Q922+de1+l05 v1

Drilling Engineering 1 Course (2nd Ed.)

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1. Hoisting System:A. The Block & Tackle

a. Hook Power

B. Load Applied to the Derrick

2. Drilling Fluid Circulation SystemA. Mud Pumps

1. Drilling Fluid Circulation SystemA. Mud Pumps (Duplex PDP & Triplex PDP)

B. Solids Control Equipmenta. Mud Cleaners

C. Treatment and Mixing Equipment

Duplex pumps

Piston scheme (double action) A duplex unitSpring14 H. AlamiNia Drilling Engineering 1 Course (2nd Ed.) 5

Triplex pumps

Piston scheme (single action). A Triplex unitSpring14 H. AlamiNia Drilling Engineering 1 Course (2nd Ed.) 6

the pump factor

The duplex mud pump consists of two double–action cylinders. This means that drilling mud is pumped

with the forward and backward movement of the barrel.

For a duplex pump (2 double–action cylinders) the pump factor is given by:

The triplex mud pump consists of three single–action cylinders. This means that drilling mud is pumped only in the

forward movement of the barrel.

For a triplex pump the pump factor is:

Spring14 H. AlamiNia Drilling Engineering 1 Course (2nd Ed.) 7

Pump Flow Rate

For both types of PDP, the flow rate is calculated from:

For N in strokes per minute (spm), dL, dR, and LS in inches, Fp in in3, and q in gallons per minute (gpm) we have:

Note that in this particular formulation, the volumetric efficiency of the pump is included in the pump factor.


Pump Power

Pumps convert mechanical power into hydraulic power. From the definition of power P=Fv

In its motion, the piston exerts a force [F] on the fluid that is equal to

the pressure differential in the piston Δp times the area A of the piston, and

the velocity v is equal to the flow rate q divided by the area A, that is

For PH in hp, p in psi, and q in gpm we have:


pump factor & hydraulic power

Compute the pump factor in gallons per stroke and in barrels per stroke for a triplex pump having 5.5 in liners and

16 in stroke length,

with a volumetric efficiency of 90%.

At N = 76spm, the pressure differential between the input and the output of the pump is 2400 psi. Calculate

the hydraulic power transferred to the fluid, and

the required mechanical power of the pump if Em is 78%.


pump factor & hydraulic power

The pump factor (triplex pump) in in3 per stroke is:

Converting to gallons per stroke and to barrels per stroke gives:

The flow rate at N = 76spm is:

The hydraulic power transferred to the fluid is:

To calculate the mechanical power required by the pump we must consider the efficiencies:


Surge Dampeners

Due to the reciprocating action of the PDPs, the output flow rate of the pump presents a “pulsation” (caused by the changing speed of the pistons as they move along the liners). This pulsation is detrimental

to the surface and downhole equipment (particularly with MWD pulse telemetry system).

To decrease the pulsation, surge dampeners are used at the output of each pump.


schematic of a typical surge dampener

A flexible diaphragm creates a chamber filled with nitrogen at high pressure.

The fluctuation of pressure is compensated by a change in the volume of the chamber.

A relief valve located in the pump discharge line prevents line rupture in case the pump is started against a closed valve.

Surge dampenerSpring14 H. AlamiNia Drilling Engineering 1 Course (2nd Ed.) 13

solids control equipment

The purpose of the solids control equipment is to reduce to a minimum the amount of inert solids and gases in the drilling fluid.

They are:Shale shakers,

Degassers,

Desanders (hydrocyclones),

Desilters (hydrocyclones),

Centrifuges,

Mud cleaners.


inactive solids effects

Fine particles of inactive solids are continuously added to the fluid during drilling. These solids increase the density of the fluid and

also the friction pressure drop, but

do not contribute to the carrying capacity of the fluid.

The amount of inert solids must be kept as low as possible.


sketch of a typical solids control systemFigure shows

a sketch of a typical solids control system (for unweighted fluid).


shale shaker mechanism

The shale shaker removes the coarse solids (cuttings) generated during drilling.

It is located at the end of the flow line.

It constitutes of one or more vibrating screens in the range of 10 to 150 mesh over which the mud passes before it is fed to the mud pits.

Shale shaker configurationsSpring14 H. AlamiNia Drilling Engineering 1 Course (2nd Ed.) 18

a typical two–screen shale shaker

The screens are vibrated by eccentric heavy cylinders connected to electric motors.

The vibration promotes an efficient separation without loss of fluid.

A two–screen shale shakerSpring14 H. AlamiNia Drilling Engineering 1 Course (2nd Ed.) 19

Degassers

Gases that might enter the fluid must also be removed. Even when the fluid is overbalanced,

the gas contained in the rock cut by the bit will enter the fluid and must be removed.

The degasser removes gas from the gas cut fluid by creating a vacuum in a vacuum chamber. The fluid flows down an inclined flat surface

as a thin layer. The vacuum enlarges and coalesce the bubbles. Degassed fluid is draw from chamber

by a fluid jet located at the discharge line.


A typical degasser diagram(A vacuum chamber degasser)


Hydrocyclones (Desanders and Desilters)Hydrocyclones are simple devices with no internal moving parts.

The drilling fluid enters the device through a tangential opening in the cylindrical section, impelled by a centrifugal pump.

The centrifugal force generated by the whirling motion pushes the solid particles towards the internal wall of the inverted cone.

As the whirling flux moves downwards the rotating speed increased and the diameters decreases.

The fluid free of solid particles is “squeezed” out of the flow and swirls upwards in a vortex motion, leaving the hydrocyclone from the upper exit.

The solids leave the hydrocyclone from the apex of the cone (underflow).

For maximum efficiency, the discharge from the apex exit of hydrocyclone should be in a spray in the shape of a hollow cone rather than a rope shape.


Flow path in a hydrocyclone

Figure shows the fluid/solids paths in a hydrocyclone.


Hydrocyclone classifications

Hydrocyclones are classified according to the size of the particles removed as desanders (cut point in the 40–45μm size range) or desilters (cut point in the 10–20μm size range).

At the cut point of a hydrocyclone 50% of the particles of that size is discarded.

The desander is a set of two or three 8in or 10in hydrocyclones, and are

positioned after the shale shaker and the degasser (if used).

The desilter is a set of eight to twelve 4in or 5in hydrocyclones. It removes particles that can not be removed by the desander.


Solid control equipment

(a) Desander (b) DesilterSpring14 H. AlamiNia Drilling Engineering 1 Course (2nd Ed.) 25

Particle size classification

A typical drilling solid particle distribution and particle size range classification are shown in the diagram.The diagram

includes the particle size distribution of typical industrial barite used in drilling fluids.


Centrifuges

The centrifuge is a solids control equipment which separates particles even smaller, which can not be removed by the hydrocyclones.

It consists of a rotating cone–shape drum, with a screw conveyor. Drilling fluid is fed through the hollow conveyor. The drum rotates at a high speed and creates a centrifugal

force that causes the heavier solids to decant. The screw rotates in the same direction of the drum but at a

slight slower speed, pushing the solids toward the discharge line.

The colloidal suspension exits the drum through the overflow ports.


Internal view of a centrifuge

The drums are enclosed in an external, non–rotating casing not shown in the figure.


mud cleaner

Inert solids in weighted fluid (drilling fluid with weight material like barite, iron oxide, etc) can not be treated with hydrocyclones alone because the particle sizes of the weighting material are

within the operational range of desanders and desilters.

Weighting material are relatively expensive additives, which must be saved.

A mud cleaner is a desilter unit in which the underflow is further processed by a fine vibrating screen, mounted directly under the cones.


mud cleaner schematic

The mud cleaner separates the low density inert solids (undesirable) from the high density weighting particles.

Unit of a mud cleanerSpring14 H. AlamiNia Drilling Engineering 1 Course (2nd Ed.) 32

Hydrocyclones

Hydrocyclones discriminate light particles from heavy particles. Bentonite are lighter than formation solids

because they are of colloidal size (although of the same density).

Barite particles are smaller than formation solids because they are denser.

The desilter removes the barite and

the formation solids particles in the underflow, leaving only a clean mud

with bentonite particles in a colloidal suspension in the overflow.


Hydrocyclones (Cont.)

The thick slurry in the underflow goes to the fine screen,

which separate the large (low density) particles (formation solids) from the small (high density) barite particles, thus conserving weighting agent and the liquid phase but at the same time returning many fine solids to the active system.

The thick barite rich slurry is treated with dilution and mixed with the clean mud (colloidal bentonite).

The resulting mud is treated to the right density and viscosity and re–circulates in the hole.


Principle of the mud cleaner

Mud cleaners are used mainly

with oil– and synthetic–base fluids where the liquid discharge from the cone cannot be discharged, either for environmental or economic reasons.

may also be used with weighted water–base fluids to conserve

barite and the liquid phase.

A diagram of a mud cleanerSpring14 H. AlamiNia Drilling Engineering 1 Course (2nd Ed.) 35

Drilling fluid components

Drilling fluid is usually a suspension of clay (sodium bentonite) in water.

Higher density fluids can be obtained by adding finely granulated (fine sand to silt size)

barite (BaSO4).

Various chemicals or additives are also used in different situations.

The drilling fluid continuous phase is usually water (freshwater or brine) called water–base fluids.

When the continuous phase is oil (emulsion of water in oil) it is called oil–base fluid.


Mixing Equipment

Water base fluids are normally made at the rig site

(oil base mud and synthetic fluids are normally manufactured in a drilling fluid plant).

Special treatment and mixing equipment exists for this purpose.

Tank agitators, mud guns, mixing hoppers, and other equipment are used for these purposes.


drilling fluids physical propertiesblendersThe basic drilling fluids physical properties are density,

viscosity, and filtrate. Fresh water density is 8.37 pounds per gallon (ppg). Bentonite adds viscosity to the fluids and also increases the

density to about 9 to 10 ppg. Higher density (15 to 20 ppg) is obtained with barite, iron

oxide, or any other dense fine ground material.

Tank agitators or blenders are located in the mud tanks to homogenize the fluid in the tank. help to keep the various suspended material

homogeneously distributed in the tank by forcing toroidal and whirl motions of the fluid in the tank.


Mud agitator

Tank agitators or blenders toroidal and whirl motionsSpring14 H. AlamiNia Drilling Engineering 1 Course (2nd Ed.) 40

Mud guns

Mud guns are mounted in gimbals

at the side of the tanks, allow aiming a mud jet

to any point in the tankhelp to homogenize the

properties of two tanks, and spread liquid additives in a large area of the tank (from a pre-mixed tank).

Centrifugal pumps power the mud guns.

Mud gunSpring14 H. AlamiNia Drilling Engineering 1 Course (2nd Ed.) 41

mixing hopper

The mixing hopper allows adding powder substances and

additives in the mud system.

The hopper is connected to a Venturi pipe. Mud is circulated by centrifugal pumps and

passes in the Venturi at high speed, sucking the substance into the system.


Mud hopper


1. Jorge H.B. Sampaio Jr. “Drilling Engineering Fundamentals.” Master of Petroleum Engineering. Curtin University of Technology, 2007. Chapter 2

1. The Rotary SystemA. Introduction

B. Kelly, Kelly Valves, and Kelly Saver Sub

C. Rotary Table and Components

2. Well Control System

3. Well Monitoring System

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