Guidelines for Volumetric Stripping Rev.1 Feb.2004

Rev: 1 Prepared by TWH/5, date: 14.02.2004

Volumetric Stripping Guidelines

Trip Margin

Form. Pressure

Mud gradient

Low Volume Swabbing while POOH.


of 27 Rev: 1 C:\Documents and Settings\1\Мои документы\My Work Data\Drilling Electronic Books\Well Control Reference Documents\Guidelines for Volumetric Stripping Rev.1 Feb.2004.doc Prepared by TWH/5, date: 14.02.2004

Introduction:

A study of blowout statistics (1200 case histories), revealed that even though the drilling industry continually learns more about how to handle an unstable well, it seems that problems of influx detection, kick handling and well pressure control do not change much with time. Data indicates that most frequently blowouts occurred during activities of actual drilling (pressure prediction, drilling in a field we think we know), tripping (swabbing, losses due to surge pressures) and circulating (ECD ignored, losses). Secondly it was noticed that the blowout frequency rose when activity levels increased due to shortage of competent drilling personnel. Thus in most cases a blowout could have been prevented. Rarely has a blowout been caused by equipment failure. It is therefore just as vital as it ever has been to continue training & assessing drillingcrews in the principles of well control. Between 20-40% of all recorded blowouts are the results of kicks taken during roundtripping. Human errors are the main causes of these kicks and the contributing factors leading to this can be summarised as:

Misinterpretation of hole condition. Misinterpretation of mud condition. Pipe pulling speed. Incorrect interpretation of Triptank data (tapered string). Incorrect procedure applied.

The accepted policy in most areas was, to run the bit back as close and fast as possible to bottom as long as the flow is not excessive. Uncertainty arises over the decision as to what is and what isn’t an excessive flow. Secondly the most important, but often forgotten, factor is the position of the influx in relation to the drillstring. If the drillstring is run unexpectedly into the influx, a severe loss of hydrostatic head will occur. The result of this may be a further loss of (over)balance with the producing formation and a rapid increase in influx (second) volume and ultimately higher closed-in surface and casing shoe pressures. In view of the above it becomes obvious that the correct procedure should be to close in the well at the first indication of flow. If strictly adhered to, closed-in pressures will in all cases be at a minimum and will leave more options open for a decision on how to kill the well, particular with a “weak” casing shoe. Additionally, it cannot be stated often enough that preventing is always better than curing an event. Everything possible should be done to enable early detections of kicks. Crews should be continuously reminded and trained of the correct procedure when swabbing is induced and on the importance of the correct use of the Triptank whilst pulling-and running pipe out/in the hole. Throughout this document the “worst-case’ scenario is described, a Low Volume Swabbed Gas influx, since it will migrate. Nevertheless a fluid kick, Oil or Brine, in an over-pressured reservoir can also give a tremendous loss of Hydrostatic-Head when the swabbed influx is displaced behind the Bottom Hole Assembly (BHA) while running into it. It only simplifies the operational since it will not migrate as fast an Gas influx. This document is a summary of the PD-03 ‘Stripping Course’-hand-out and other published documents on this subject and should serve as a tool for supervisors at all levels, how to focus on procedural and equipment requirements. It also captures all shortfalls as observed during assessments recently held. Note:

• There are excellent Well Engineering software packages, such as WfW & IDM to calculate and simulate Swap & Surge pressures with respect to pipe pulling speed and minimum Trip Margins.

• This document only describes the effect of Low Volume Swabbing and how to proceed.



Table of Content:

Subject: Pages: Introduction 2 Table of content 3 1. Conditions which can lead to a Well Control event while tripping pipe 4 2. Example of the results when attempting to outrun a gas swab-kick 4 - 6 3. Preparing for a Volumetric Stripping operation. 7 4. Volumetric Stripping procedure 7 - 8 5. Attachments:

1. What to Check & Plan before POOH. 9 2. Guideline on how to POOH safely. 10 3. Volumetric control for gas migration with Bit off bottom. 11 - 14 4. Equipment requirements to perform a stripping operation. 15 - 20 5. Checklist for the combined Stripping & Volumetric operations 21 - 23 6. Volumetric Stripping sheet & Recording sheet. 24 - 25 7. Guidelines for conducting a Strip-drill 26 - 27



1. Conditions which can lead to a Well Control Event while tripping pipe. During any roundtrip in a well, by definition Swabbing (dragging mud and causing a negative pressure), Low Volume Swab kick, will occur when POOH and a pressure Surge will develop when RIH. Swabbing can lead to a Well Control Event while a pressure Surge can lead to losses which could also turn into a Well Control Event. The main elements which affect this phenomenon can be summarised as followed:

Poor mud conditions: - high viscosity (PV/YP) - High Gel strengths - High Fluid Loss ⇒ thick mudcake. - Use of LCM

Balled BHA, stabilisers, often in soft and reactive shale/clayish formations. Hole size – BHA size & geometry. Insufficient Trip-margin, i.e. overbalance, to compensate for any natural swab

pressure. Pulling speed, gel effect.

And remember that swabbing can still take place when the Bit/BHA is inside the casing, particular at high angle wells, casing shoe set at inclinations above 350, where a lot of oriented drilling, stationary drillstring, had to take place ⇒ poor hole cleaning. Other causes which can lead to a Well Control event while tripping can be categorised as followed:

Improper hole fill, actual less than calculated Misinterpretation of slug behaviour in a tapered drillstring Weighting material sag (on surface as well as subsurface) Filling the hole with a light mud weight (heavy rain experienced, etc)

2. Example of the results when attempting to outrun a gas swab-kick. The figures below, including those on the next 2 pages, are self explanatory and the conclusion can be drawn from here, that the attempt to run into a rising and expanding (gas) influx emphasises the risk attached to a kick with higher pressures. It distinct the advantages of an early close-in procedure.

Development of a Swab kick: Stage 1

Situation:• Penetrated the reservoir (gas)

and the 8 1/2” bit at 2800 m (TVD) had to be changed

• Mud gradient = 17.5 kPa/m• Form. gradient = 16.3 kPa/m• Gas gradient +/- 3 kPa/m⇒ Overbalance on reservoir at

bottom:= 3360 kPa

0

500

3500

2500

1000

2000

1500

3000

40.k10.k 20.k 30.k 50.k

2800 m

0

Overbalance, Trip margin

Dep

th, m

Pressure, kPa




Situation:• While POOH swabbing

occurred.• With the bit at 1700 m, a slight

flow was observed.• A gain of +/- 1.5 m3 was

measured from improper hole fill and flow (expansion).

• OH filled with gas-cut mud.⇒ Overbalance on reservoir at

bottom:= 2000 kPa

0

500

3500

2500

1000

2000

1500

3000

40.k10.k 20.k 30.k 50.k

2800 m

0

Loss of Overbalance, Trip margin

Dep

th, m

Pressure, kPa

POOH to 1700 m

Accumulated gas, Influx


Situation:• BHA run in hole while the well

was not flowing excessively (?)• Influx displaced behind BHA,

sharp increase in influx height and consequently a further reduction of overbalance.

• Gain at surface +/- 4.0 m3. • OH filled with gas-cut mud.⇒ Overbalance on reservoir at

bottom:= +/- 0 kPa

0

500

3500

2500

1000

2000

1500

3000

40.k10.k 20.k 30.k 50.k

2800 m

0

Zero Overbalance, Trip margin

Dep

th, m

Pressure, kPa

RIH to 2200 m

Increase in height of Influx




Situation:• Continue RIH while expansion

and accumulation of gas continued.

• Well flowing excessively (?)• Overbalanced lost and

consequently the well started to produce (2nd influx)

• Gain at surface +/- 10 m3. • OH filled with gas-cut mud.⇒ Overbalance on reservoir at

bottom:= - (?) kPa

0

500

3500

2500

1000

2000

1500

3000

40.k10.k 20.k 30.k 50.k0

Dep

th, m

2800 m

Pressure, kPa

RIH to 2400 m

Increase in Influx Volume

⇒ height

Underbalanced !!Producing (2nd Influx)


Situation:• Well closed due to excessively

(?) flow. • Total influx vol.=15 m3.• Closed in annulus pressure

5000 kPa• Bit still 400 (TVD) m of bottom.• OH heavily loaded with gas-cut

mud, 2nd Influx.⇒ Control lost⇒ To recover, difficult and risky

0

500

3500

2500

1000

2000

1500

3000

40.k10.k 20.k 30.k 50.k

2800 m

0

Dep

th, m

Pressure, kPa

2400 m

Results:• Annulus pressure>5000 kPa

• High Stripping forces, damage to equipment.

From the foregoing it can be seen that an alternative approach is desirable to return the Bit/BHA back to bottom whilst maintaining control of the well. Such an approach is described in the remaining of this document, the combined stripping and volumetric method.



3. Preparing for a Volumetric Stripping operation. When planning a Trip, for what ever reason, options should be considered on how to prevent an unexpected Well Control event. Attachment #1 & 2 could be used as a guide to prevent such an event from happening or how to proceed if swabbing did occur. If a Well Control event develops and gas migration takes place, it’s important to prevent any further escalation. Attachment #3 could be used as guides how to Volumetric control excess pressures due to gas migration while preparing for the Stripping operations. When planning for a possible Stripping operation, Attachment #4 could be used as a guide on what should be the considered requirements for equipment when conducting such operations. When preparing for a Stripping operation, Attachment #5 could be used on how to perform an overall check prior to commence the operation. Attachment #6 could be used as a guide how to collect and record all required data to ease operations. Attachment #7 could be used as a guide how to perform and train crews for an unplanned Stripping operation. 4. Volumetric Stripping procedure. Should a well kick whilst tripping, it is important that the decision taken is made with great care to minimise the exposure to a Well Control event. To this end, it is essential that rigs are suitable rigged-up to implement the Volumetric Control method and combine this method with Stripping operations. If a swab kick is detected at an early stage, wellhead pressures will remain manageable and as such stripping should be possible trough any Bag-type preventer. The use of a Bag-type preventer allows Tooljoints to pass through the packing element due to its design. To minimise wear, the pipe should be lubricated and closing pressure applied to the preventer should be kept to a minimum whilst avoiding leakage. Additionally, Drillpipe/casing protectors should be removed and the Drillpipe (and Tooljoints) surface to be smoothened from tong & slip marks. Regardless of the method used to strip pipe into the hole, to enable effective pressure control, it is important to measure all the fluid movements on surface and from the wellbore accurately. Influxes that have entered the well could be gas and migration may take place. If there is no migration it could mean that a fluid, oil or formation water, is swabbed but it also could mean that conditions are as such that gas is still in liquid phase and can brake-out higher up the hole. As long as we face a liquid phase, as pipe is stripped in, the volume of mud released from the wellbore should equal the closed-end displacement and the surface pressure should remain the same. Note: With an influx at liquid phase, gas, oil or formation water, we still apply the same principles, i.e.

Pchoke=Pann+Ps+Pw, to maintain a controlled bottom hole pressure. If a gas influx migrates, the surface pressure will increase further after the initial build-up is completed. In this case it is necessary to bleed off additional fluid to let the gas expand and thus reduce the chance of formation break-down. This is achieved by maintaining a constant choke pressure whilst the pipe is stripped in and thus combining the Stripping and static Volumetric Control method. When the Bottom Hole Assembly (BHA) enters the influx, a dramatic loss of Hydrostatic Head (HH) will take place, difference in gradient of mud with respect to the gradient of the influx. This loss of HH should be anticipated and additional back pressure should be added. To simplify and allow easy operations the following assumptions have been made, all of which gives “worst case” scenario: An influx will be treated as a gas influx, i.e. adding extra back-pressure (Pw) allowing migration and

expansion.



The influx remains as a continuous slug, bubble, occupying the entire annular cross section. Loss of HH (Ps) will be added at the very start of the stripping operations and it’s assumed that the

influx will be opposite the smallest annular section, i.e. opposite the Dc’s in the BHA. Procedure: 1. If Swabbing takes place, perform a flow check and use the flowchart in attachment #2 as a guide on

how to proceed. 2. If a swab kick is detected, close-in the well by installing a RHKC on the string, close same and use the

hard shut-in method to close-in the annulus. Record the influx volume and monitor, record, pressures at 2 minutes intervals to determine the stabilised pressures, Pann and Pdp.

3. Continue recording pressures at 5 minute intervals to see if migration takes place. 4. Complete the Volumetric Stripping sheet as per attachment #6. While preparing for a Stripping

operation, use the Volumetric Control method (see Attachment #3) to control the well if gas migration takes place.

5. If a Stripping operation has to be conducted, reduce Bag-type preventer closing pressure, use attachment #4 as a guide, and open Surge-bottle.

6. Have a safety meeting, brief crews and complete all checks, use attachment #5 as a guide, to start Stripping operations.

7. Install Gray-valve on top RHKC. Open RHKC slowly to check that Gray-valve is sealing. If a non-ported float valve is installed in the BHA, most likely no pressures will be seen below the RHKC. Consider to install a circulating device to confirm the string is not plugged and record pressures before commencing to strip down. From this pressure reading it’s even possible to optain an indication if the Influx is below or above the bit.

8. Install a stand of Drillpipe, smoothen Drillpipe tong and slip-marks and remove protectors when installed. Lubricate Tooljoints.

9. Ensure Choke-line & Manifold are lined up to discharge bled-off mud into the Trip-tank. 10. Ensure Trip-tank is +/- 30% filled and starting volume recorded. 11. Allow Pchoke to rise till Pchoke1=Pann + Ps + Pw, whilst stripping the first stand.

Pann = Initial closed-in annulus pressure before second build-up. Ps = Allowance for the loss of Hydrostatic Head (HH) when BHA is run into influx. Pw = Working pressure to allow expansion. See attachment #3 for calculations on Ps and Pw (∆V)

12. Fill each stand stripped with mud from the active mud-system. 13. Avoid excessive surge pressures on the well as well on the Bag-type closing system when passing

Tooljoints through the packing element. 14. Whilst stripping pipe, the volume increase due to Closed-End (CE) displacement of Drillpipe and

expansion volume of influx are purged into the Trip-tank. After Stripping the entire stand the CE volume will be bled into the Strip-tank. Thus ensuring that any increase in the Trip-tank is due to expansion of the gas which reflects the loss of HH in the well.

15. Maintain Pchoke1 constant whist stripping pipe until the actual volume increase (⇒ excluding CE volume) in the Trip-tank equals the equivalent working volume, ∆V, converted from Pw.

16. While continuing stripping the next stand, allow Pchoke to rise to Pchoke2 = Pchoke1+Pw . 17. Continue stripping pipes and repeat steps 12-16 as often as necessary to allow migration and

Volumetric control until the Bit is back on bottom. 18. Back on bottom, prior to conducting the “Drillers Method” killing operations, close Ram-type preventer

to have full integrity on BOP equipment when the influx reaches surface. Line up mud discharge from Choke-manifold through Separator.

19. After the well is back on primary control and before opening the Bag-type preventer, be aware that trapped pressures could still be in the BOP-stack and below the Gray-valve.

20. Ensure that equipment is reset to normal operations since you still have to attempt to POOH again!



Attachment #1: What to Check & Plan when planning to POOH

Why?

Drilling Stopped

Case of Open Hole (ext ended exposure time)

E-line Logging (extended exposure time & interference of equipment.)

A Bit change (min. exposure time)

Reservoir exposed?

Reservoir exposed?

Reservoir exposed?

Continue with Attachment #2

No

Continue with Attachment #2

No

Check & Plan Top Hole Drilling without BOP protection?

⇒ Shallow Gas, pull wet and consider to pump out of hole? Soft shale’s/clays drilled?

⇒ Increases chance of a balled-up/packed assembly! ⇒ Increased chance for High Volume Swabbing!

Mud conditions as per program? ⇒ Gels to a minimum to minimise Low Volume Swabbing, also during E/line logging (Check tool sizes and logging speeds wrt hole size)? ⇒ Gels to a minimum to avoid losses when RIH, especially when POOH for Casing? ⇒ Drilled with a low Fluid Loss (FL) minimised Mudcake ⇒ To prevent weighting material settling (Barite-sag)? ⇒ Volume, height of planned viscous pill not excessive?

Hole conditions and clean? ⇒ Correct mudweight not masked by cuttings? ⇒ Cutting-bed on high deviated wells? ⇒ Planned to pump out of hole when O/P’s are experienced?

Hole size in relation BHA size, number of stabilisers in BHA, minimum annular clearance? ⇒ Consider to pump out of hole to +/- 100 m above exposed reservoir to minimise Low Volume Swabbing trough reservoir?

Tapered drillstring used? ⇒ Slug size, displacement & position pre-calculated?

Gas shows on connections, drilling and on previous trip? ⇒ Trip Margin adequate? ⇒ ‘Swab’-trip considered? ⇒ Spotting a viscous pill above reservoir considered?

Reservoir High permeable? Monitoring equipment in good working conditions? Extra training for personnel required?

⇒ HPHT conditions! ⇒ UBD conditions!

Yes Yes

Continue with Attachment #2.



Attachment #2: Guideline on how to POOH safely.

No Yes

No

Yes

No Yes

Yes No

POOH and confirm hole conditions. Check for Swabbing; externally, annulus, and internally, drillstring!

Swabbing? ⋅ Continue POOH and consider pumping a slug only when back in the shoe. ⋅ Have regular Flow checks. ⋅ When O/P’s are experienced swabbing can still occur!

In drillstring; ⋅ Fill up, check fluid level and circulate drillstring volume to homogenous mud. ⋅ Flow check.

In Annulus

Flow?

⋅ Flow check. ⋅ Evaluate situation.

Condition mud and Circulate clean. Flow Check

“Colour coding”: = safe = be Alert = unsafe, close-in

Close in and evaluate situation.

Bit close to bottom?

⋅ Prepare to Strip to bottom. ⋅ Strip to bottom. ⋅ Circulate Influx out, use Drillers method (P Standpipe = Cst).

No

Yes

⋅ Use Drillers method to circulate out any possible influx in annulus. ⋅ Flow check. ⋅ RIH, circulate and condition mud as required. ⋅ Flow check. ⋅ Wash out of hole and clear tight spots(s). ⋅ Continue and follow plan.

Swabbed close to a possible reservoir or in Top-hole?

⋅ Circulate and condition mud. ⋅ Flow check. ⋅ RIH, circulate and condition mud as required. ⋅ Flow check. ⋅ Wash out of hole and clear tight spots(s). ⋅ Continue and follow plan.

⋅ Circulate and condition mud. ⋅ Flow check. ⋅ Wash out of hole and clear tight spots(s). ⋅ Continue and follow plan

Bit change?

No, i.e. extended exposure time!

Yes, i.e. short exposure

time!

Remember: Every situation stands on it own. Perform Volumetric bleed when gas percolates

up. Don’t start Stripping operations when not 100% prepared.

Stripping back to bottom is a non-standard operation. Evaluate carefully and Instruct crew thoroughly, repeat same on crew changes.

This flowchart is a guide for standard operations, modify it when your operations are non-standard, i.e. UBD, HPHT, etc.

Yes

Sufficient Trip Margin?



Attachment #3 Volumetric Control for Gas migration with Bit off Bottom. Any time a well is closed-in due to signs of a possible influx observed while POOH and if this influx contains Gas, the influx will start to migrate to surface ⇒ increase of pressure in time will be observed. This increase in pressure should be monitored closely and controlled, while the Rig team prepares themselves for this Well Control event, this to prevent any possible fracturing of formation and in particular around the previous casing shoe. How to control this increasing pressure, while maintaining a bottomhole pressure preventing any further escalation (2nd influx), is described below and should be used to train staff on the Rig. Other applications where this application could be used for are:

Pipe is near surface and the weight of string insufficient to perform stripping operations. Pipe is completely out of the hole pre-empting a stripping operation. Annular BOP damaged and stripping through pipe-rams is not an option (no double set of pipe-

rams or spacing for Tooljoint not sufficient) Circulation through the drillstring not possible due to plugged nozzles, forgot to open RHKC

when stripping had commenced, etc.

Equipment Arrangement for Volumetric Control

Next pages will describe: The migration and volumetric control of a closed-in well containing a gas-influx with the Bit off

bottom.

Gray Valve

RHCK

BHA

Swabbed Influx

Choke

Trip Tank, calibrated!

Stripping Tank, calibrated!

Annular Preventer

Stripping Bottle

Closing line

Opening line

Choke venting into Trip-tank

Returns from Flowline back into Trip-tank

Ram-type Preventers not included!



Percolation or Migration speed: When no pressure is released on surface, the gas-influx volume will not change and the pressure at the top of the, assumed, bubble will remain Cst, Boyle’s law: PxV=Cst. Since the gradient of gas is far less than the gradient of any mud system, ρgas +/- 2-3 kPa/m and ρmud

>10+ kPa/m, the influx will migrate, change-over of medium, to surface. Since a volume is a function of Area x Height (AxH), Boyle’s law in this case becomes also a function

of height which has to be translated into Hydrostatic Head (HH). Subsequently, when an influx migrates in time, it will come around several drillstring components and

consequently the height of the influx will change accordingly. In relation to this the equivalent hydrostatic head will change ⇒ rapid increase in choke pressure when migrating across your BHA. This at the same time can indicate where about the influx could be positioned.

See figure below for a schematic explanation.

Influx below BitH1

Pchoke

H3Influx around

BHA

PchokePchoke

Influx partly around BHA and in OHH2

•Influx volume remains constant, Pchoke raises constantly and aggressively when getting around the BHA.

•Height of influx changes due to capacity changes of hole configuration. (H1<H2<H3)

•Consequently the hydrostatic head of gas changes.

To determine the migration speed its important that annular, choke, pressures are recorded at specific time intervals, pressure recorded every 5 min (?), to calculate the migration speed. The accuracy of calculating the migration speed depends if the influx moves up without any change of annular capacity ⇒ height.

Theoretically the “Gas Bubble” migration speed is calculated by using the following formula:

Percolation/Migration speed (m/hr) = ∆(Pann2-Pann1) / ρmud ∆ P ann in kPa/hr after the initial build-up. ρmud in kPa/m of mud presently in the hole.

If the gas influx migrates, the surface pressure will increase accordingly which could lead to a

formation breakdown. To control this situation it is necessary to bleed-off fluid and as such let the influx expand. Consequently the pressure on top of the gas bubble, Boyle’s law, will decrease and as such the bottomhole pressure will reduce.

This reduction in bottomhole pressure should not become less than the original pressure otherwise a second influx will develop. To control the well at a pressure equal or above original bottomhole pressure, a controlled volume has to be bled-off in conjunction with a pre-determined Pchoke.



Controlled bleed-off Volume to remain in Control: To simplify calculations we use a universal annular capacity Open Hole/Drill collar capacity. The influx is seen as a single bubble. The open hole/Drill collar capacity is used which gives the “worst case” situation (as explained above) The choke man will maintain a constant predetermined pressure. The bleed-off of mud to maintain a

constant pressure will be collected in a calibrated Trip-Tank and volumes recorded. The choke man should allow the choke pressure to rise by Pw when a predetermined ∆Volume is

recorded due to loss of HH while gas is expanding. Below the calculations, procedures and a graphical summary of results explained in detail. These predetermined pressures and volumes equals;

P choke pressure (Pch)= P annulus pressure (Pann) + P safety pressure (Ps) + P working pressure (Pw) Pann = Initial annular closed-in pressure before second build-up. Ps = Safety for allowance for loss of hydrostatic head (HH) as influx gets across DC’s. = Influx volume x F-factor (predetermined) Whereby: F-factor = (1 / OHcapacity) x (ρ mud- ρ gas)x(OH capacity / OH-DC capacity -1) F-factor - kPa/m OH capacity - m3/m OH-DC capacity - m3/m ρ mud - kPa/m ρ gas - kPa/m (use 2.3 when unknown) Influx volume - m3

Pw = Working pressure increment equivalent to a ∆Volume of mud converted into HH. Whereby: Pw = usually chosen as 300 kPa ∆Volume = (Pw / ρ mud) x OH-DC capacity

1.Close-in choke and allow Pchoke to build to Pchoke 1, i.e. Pann+Ps+Pw

2.Maintain choke pressure constant by bleeding fluid at choke & collect in trip tank to a predetermined volume Δ V

3.Close-in choke and allow Pchoke1 to build up by a Pw step to Pchoke2, i.e.: Pchoke1+Pw

Expansionof gasinfluxequivalentto Δ V inDC/OHAnnulus.

Pchokeconstant

Expansionof gasinflux iscalculatedfrom theincrease involume ΔV

ΔV

Volume increase atsurface due toexpansion of gas

Volumetric Control Steps

ΔV



Ps Downhole

Downhole

Surface

PsPw

The Volumetric MethodPch3 = Pch2 + Pw

Bottom Hole Pressure (HH)

Closed-in Annulus Pressure

Pch1 = Pan + Ps + Pw

Influx getting across BHA, DC’s, P safety controlling loss of HH

Pch2 = Pch1 + Pw

⇒

When using the Volumetric Control method and when for any reason circulation isn’t possible due to a plugged drillstring, stripping pipe was not an option due to the limited string weight or no pipe was in the hole, eventually gas will reach surface, at the choke, due to migration. At this stage, maintaining minimum wellhead pressure, the option of bleeding off by letting the gas migrate and expend will stop. The well has to be “Lubricated”, i.e. reversing the process, pumping a measured volume of mud into the well and reduce surface pressure in line with the net increase in hydrostatic pressure of mud. The sequence of the reversed process;

Pump the equivalent volume, ∆Volume = (Pw / ρ mud) x OH-DC capacity, into the annulus. Allow time to let mud fall through the gas bubble. Bleed-off gas pressure equal to Pw, ⇒ Pchoke new =Pchoke old - Pw Continue until all gas is replaced by mud and zero wellhead pressure is reached. Read graph below as an example.

Reverse Volumetric Control

0

500

1000

1500

2000

2500

0 500 500 1000 1000 1500 1500 2000 2000

Volume pumped

Wel

lhea

d pr

essu

re

Released pressure, equals Pw

Pumped volume, equals ∆V



Attachment #4

Equipment requirements to perform a stripping operation. 1. General: The equipment requirements for Stripping pipe during a low pressure Well Control event during a roundtrip can be split into 3 groups:

a. A fluid-discharge system from the Wellhead (BOP) to a dedicated and calibrated tank, to allow a controlled, pressure & volume, bleed-off of mud.

b. A pressure regulation system to respond fast and guarantee sealing of a Bag-type preventer when a Tooljoint is stripped through the sealing element of a Bag-type preventer.

c. Additional equipment to ease the operations. Beside the requirements for equipment, the success factor of handling any Well Control event and in particular when stripping operations have to be conducted, is understanding the limitations of the equipment in use. Most events escalated since sealing elements of preventers got unnecessary damaged. Therefore it’s of great importance that Manufactures maintenance-and operational manuals of all equipment on your Rig are available, understood and adopted to. Hereafter a brief description of the equipment requirements and operating limitations will be described, but nevertheless its the task of the Supervisors on the Rig, Contractor as well Company man, to familiarize themselves and ensure that they understand the operating limits of their equipment in use. 2. Schematic Equipment layout: Below a schematic layout (copy from Drillers-notebook) of the fluid discharge from the Wellhead, via

the Choke-line & Choke-manifold into a calibrated Trip-tank. To ease operations a Strip-tank, calibrated, is used to monitor and record volumes of Closed-End (CE) displacement of pipe, stand, stripped into the hole while in the Trip-tank the volume increase of gas expansion is monitored/recorded separately.



Below a schematic layout (copy from Drillers-notebook) of a pressure regulation system to respond fast

and guarantee sealing of a Bag-type preventer when a Tooljoint is stripped through the sealing element of a Bag-type preventer. To minimise wear on the sealing element of a Bag-type preventer the closing pressure should be reduced as much as possible and the element allowed to expand and contrast (breathe) as the Tooljoint pass through. Lubrication of the pipe with a mixture of oil and graphite or a small leakage of mud, only if discharge of the leakage is collected in the Trip-tank, will reduce wear of the element even further. To ease the expansion and contraction of the sealing element of the Bag-type preventer, a Surge-bottle, a 10 gallon Accumulator, is installed as close as possible to the preventer. The pre-charge pressure of the Surge-bottle, accumulator, depends on the type of Bag-type preventer installed. As rule of thumb it should be pre-charged to 50% of the minimum required closing pressure, described further on, for a Bag-type preventer. Under normal operating conditions, the Surge-bottle should be isolated.

Removing vent-plug on opening line, only for Cameron type-D preventers!

To ease operations, most remote BOP control systems are equipped with a control suitable to regulate the Bag-type preventer closing pressure remotely. To adjust the closing pressure of the Bag-type preventer remotely, an air (hydraulic) operated regulating-valve should be installed on the BOP control unit. The air operated regulating-valve should be a fail-safe type, i.e. maintain closing pressure when the air or hydraulic signal to operate the valve is lost. The TRTM regulation valve incorporates a fail-safe feature. With the TRTM regulator, if the pilot pressure is lost, the manual adjusting screw remains in position, thereby maintaining the last regulated pressure setting. Important here is that the mechanical lock screw remains locked to ensure that the last setting remains.



An other advantage of the TRTM-fail safe regulator valve is; high flow-through vs. valve size due to a multiple internal flow paths, therefore responsive to stripping operations due to the multi-port vent line.

3. Bag-type preventers and minimum closing pressure: Hydrill GK preventer:

The GK preventer has been developed especially for use on surface installations. Seal off is effected by hydraulic pressure applied to the closing chamber which raises the piston, forcing the packing unit/element into a sealing engagement. The GK is designed to be pressure assist in maintaining packing unit seal-off once initial seal-off has been affected. As well pressure increases, closure force will increase and as such the friction force to strip pipe through the preventer will increase.

Longest packing unit life is obtained by adjusting the closing chamber pressure. The table below can be used as a guide for the GK-preventers to establish the initial closing pressure (psi).



Cameron D-type preventer:

The main difference between the Hydryl type GK bag-type preventer and the Cameron D-type bag-type preventer is that the Type-D is not pressure assist. The advantage of this is that friction forces to strip through the preventer will not increase while wellhead pressure increases. Although, the disadvantage is that closing pressures are slightly higher and as such increased wear to the packing element. Secondly the initial stripping forces are also slightly higher due to the higher closing pressure. Pre-charge pressure for the Surge-bottle in combination with a type-D preventer should be +/- 4/500 psi. The recommended method of venting the opening chamber is to remove the plug from the unused opening port.

Cameron “D” Type Annular Preventer

Operating Piston Vent

As mentioned before, always use the lowest practical closing pressure when stripping, to prevent the packing element from excessive wear. Reduce the closing pressure until well fluid leaks slightly around the packing unit while the pipe is in motion. For the Cameron type-D preventer it’s important to monitor the closing pressure while stripping a Tooljoint through the packing element. The pressure surge in the BOP closing chamber should not exceed an increase of 100 psi. The greater the pressure surge the faster the wear of the packing element. The graph on the next page can be used as a guide to estimate the minimum closing pressure, for a type-D preventer, required to seal a given wellbore pressure when stripping.



Importance of knowing your equipment limitations: Below an illustration, showing the differences on minimum closing pressures of the various types of Bag-type preventers, hopefully this demonstrates that it’s necessary to check your operating manuals to apply the correct procedures.



Attachment #5

Checklist as preparation for the combined Stripping & Volumetric method. At this stage it’s assumed that the well is already closed in as per standard procedure!

A: Stripping through the Bag-Type preventer. Yes No 1. Organisation:

a. Has one person been designated to supervise the stripping operations? b. Have personnel on location been assigned to specific tasks and instructed on

operations/tasks?

c. Is there a prepared tabulation sheet to record all pressures while preparations are ongoing?

d. Choke-man assigned and instructed what his maximum surface pressure is and how to handle if this pressure is reached?

2. Equipment:

a. Are drawings with dimensions of the BOP available and checked? b. Can you equalize pressure between preventers with the well pressured? c. Are Trip-and Stripping tank dimensions available and checked? d. Can the volume in these tanks accurately be measured? e. Is a fill-up line, to fill-up the (drill) string, available and operational on the

Rigfloor? Confirm from which tank this mud is taken (avoid using the Trip-tank, will confuse situation)?

f. Will all released fluids, from choke manifold and bell-nipple (leakage when tool joints pass through preventer), bled back into the Trip tank?

g. Are all pressure gauges working and of the required accuracy & range? h. Are spare Right Hand Kelly-Cock (RHKC) and Gray valve (inside BOP)

available?

i. Are there spares for BOP (seals) and choke available? j. Can you drain mud from Trip tank into Strip tank? k. Pressure recorders available to monitor trends/steps.(useful for evaluating

operations!)?

3. Observations:

a. Was a heavy slug pumped? b. Are all annuli pressures recorded (A/B/C)? c. Are the original circulation pressures recorded? d. Is there a float valve installed in the BHA? e. Are pressure gauges checked and compared? f. External and/or internal swabbing occurred? g. Depth of observed resistance recorded? h. Pressures recorded at a fixed time interval? i. Swabbed volume recorded? j. Well started to flow while POOH or when RIH? k. Bit depth and drilled depth recorded? l. Is the stripping force known/recorded to strip a Tooljoint/RHKC or Gray

valve through the back-type preventer (from last Strip-drill!)?

m. String weight been recorded? 4. Calculation:

a. Has the force been calculated against wellbore pressure, on Tooljoint OD, to verify that pipe can be stripped through one of the preventers?



b. Has the Casing burst and/or Maximum Allowable Surface Pressure (MAASP) been determined?

c. Has the effect of stripping into the influx been calculated (Ps)? d. Has the working pressure Pw been converted into an equivalent working

volume, i.e. ∆V in OH-DC annulus?

5. Actions:

a. Install Gray-valve and check if it’s holding pressure by opening the RHKC. (This will only be valid if there is no Float valve installed in the BHA!)

b. Closing pressure of the annular preventer to be adjusted lowered, to minimise wear of preventer packing element? Use manufacture advised closing-pressure rating with respect to Pipe diameter and wellhead pressure. (Breathing of opening line required for Cameron D?)

c. Ensure valve to back-type accumulator surge bottle, mounted close to the annular preventer, is open and has the corresponding pre-charge pressure (400 psi, surface stacks!).

d. Ensure that all rough surfaces on Drillpipe, from tong & slip marks, are smoothed and Tooljoints lubricated before commencing to strip through a preventer.

e. Ensure all drillstring/casing protectors are removed form the pipes which have to be stripped-in.

f. Install the first stand and check that the correct amount of mud, closed-end displacement, is bled into the Strip tank when the stand is stripped in.

6. Post Stripping actions:

a. When Stripping is completed and the well back under control, re-adjust annular closing pressure to the original required closing pressure.

b. De-pressurise and isolate stripping bottle. c. Evaluate occurrence of Well Control Event. d. Evaluate operations undertaken to regain primary control. Record and adjust

rig procedures if required. Consider to increase the Trip Margin and perform a short Swab trip to check if the available Trip Margin is sufficient.

B: Stripping through a Bag-Type and one Ram-Type preventer. This method is used when the force to strip through the Bag-type preventer is too high to pass, e.g. meaning there is not sufficient string weight available to force the RHKC+Gray Valve+Tooljoint through the closed Bag-type preventer. Section B is an addition to A!

1. Checks: a. Is the spacing sufficient to Strip from Bag-type preventer to one Ram-type

preventer when the stripping force of a Tooljoint (+ RHKC + Gray-valve, +/- 1.50 m long) is too high?

2. Actions:

a. Close bottom Ram-type preventer, check visually. b. Bleed-off trapped pressure between Bag-type preventer and Ram-type

preventer.

c. Lower to closing pressure of the Ram-type preventer. d. Open Bag-type preventer (remain aware of possible trapped pressures). e. Strip pipe slowly through the closed Ram-type preventer and tag gently the

rams-body with up-set of the pipe’s Tooljoint.

f. Pick-up to original weight and close Bag-type preventer. g. Pressure up, equalise, between Bag-type and Ram preventer, equal to the



wellhead pressure. h. Open Ram-type preventer. i. Use tags to indicate which preventer will be holding the wellbore pressure. j. Continue repeating cycle 2a-2i until enough weight is available to strip

through the Bag-type preventer.

3. Post Stripping actions:

a. When Stripping is completed and the well back under control, re-adjust annular closing pressure to the original required closing pressure.

b. De-pressurise and isolate stripping bottle. c. Evaluate occurrence of Well Control Event. d. Evaluate operations undertaken to regain primary control. Record and adjust

rig procedures if required. Consider to increase the Trip Margin and perform a short Swab trip to check if the available Trip Margin is sufficient.

Note:

• When maintenance is required on the Bag-type preventer, secure the well and restart operations by means of the above described methods. While repairing the Bag-type preventer ensure the Volumetric Control method is followed, i.e. allowing the well to build up to Pchoke (1,2, etc.) and bleeding off ∆V as per attachment #3.

•



Attachment #6

Well: Volumetric Stripping Sheet Date: Pre-recorded data: Mud gradient kPa/m MAASP kPa

Size of Casing Inch Formations strength gradient (Leak-off or Limit test)

kPa/m

Shoe depth AH/TVD m Size of OH m Casing capacity ltr/m Drilled depth AH/TVD m Size & Wt DP inch # OH-DC capacity ltr/m Tooljoint OD inch OH-DP capacity ltr/m DP cap. & CE displacement ltr/m Slow circulation rate data:

Pump output Ltr/str Avg. CE displacement/stand ltr

20 spm kPa 30 spm kPa Size/Length of DC’s inch m 40 spm kPa

DC cap. & CE displacement ltr 50 spm

kPa

Float valve in BHA installed Yes No

Trip tank capacity ltr/cm Trip tank level increase of 1 stand DP cm

Strip tank capacity ltr/cm Strip tank level increase of 1 stand DP cm

Required friction, loss of hookload, (experienced from previous Strip-drill at zero wellhead pressure) to strip Tooljoint (RHKC/Gray valve) through Bag-type preventer (Fbag-type).

kg

Pre-chosen Pw (usually chosen as 300 kPa) and kPa Equivalent ∆Volume ( (Pw / ρ mud) x OH-DC capacity) ltr Kick / Swab data: Bit depth when closed in? m Closed in when: POOH RIH Swabbed influx volume? ltr Stabilised Pdp (SIDPP)? kPa

Depth(s) of observed resistance while POOH? m

Stabilised Pann1 (SICP)? kPa Pann1 increasing? Yes No ∆(Pann2-Pann1) kPa/5min Stripping Calculations:

Ps

Ps=Influx volume x F-factor F-factor = (1 / OHcapacity) x (ρ mud- ρ gas)x(OH capacity / OH-DC capacity -1)

kPa

Pchoke1 Pchoke1=Pann1+Ps+Pw kPa Pchoke2 , etc. Pchoke2=Pchoke1+Pw, etc. kPa Friction weight due to wellhead pressure Fup=π/4x(ODTooljointx2.54)2xPann1x0.0102 kg Minimum string weight, hookload (HL), required to Strip through Bag-type preventer with Tooljoint.

Minimum required HL= Fup+ Fbag-type kg

Circulation Calculations: Drillpipe content ltr Drillpipe/Casing content ltr BHA content ltr Drillpipe/OH content ltr BHA/OH content ltr Total Drillstring content: ltr Total Annular content: Ltr



Well: Recording Sheet Date:

Triptank level at: Starting level (level1) cm Pchoke4 (level5=level4+∆V) cm Pchoke1 (level2=level1+∆V) cm Pchoke5 (level6=level5+∆V) cm Pchoke2 (level3=level2+∆V) cm Pchoke6 (level7=level6+∆V) cm Pchoke3 (level4=level3+∆V) cm Pchoke7 (level8=level7+∆V) Cm Actual Data: *Triptank level recorded, is actual level after a draining the CE volume of 1 stand into the Strip-tank. Time: Stand #: Pchoke actual: *Trip tank level: Remarks:



Attachment #7

Guidelines for conducting a Strip-drill. 1. Purpose: The purpose of the stripdrill is threefold:

a. Training of personnel to obtain routine and familiarity, including communication aspects. b. Check on proper functioning of equipment. c. Determination of the required annular closing pressure and strip-in friction.

2. Timing: The Strip-drill, ideally, to be held in the casing , prior to drilling-out the shoetrack (leave enough room above the shoetrack to strip-in a minimum of 3 stands!) to avoid any unnecessarily exposure of formation to a pressure which could possibly fracture the same. A Strip-drill could be combined together with a Pit-drill. 3. Procedure:

a. Initiate an alarm to simulate a Well Control event. b. Close-in the well as per standard procedure when tripping. c. Pressure up the well to +/- 3000 kPa, equals Pann. d. Monitor and record all required data and complete the Volumetric Stripping Sheet (as per

attachment 6). e. Evaluate situation (as per attachment 1 &2) and chose to perform a volumetric stripping

operation. f. Use attachment #5, “Checklist as preparation for the combined Stripping & Volumetric

method” for cross-reference to assure all checks are completed and recommendation understood.

g. Reduce the Bag-type preventer to the lowest closing pressure, leakage free, as per Manufacture specifications for the equipment installed at the present wellhead pressure (see attachment #4 for equipment specifications required for Stripping).

h. Line-up Stripping-bottle (sometimes called as; Surge-bottle/Stripping Accumulator), by opening the valve upstream of it. Ensure that the pre-charge pressure of the Stripping-bottle is conform the pre-set specification, i.e. +/- 450 psi for model Cameron type-D preventer or 50% of the required closing pressure as per Manufacture specifications. (Remove opening-line vent-plug from Bag-type preventer for Cameron model-D preventer check Manufactures recommendations & specifications.)

i. Install Gray-valve on the RHKC. j. Open RHKC slowly and check the Gray-valve for leakage.

(When a non ported Float-valve is installed there should be no pressure build-up below RHKC) k. Install a stand of Drillpipe, and smoothen all Tong-& Slip marks and lubricate each Tooljoint

with grease (don’t use pipe dope) when stripping will be performed. If used/installed, remove all Drillpipe/Casing protectors.

l. Ensure choke-line and manifold are lined-up to the Trip-tank. m. Fill Trip-tank to 1/3 of its capacity, mark and record volume. n. Strip-in/Run in hole with a minimum of 3 stands while maintaining a constant wellhead

pressure. Bleed-off CE-displacement of every stand into the Stripping-tank Record and check Trip-tank volume for gain (since this is a drill, nothing will be seen, but let crews get used to do it). Check if filling-up of the drillstring is properly done and done with original mud. Record actual values of annular closing pressures and friction due to the Tooljoint (RHKC and Gray-valve) passing through the closed Bag-type preventer.

o. After the exercise is completed, release wellhead pressure via Choke-manifold. (Install opening-line vent-plug if removed from Bag-type preventer as per Manufactures specifications.) Open de Bag-type preventer and POOH till the Gray-valve and RHKC can be removed. (Be aware of any trapped pressures below Gray-valve.)



p. Reset all closing pressure of preventers to original. Close valve upstream Stripping-bottle and assure that bottle is pre-charged to its original pressure.) Reset all Choke-line & Manifold valves as per original.

q. Evaluate drill with all involved and record any recommendations/short-falls for future reference.

Guidelines for Volumetric Stripping Rev.1 Feb.2004

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Transcript of Guidelines for Volumetric Stripping Rev.1 Feb.2004