wt. Avg. 0.4 1.2 1.4 14.5 8.1 8.1 1.1 4.9 1.8 3.2 3.4 52.0 260 Abu Hadriyah Arab-C Max. 0.3 1.3 2.2 17.2 8.4 7.8 1.1 4.6 1.6 3.1 2.8 49.6 57 Abu Jiffan Arab-D Min. 0.2 1.7 2.6 9.6 9.6 9.3 1.2 4.9 1.7 3.0 3.9 52.4 253 Abu Jiffan Arab-D Wt. Avg. 0.2 1.9 3.1 9.2 8.9 8.8 1.2 4.7 1.7 3.1 4.4 52.7 253 Abu Jiffan Arab-D Max. 0.3 2.1 3.6 8.9 8.3 8.3 1.2 4.6 1.8 3.1 5.0 53.0 253 Ain Dar L. Fadhili Min. 0.1 3.9 0.3 34.3 13.8 8.5 1.0 4.0 1.1 2.1 1.6 29.3 730 Ain Dar Arab-D Wt. Avg. 0.1 5.9 1.7 25.1 10.4 7.7 1.0 3.8 1.2 2.2 3.0 37.8 550 Ain Dar Arab-D Max. 0.2 6.3 2.7 24.0 10.2 7.0 0.9 3.5 1.2 2.1 3.2 38.7 550 Berri Arab-B Min. 0.1 1.2 1.1 4.3 6.7 9.7 1.7 6.1 2.3 3.6 3.5 59.8 139 Berri Wt. Avg. 0.1 1.5 2.1 4.6 6.4 9.2 1.5 5.7 2.2 3.6 3.7 59.3 145 Berri Hanifa Max. 0.1 6.6 8.9 24.9 10.2 7.2 0.9 3.5 1.2 2.1 2.8 31.6 659 Dammam Arab-D Min. 0.2 2.8 1.0 21.9 2.0 1.5 0.3 1.3 0.4 0.9 4.7 63.1 353 Dammam Wt. Avg. 1.4 4.8 1.7 22.6 2.1 1.6 0.4 1.4 0.8 1.3 3.6 58.4 360 Dammam Arab-D Max. 1.5 5.5 2.2 22.4 1.6 1.1 0.2 0.8 0.4 0.9 3.4 60.0 353 Fadhili Arab-D Min. 0.0 2.9 4.1 33.4 11.1 6.8 0.5 3.9 0.8 2.5 3.2 30.7 955 Fadhili Wt. Avg. 0.1 2.3 5.5 31.8 12.8 8.3 0.9 3.8 1.0 2.0 1.4 30.3 962 Fadhili Arab-D Max. 0.1 9.8 11.1 25.8 9.3 7.1 0.9 3.5 1.2 2.0 1.8 27.4 955 Fazran L. Fadhili Min. 0.3 3.8 0.6 21.0 11.3 9.3 1.2 5.2 1.8 3.4 3.7 38.5 1100 Fazran Wt. Avg. 0.2 4.5 1.5 21.5 11.3 8.5 1.0 4.1 1.3 2.5 4.0 39.5 565 Fazran L. Fadhili Max. 0.1 2.1 2.2 34.0 11.7 6.8 0.8 3.7 1.3 2.2 2.1 33.0 1100 Haradh Arab-D Min. 0.3 1.4 0.0 19.5 10.5 10.0 1.2 5.1 1.6 2.8 2.8 44.7 470 Haradh Arab-D Wt. Avg. 0.2 3.8 0.4 22.2 9.5 8.5 1.1 4.5 1.6 2.8 3.9 41.4 470 Haradh Arab-D Max. 0.2 4.8 0.8 27.4 10.7 8.2 1.0 3.9 1.3 2.3 2.0 37.6 470 Harmaliyah Arab-D Min. 0.1 4.8 1.7 25.5 11.8 8.3 0.9 3.8 1.2 2.3 3.1 36.6 772 Harmaliyah Arab-D Wt. Avg. 0.1 5.1 4.1 27.7 11.4 7.8 0.9 3.7 1.3 2.4 3.0 32.7 772 Harmaliyah Arab-D Max. 0.1 5.3 5.3 24.9 10.6 7.6 0.9 3.8 1.2 2.3 3.2 34.8 772 Hawiyah Arab-D Min. 2.1 4.8 0.2 29.4 6.9 5.8 0.8 3.5 1.2 2.2 3.0 40.2 485 Hawiyah Arab-D Wt. Avg. 1.0 4.8 0.8 22.8 9.1 7.9 1.0 4.1 1.4 2.6 3.5 40.9 485 Hawiyah Arab-D Max. 0.4 4.1 1.1 15.9 8.3 7.6 1.0 4.3 1.7 3.4 6.0 46.1 485 Khurais Arab-D Min. 0.3 1.4 0.0 13.8 9.2 8.9 1.3 4.8 1.7 3.1 4.0 51.4 277 Khurais Arab-D Wt. Avg. 0.5 1.9 0.6 13.7 9.3 9.2 1.2 4.9 1.7 3.0 3.8 50.1 277 Khurais Arab-D Max. 0.8 4.5 2.9 12.8 6.1 8.9 1.4 4.9 1.9 3.0 3.9 48.7 277


Page 28 of 32

Table A8 – Oil Field Data from Exploration and Producing (Cont'd) Components (mole %)

Well Name Reservoir Range N2 CO2 H2S C1 C2 C3 i-C4 n-C4 i-C5 n-C5 C6 C7+ GOR Khursaniyah Arab-D Min. 0.1 2.5 2.0 19.4 9.8 8.6 1.1 4.5 1.7 3.1 3.2 44.0 350 Khursaniyah Wt. Avg. 0.2 3.1 2.4 21.5 9.8 8.5 1.1 4.2 1.5 2.6 2.8 42.3 380 Khursaniyah Arab-B Max. 0.1 4.7 4.8 15.8 7.2 6.9 1.0 3.8 1.5 2.7 2.9 48.7 350 Mazalij Arab-D Min. 0.1 3.4 1.9 28.7 5.8 6.4 1.0 3.7 1.4 2.2 3.2 42.1 398 Mazalij Arab-D Wt. Avg. 0.3 2.6 3.2 19.2 8.0 7.5 1.1 4.3 1.7 2.7 4.0 45.4 398 Mazalij Arab-D Max. 0.3 1.6 5.5 5.3 8.7 8.3 1.2 5.0 2.1 3.4 5.6 53.0 398 Qatif Fadhili Min. 0.2 3.5 3.7 38.2 12.3 7.4 0.9 3.6 1.2 2.2 3.0 23.8 1266 Qatif Wt. Avg. 0.9 6.6 7.9 14.4 7.0 7.2 1.0 4.1 1.6 2.7 3.8 43.0 330 Qatif Arab-D Max. 0.3 6.7 11.9 20.8 9.0 7.1 1.0 3.6 1.4 2.2 3.6 32.5 870 Shedgum Arab-D Min. 0.3 5.4 0.8 25.0 10.0 7.7 1.0 3.9 1.3 2.4 3.3 38.9 540 Shedgum Wt. Avg. 0.2 5.3 1.1 24.4 9.9 7.8 1.0 4.0 1.4 2.4 3.2 36.2 540 Shedgum Arab-D Max. 0.2 5.4 1.6 24.3 9.8 7.6 1.0 3.9 1.3 2.4 3.3 39.3 540 Uthmaniyah Arab-D Min. 0.1 3.8 0.2 26.1 9.7 7.7 0.9 4.2 1.6 3.0 3.4 39.4 515 Uthmaniyah Arab-D Wt. Avg. 0.2 4.5 0.8 24.6 10.0 8.1 1.0 4.1 1.4 2.5 3.3 39.3 515 Uthmaniyah Arab-D Max. 0.1 5.2 1.6 23.9 9.2 7.7 1.1 4.4 1.5 2.7 4.1 38.7 515


Page 29 of 32

Table A9 – Gas Field Data from Exploration and Producing

Mol Wt. Component (mole %)

Well Name Reservoir Range N2 CO2 H2S C1 C2 C3 i-C4 nC4 iC5 nC5 C6 C7 C8 C9 C10+

North Ghawar (Ain Dar and Shedgum)

ANDR-277 Khuff-B 23.1 Min. 14.7 3.8 0.7 70.4 4.9 1.8 0.4 0.6 0.2 0.2 0.2 0.3 0.4 0.3 1.1

SDGM-226 Khuff-C 23.7 Med. 11.8 3.7 3.6 69.4 5.1 2.0 0.5 0.8 0.3 0.3 0.4 0.4 0.4 0.3 1.1

SDGM-212 Khuff-C 24.6 Max. 11.5 3.9 6.0 66.6 5.0 2.1 0.5 0.8 0.4 0.3 0.5 0.6 0.6 0.4 1.0

Central Ghawar Area (Uthmaniyah)

UTMN-622 Khuff-B 25.5 Min. 10.5 1.7 2.3 68.4 6.7 3.0 0.6 1.2 0.5 0.5 0.7 0.8 0.8 0.6 1.8

UTMN-616 Khuff-C 24.9 Med. 11.5 3.3 5.2 66.0 5.8 2.5 0.5 1.0 0.4 0.4 0.6 0.6 0.6 0.5 1.3

UTMN-2000 Khuff-C 26.4 Max. 10.2 3.1 9.3 62.0 6.2 2.7 0.5 1.0 0.3 0.3 0.6 0.9 0.8 0.6 1.5

South Ghawar Area (Hawiyah)

Khuff-C 27 Avg. 9.6 2.2 2.5 68 6.7 2.9 0.5 1.1 0.4 0.4 0.7 1.0 1.0 0.7 2.2

Khuff-C 26.6 Min. 9.8 2.3 0.5 69.4 6.8 3.0 0.5 1.1 0.4 0.4 0.7 1.0 1.0 0.7 2.2

Khuff-C 27.1 Med. 9.6 2.2 3.0 67.7 6.6 2.9 0.5 1.0 0.4 0.4 0.7 1.0 1.0 0.7 2.2

Khuff-C 27.2 Max. 9.4 2.2 4.5 66.6 6.5 2.8 0.5 1.1 0.4 0.4 0.7 1.0 1.0 0.7 2.1

South Ghawar Area (Haradh)

Khuff-C 25 Avg. 9.0 1.5 0.6 71.1 7.4 3.3 0.6 1.4 0.5 0.5 0.6 0.8 0.8 0.6 1.2

Khuff-C 25 Min. 9.0 1.5 0.5 71.2 7.4 3.3 0.6 1.4 0.5 0.5 0.6 0.8 0.8 0.6 1.2

Khuff-C 25 Med. 9 1.5 1.0 70.9 7.4 3.3 0.6 1.4 0.5 0.5 0.6 0.8 0.8 0.6 1.2

Khuff-C 25 Max. 9 1.5 2.0 70.1 7.3 3.3 0.6 1.4 0.5 0.5 0.6 0.8 0.8 0.6 1.2

Qatif

QTIF-51 Khuff-A 20.9 Min. 6.5 9.1 7.2 75.8 1.2 0.2 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

QTIF-152 Khuff-B 24.7 Max. 42.2 2.0 11.2 42.2 0.9 0.2 0.0 0.2 0.0 0.0 0.1 0.8 0.0 0.0 0.0

Abqaiq Abq Cap

Gas Abqaiq 0.7 8.6 2.3 64.5 14.1 6.1 2.2 0.9 0.3 0.1 0.1 0.1 0.0 0.0 0.0

Berri

Berri Khuff Berri 23.2 10.0 8.2 19.8 61.4 0.3 0.2 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0


Page 30 of 32

The table below shows examples of the maximum RERs for some fields. The RER values shown are based on the calculation information above and the maximum open flow and highest sour gas concentration typically expected the fields listed. The values below are for example only.

Gas Fields

RER100ppm

(meters) RER30ppm

(meters) RER½LFL

(meters)

Abqaiq Gas Cap 1170 3170 170

North Ghawar (Ain Dar and Shedgum) 1420 4090 160

South Ghawar (Haradh) 460 1210 160

South Ghawar (Hawiyah) 1110 3050 180

Uthmaniyah 2740 7110 170

Oil Fields

RER100ppm

(meters) RER30ppm

(meters) RER½LFL

(meters)

Abqaiq 1780 4140 620

Abu Jiffan 1270 2660 220

Ain Dar 850 2130 160

Dammam 460 770 100

Fazran 280 960 100

Haradh 910 2250 210

Harmaliyah 1340 3060 190

Hawiyah 490 1130 220

Khurais 950 2010 200

Khursaniyah 1340 2890 200

Mazalij 1880 3820 300

Shedgum 530 1270 170

Uthmaniyah 700 1590 240


Page 31 of 32

Gas Field RER Work Sheet

Information Value

Well Name

Field

Absolute Open Flow, Qgas MMSCFD

Mole % of H2S in Gas, [xH2S]gas

DATA from Table A6

Minimum AOF, MMSCFD, per Table A6

Maximum AOF, MMSCFD, per Table A6 Is AOF for well greater than minimum

and less than maximum AOF for field? ( ) Yes (continue) ( ) No (stop: Contact LPD/TSU)

Minimum mole percent (%) of H2S per Table A6

Maximum mole percent (%) of H2S per Table A6 Is H2S mole % for well greater than minimum

and less than maximum flow rate for field? ( ) Yes (continue) ( ) No (stop: Contact LPD/TSU)

Constants from Table A6

e

f

g

h

l

m

Calculate H2S Release Rate

QH2S = (QAOF)(xH2S) [MMscfd of H2S]

Calculate RERs RER100 ppm = e(QH2S)f : RER30 ppm = g(QH2S)h

RER½ LFL = l(QAOF)m

Results

RER100 ppm

RER30 ppm

RER½ LFL


Page 32 of 32

Oil Field RER Work Sheet

Information Value

Well Name

Field

Maximum Flow Rate, Qoil Mbpd

GOR, scf/stb

Mole % of H2S in Oil, [xH2S]oil

DATA from Table A7

Minimum Flow Rate, Mbpd, per Table A7 or Qoil

Maximum Flow Rate, Mbpd, per Table A7 or Qoil Is flow rate for well greater than minimum


Minimum mole percent (%) of H2S per Table A7

Maximum mole percent (%) of H2S per Table A7 Is H2S mole % for well greater than minimum


Constants from Table A7 a b e f g h l m Calculate flashed gas release rate

Qgas = (Qoil)(GOR)/1,000 [MMscfd]

Calculate the H2S concentration in flashed gas

φ = a(GOR)b

[xH2S]gas = φ [xH2S]oil

QH2S = (([xH2S]gas)/100)Qgas [MMscfd of H2S]

Calculate RERs RER100 ppm = e(QH2S)f RER30 ppm = g(QH2S)h

RER½ LFL = l(Qgas)m

Results

RER100 ppm

RER30 ppm

RER½ LFL

Saudi Aramco 7180 (5/89)

SAUDI ARABIAN OIL COMPANY (Saudi Aramco)GENERAL INSTRUCTION MANUAL

ISSUING ORG.

SUBJECT:

G.I. NUMBER

ISSUE DATE REPLACES

APPROVAL PAGE NUMBER

OF

* CHANGE ** ADDITION NEW INSTRUCTION COMPLETE REVISION

DRILLING & WORKOVER

RIG SITE FLARE GUN AND COMMUNICATION EQUIPMENT

1852.001

03/10/1999 NEW

FAM 1 2

X 2

Approved

CONTENT:This General Instruction contains policy for equipping a rig with a Flare Gun and standard CommunicationEquipment.

1. OBJECTIVE2. BACKGROUND3. FLARE GUN4. COMMUNICATION EQUIPMENT

1.0 OBJECTIVE

The purpose of this policy is to ensure that every rig is fully equipped with a Flare Gun andCommunication Equipment in case of an uncontrolled surface well flow (blowout) or otheremergency.

2.0 BACKGROUND

2.1 During Drilling and Workover operations, with a rig on the well, an uncontrolled surface flow(blowout) may occur, requiring immediate ignition of the well effluent to protect human life andcompany assets. In such a case, a Flare Gun is fired to ignite the effluent before spreading.

2.2 During the blowout emergency, it becomes imperative to have reliable means of communicationat the rig site and with headquarters, especially when all power is turned off at the well site toavoid uncontrolled ignition. The use of mobile car radios and portable communication devices(such as Walkie-Talkies) become essential in effective transmittal of instructions and expedientcontrol of the well.

3.0 FLARE GUN

Drilling & Workover will have a Flare Gun on each rig site, as well as a box of at least 24 cartridgeswith long shelf life. The Flare Gun and cartridges will be locked up in a clearly marked wooden box inthe Foreman's office, and the location of the key will be known only to the Foreman and the rigContract Supervisor. The Foreman and Contract Supervisor should be proficient in operation of theFlare Gun.



ISSUING ORG.

SUBJECT:

G.I. NUMBER

ISSUE DATE REPLACES


OF


DRILLING & WORKOVER

RIG SITE FLARE GUN AND COMMUNICATION EQUIPMENT

1852.001

03/10/1999 NEW

FAM 2 2

X 2

Approved

4.0 COMMUNICATION EQUIPMENT

4.1 Mobile Radio

Drilling & Workover and Computer & Communications Services Department will worktogether to forecast, acquire and install a single side-band mobile radio in every rig Foreman'svehicle to provide the capability to communicate with the Superintendent in case of anemergency. The radio will only be used when at a safe distance from the well site in case ofunignited hydrocarbon accumulation since the vehicle and radio are both sources of ignition.

4.2 Walkie-Talkie

Drilling & Workover and Computer & Communications Services Department will worktogether to forecast and acquire at least two portable communication devices, such as Walkie-Talkies. The devices are needed on every rig site during an emergency or critical operation. Theportable communication devices will be locked up in a clearly marked wooden box in theForeman’s office, and the location of the key will be known only to the Foreman and the RigContract Supervisor. The Foreman is responsible for the proper operation and charging of thedevices. The Walkie-Talkies must be rated for use in Class I, Div. I electrically classified areas(i.e. explosion proof).

Approved by:

F. A. Al-MoosaGeneral Manager, Drilling and Workover.

N. H. Al-RabehManager, Computer and Communications Services Department.



ISSUING ORG.

SUBJECT:

G.I. NUMBER

ISSUE DATE REPLACES


OF


DRILLING & WORKOVER

ISOLATION BARRIERS FOR WELLS DURING DRILLING& WORKOVER OPERATIONS (WITH AND WITHOUT RIG)

1853.001

02/14/1999 NEW

MYR 1 5

X 5

Approved

CONTENT:This document contains instructions for providing adequate isolation barriers (or shut-offs) when removingsurface control equipment while drilling or working over wells. These instructions are also applicable for wellrepair work, performed by the Drilling & Workover organization without a rig on location.

1. OBJECTIVE2. BACKGROUND3. MINIMUM REQUIREMENT4. TYPES OF ISOLATION BARRIERS5. RELIABILITY OF ISOLATION BARRIER6. WAIVER

1.0 OBJECTIVE:

The purpose of this GI is to ensure safe operations during drilling and well repair work by strictcompliance to the guidelines. Short cuts to compromise these guidelines will not be permitted unless awaiver is obtained from the Vice President of Petroleum Engineering & Development or designatedrepresentatives.

2.0 BACKGROUND:

When drilling or working over wells, with or without a rig, situations arise where surface equipmentsuch as Blow Out Preventers (BOPs), wellheads, master valves and trees have to be removed forvarious reasons. In these situations, surface well control is temporarily removed and is substitutedwith downhole isolation barriers so that the reservoir pressure is isolated and work can continuearound the wellhead safely. More than one isolation barrier or shut-off is normally required in certainwells in case of unexpected failure of the primary barrier. Adequate back-up barriers reduce thechances of uncontrolled surface flow (blowout) and costly repair work.

3.0 MINIMUM REQUIREMENT:

The following guidelines will apply at all times unless a waiver has been obtained from Management(as described in paragraph 6.2). The mandatory number of barriers or shut-offs in each case is theminimum; any additional barriers are optional, dictated by the well condition and downholecompletion equipment.

3.1 Oil Wells (GOR less than 850 scf/bbl)

2 shut-offs, one of which is mechanical.



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3.2 Oil Wells (GOR more than 850 scf/bbl)

3 shut-offs, two of which are mechanical.

Note: For tubing and packer completed wells, the 3 shut-off guideline is applicable to thetubing only. A minimum of 2 shut-offs is required for the tubing-casing annulus(tubing hanger and packer seals). If one of the two shut-offs is deemed to beineffective or questionable, then the annulus will have to be filled with overbalancedkill fluid to act as a reliable shut-off.

3.3 Water Injection Wells

- If positive WH pressure, 2 shut-offs are required, one of which is mechanical.

- If no WH pressure, 1 shut-off is required.

Note: It is acceptable to nipple up or nipple down the BOPs on top of the injection tree byonly closing the 10" ball valve. No additional shut-offs are required as long as the treewas never removed or the tree has been pressure tested after nippling up.

3.4 Gas Wells

3 shut-offs, two of which are mechanical.

Note: For tubing and packer completed wells, the 3 shut-off guideline is applicable to thetubing only. A minimum of 2 shut-offs is required for the tubing-casing annulus(tubing hanger and packer seals). If one of the two shut-offs is deemed to beineffective or questionable, then the annulus will have to be filled with overbalancedkill fluid to act as a reliable shut-off.

3.5 Water Supply Wells (with or without submersible pump)

- If well flows to surface, 1 shut-off is required.

- If well does not flow to surface, no shut-off is required.

4.0 TYPES OF ISOLATION BARRIERS:

4.1 A number of acceptable isolation barriers or shut-off alternatives are available and can be usedunder different operating conditions. These barriers can be separated into two main groups:Mechanical and Non-Mechanical.



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4.2 The following are examples of Mechanical and Non-Mechanical isolation barriers. The type ofbarrier to utilize will depend on the well condition and downhole completion equipment. Thesebarriers include, but are not limited to:

Mechanical:- Drillable or Retrievable Bridge Plug- Retrievable Tubing Plug- Back Pressure Valve- Valve Back-Seat- Surface Valve- Subsurface Safety Valve (SSSV)- Unperforated Casing

Non-Mechanical:- Kill Fluid- Cement

5.0 RELIABILITY OF ISOLATION BARRIERS:

5.1 Equipment Testing

5.1.1 Vendor Testing: Prior to delivery of a new mechanical pressure isolation device, thevendor must conduct the required and appropriate hydrostatic pressure tests per SaudiAramco Materials System Specification (SAMSS) to insure that the device meets designspecifications.

5.1.2 Field-Testing: Whenever a mechanical isolation barrier is installed in a well, every effortshould be made to field test and insure the barrier is holding. Since plugs are designedto hold pressure from above, below or from both directions, the field test should bedesigned according to the plug functionality.

5.2 Kill Fluid

5.2.1 A kill fluid can be used as one of the isolation barriers as mentioned in section 4.2 above.In order for the kill fluid to be effective as an isolation barrier, two conditions must bemet:

a) The hydrostatic pressure of the kill fluid column must exceed the reservoirpressure.

b) The wellbore kill fluid must remain static at surface for a period of time ( as peritem 5.2.2 below) to insure the presence of a competent barrier.



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5.2.2 The following are the minimum mandatory observation times for a kill fluid to bedeclared static:

Oil Well (GOR less than 850 scf/bbl): 1 hourOil Well (GOR more than 850 scf/bbl): 2 hourGas Well 3 hoursWater Injector 1 hourWater Supply Well 30 minutes

6.0 WAIVER:

6.1 The above instructions will be mandatory when drilling or working over a well (with or withouta rig) by the Drilling & Workover organizations, unless prior management approval has beensecured. A written waiver to divert from the established guidelines must be obtained when anunusual well situation dictates the need for fewer barriers than stipulated. Obtaining a waiver toreduce the number of isolation barriers or shut-offs is highly discouraged and should only beconsidered when there are no other alternatives.

6.2 The waiver will be requested by submitting Waiver Request Form Waiver - 01 (see Appendix I)documenting the well situation, explaining why a waiver is necessary and explaining the impactof the waiver. Waiver signature approval level will be Vice President of Petroleum Engineering& Development or designated representaive.

Recommende by:

F. A. Al-MoosaGeneral Manager, Drilling and Workover

Approved by:

M. Y. RafieVice President, Petroleum Engineering & Development

WAIVER REQUEST FOR ISOLATION BARRIERDate Requested Waiver Request #

Saudi Aramco Form: Waiver 01(10/98)

Well Name & Number Plant # Facility Connected to

Include number, paragraph, and issue date of this affected GI

Waiver requested Y NAfter-the-Fact

Justification (Include discussion of impact assessment) Impact Assessment

Y N

R Financial Impact

OT

A Safety Impact

NI

GR

OR

EV Discuss under Justification

I Alternatives to waiving requirements

AW

Originating Organization (Originator's Name) (Signature) Date

Phone:Originator's Supervisor (Signature) Date

Phone

REMARKS

LA

VO

RP

PA

Vice President or Designated Representative Signature Date

Name

Appendix I GI 1853.001Page 5 of 5

SAUDI ARAMCO DRILLING & WORKOVER

ROOM 221A, BLDG 3193 DHAHRAN 31311, SAUDI ARABIA TEL. 862-8000, FAX. 862-8011

October 18, 1999

D&WO/GM-160 Clarification of GI 1853.001 Managers Drilling & Workover The new GI 1853.001 entitled “Isolation Barriers for Wells during Drilling & Workover Operations (with and without Rig)” was approved in November 1998 and distributed for implementation. The interpretation of the GI with respect to changing rams or installing casing rams has been questioned. The following clarifies the shut-off requirements for these operations as per the subject GI.

Section 3.0, Paragraphs 3.2 (Oil Wells with GOR more than 850 scf/bbl) and 3.4 (Gas Wells)

Three mandatory shut-offs are required; two of which should be mechanical.

Clarification: i) For BOP stack removal or tree removal, the mandatory shut-off requirements are

applicable.

ii) For changing rams or installing casing rams, the mandatory shut-offs do not apply. Two barriers are adequate; one of which should be mechanical. Shutting the blind rams with kill fluid in the hole will provide proper isolation since the 1) BOP preventers below the open ram cavity are effective and reliable (recently pressure tested), 2) time involved in changing rams is much less than removing the entire BOP stack or tree. When changing the lowermost set of rams, a down-hole mechanical shut-off (either cased hole or packer) with kill fluid is required.

Signed 10/18/99

__________________________________ F. A. Al-Moosa, General Manager Drilling & Workover dgn/ cc: Drilling Superintendents, Deep Drilling and Onshore Workover Dept. Drilling Superintendents, Dev. Drilling and Offshore Workover Dept. General Supervisors, Drilling and W/O Engrg. Dept. Originator Letterbook

Well Control Manual

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