RIG PUMP

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7/13/2007 M A-Mohsen

RIG PUMPS

High-pressure mud pumps are positive displacement pumps. They convert mechanical power into hydrau

power. Their mechanical components (power ends) are usually maintained by mechanics. The hydraulic p(fluid end) of the pump, however, is maintained by the drilling crew. Since they are a critical part of the

equipment it is essential that the drilling engineer should have a thorough knowledge of their mechanical hydraulic aspects.

The pump nomenclature, as given in Figure 3.3.01 showing a cross-section of a duplex pump, should be stud

carefully to obtain a knowledge of the basic terminology.

This Topic will deal with:

Working principles

General construction

Pulsation dampeners

Relief valves Capacity, efficiency and

required power

Figure 3.3.01High-pressure mud pump

3.2.1 WORKING PRINCIPLES

SINGLE ACTING PUMP

The power end of the pump serves to convert

the rotary motion of the prime mover into a

reciprocating motion. This reciprocatingmotion is, in turn, converted to fluid flow by a

piston or plunger type fluid end.

The part where rotary motion changes into

reciprocating motion is normally called a"crosshead". The connecting rod provides the

linkage between crank and crosshead. The

piston or plunger is connected to the

crosshead by the extension rod and the pistonrod. Figure 3.3.02 Single-acting pump

In a single-acting mud pump the piston produces the fluid volume during half the crank cycle only.

The main parts of the pump's fluid end are: the housing itself, the liners with packing rings, covers plus packpiston(s) with piston rods, and the suction and discharge valves with seats.

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In practice triplex pumps have the following advantages:

The triplex pump provides a more even delivery so that discharge variations are about half those o

duplex pump. This provides longer life of pump parts, hoses etc.

The total weight of a triplex pump is approximately 70 % of that of a duplex pump with the sacapacity and it also requires less space.

Triplex pumps are more accessible than duplex pumps and consequently maintenance is faster cheaper.

Downtime incurred due to pump repair is expensive and should be prevented. Frequent pump overhauls

demanding in terms of labour. Therefore the purchase of a generously sized pump is often preferred as reduces the wear on parts, and the amount of maintenance required.

Common operational requirements may vary between 5.4 - 6.7 m3/min at 7,000 kPa (1,200 - 1,500 gpm at 1,psi) and 1.35 - 2.25 m3/min at 31,500 kPa (300 - 500 gpm at 4,500 psi). However, from experience it has b

found that mud pump part wear sharply increases when operating the pump at pressures exceeding 21,000 k

(3,000 psi).

Liner changes can be necessary when the flow rate ranges required during the course of the well cannot

covered by one and the same liner size, even when several pumps are run simultaneously.

3.2.2 CONSTRUCTION

The power and fluid ends are shown below in more detail.

POWER END

Figure 3.3.05 gives a cut-away view of a

complete power end. The rotatingmotion of a one piece pinion and shaft isconverted into a reciprocating motion by

an eccentric shaft. All the shafts aresupported by roller bearings.

The crosshead, which slides inside a

crosshead guide to sustain the true linear

movement of the extension rod is clearly

visible as well as the stuffng boxassembly which is also shown in detail

in Figure 3.3.06.

The connection between the extension

rod and piston rod is a fine tapered treadwith jam nut (in a double-acting pump)

or butted with a clamp (in a single acting pump) as shown in the figure below.

Figure 3.3.05 :Power end of a mud pump

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Figure 3.3.06Stuffing box assembly (oil-seal type) Figure 3.3.09 : Cross-section oil-flood stuffing box

Figure 3.3.07 :Extension-piston rod connection

FLUID END

Special attention should be paid to the oil floodstuffing box (Figure 3.3.09) which has to

withstand the full pump pressure. The stuffing

box is cooled and lubricated by an independentlubricating system.

A closed cooling system is used to protect the Figure 3.3.11 :Piston cooling system

pistons of the single-acting pump from overheating (see Figure 3.3.11). The cooling liquid is usually a mixt

of oil and potable water and is circulated by a small pump. If the pistons were not cooled the sleeves wobecome hot and overheat within a few minutes. The cylinder surface must also be lubricated.

The splash baffle on the extension rod prevents the cooling water being carried to the pump crank-case by

extension rod.

PISTON AND LINER

Liners of high-pressure mud pumps are always locked in place by a metal-to-metal contact.

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A special liner lock nut is used in triplex pumps (see number 13 in Figure 3.3.10); duplex pumps are provi

with a dual cage metal-to-metal liner retention system (Figure 3.3.12).

The latter arrangement holds the liner metal-to-metal against a

shoulder in the housing by means of set screws (the large bolts inFigure 3.3.18), which are tightened against a liner cage. The liner

packing is adjusted separately with set screws on a liner packing cage(the small bolts in Figure 3.3.12). Some types of pumps have specialtell-tale holes (a small hole connecting the liner packing spacer ring

area to atmosphere) to check the proper functioning of the packing. If

fluid drips out of these holes the liner packing has to be tightened.

These holes should never be plugged off to stop the "leaking"! Figure 3.3.12 :Retention system in duplex pump

Liner wear is worst in the middle of the stroke as a result of the piston

velocity being highest at that point.

The maximum allowable liner wear depends on the pressure the pump has to

overcome (see Table 3.3.1). Figure 3.3.13 :Liner wear

Figure 3.3.14 :Pistons of mud pumps

Figure 3.3.14 shows the pistons of a double-

acting and a single-acting pump. Note thatthe piston bodies have been provided with a

special tell-tale wear groove to provide a

means for judging the piston wear.

The piston rubbers are made of

polyurethane. The clearance betweenpiston and liner determines the life of the

rubbers (see Figure 3.3.15). If the play is

too great it is possible that the rubber willbe extruded into the gap and become torn.

VALVES AND SEATS

The volumetric efficiency is strongly inuenced by the condition of the valves. This means that regu

inspection is a necessity if the efficiency is to be kept optimal.

After inspection the valves should always be returned to the seat from which they came. Valves and seats t

to wear together with matching wear patterns. They will give longer service if they are kept together.

After renewing a seat the valve should always be replaced. The valve is equipped with fins (Figure 3.3.08) o

guide pin (Figure 3.3.10) to ensure good alignment in the seat. A valve spring helps to close the valve.

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Most of the valve seats are tapered on the outside to fit tightly into the pump body. It is essential that the mat

faces are thoroughly cleaned, as improper seating could lead to a washout in the body which could spoil

entire fluid end.

As the fit of the valve seats must bevery tight this means that the valves

have to be driven into position with acopper bar and removed with aspecial (hydraulic) pulling tool.

Figure 3.3.15 :Graph showing piston seal

endurance

3.2.3 CAPACITY, EFFICIENCY AND REQUIRED POWER

CAPACITY

As shown under 3.2.1 (Working principles) the theoretical output per stroke is given by:

for a single acting triplex pump :

for a double acting duplex pump: All in consistent units

Multiplying the theoretical output per stroke by the recorded strokes per minute and adjusting for the volume

efficiency ( ) will give the effective output, Qe.

Thus, for a single acting triplex pump :

Qe

in litres/min

in bbls/min

where, in the two equations where units are given, L, D and d are expressed in inches, which is the u

normally used for this purpose.

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Similarly, for a double acting duplex pump :

Qe

in litres/min

in bbls/min

where in the above equations

Mud pumps are normally equipped with pump stroke counters. There are two types of stroke counters, oneindicate the pump rate (spm) and one to record the cumulative number of strokes. The latter type of counter

used to monitor jobs such as chasing cement and spotting slugs, and during well control. In general s

counters are needed to follow the volumes pumped when volumetric control is essential. However, it is a

necessary to know the pump efficiency to be able to determine the actual volume delivered. Given that efficiency is pressure related it should always be checked when pumping with a reasonable pressure.

VOLUMETRIC EFFICIENCY ( )

As stated in the previous paragraphs, the volumetric efficiency is therelationship between the theoretical and effective output of a pump.

Loss of volumetric efficiency is mainly caused by the delay in valve shutdown. When the plunger motreverses the valves are not yet completely closed, due to the mass-inertia of the valves, and some of the liq

has the opportunity to flow back.

The following losses are recognized:

Leakage losses of the discharge valve:

As long as the discharge valve does not close completely during the suction stroke a small amountliquid will flow back from the discharge line into the cylinder.

Leakage losses of the suction valve:

As long as the suction valve does not close completely during the discharge stroke a small amountliquid will flow back from the cylinder into the suction line.

Other causes of loss in efficiency are:

Losses due to a leaking stuffing box:

During the suction stroke air is sucked in through the stuffing box. This air obviously reduces the ove

suction volume of the pump. During the discharge stroke liquid will leak through the stuffing box so tthe quantity discharged is also reduced.

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Leakage losses between piston and liner:

The seal between the piston and liner may not be perfect, consequently during the discharge stroke soliquid may leak past the piston. It is also possible that during the suction stroke of a single-acting pu

some air is drawn in past the piston.

Leakage losses in suction lines:

Leaks in the suction line may result in air being pulled into the drilling fluid flow during the suctstroke.

Air or gas absorbed in liquids:

The liquid itself may contain gas or air either dissolved or transported as small bubbles. One of the mcommon causes of suction aeration is the mixing of drilling f luid or the adding of chemicals through

hopper.

The highest practical efficiency should be maintained by regularly checking and servicing the pump.

Determination of the pump efficiency

The volumetric efficiency of a pump can be determined by pumping a known volume of uid from one tankanother and comparing it with the theoretical volume calculated from the number of strokes made. This sho

be done whilst pumping over the well at a reasonable rate to ensure the pump is delivering against pressure

good time to do this is when circulating prior to running casing and cementing). The volumetric efficiency oduplex pump will usually be 90 % or more. A triplex pump will usually have a volumetric efficiency gre

than 95%.

POWER REQUIREMENTS

The hydraulic power ( ) can be calculated using the equation

In SI units( ) is in kW, is in kPa and is in m3/min,

thus kW

In field units( ) is in HHP, i is in psi and is in bbls/min,

thus HHP

In practice the input power supplied must be greater than the hydraulic horsepower because of

the work required by the mechanism of the pump itself.

the work absorbed by the hydraulic inefficiencies

The ratio of the hydraulic power to the input power is the mechanical efficiency, . Thus .

is usually of the order of 0.85

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OPERATING LIMITS

Operating limits are set in the first place by the fluid end dimensions but ultimately by the power end. T

maximum discharge pressure is determined by the size of liner installed, and the available torque from

power end. The output volume for a given liner depends on the attainable pump speed, i.e. the available powfrom the power end.

3.2.4 RELIEF VALVES

Mud pumps must be equipped with pressure relief valves. These valves prevent too

high a pressure being built up in the circulating system. The relief valves most

commonly used in Shell operations are the Cameron type "B" reset relief valveand the Cameron shear relief valve. A discharge line should be connected between

this valve and the drilling fluid tank. For safety reasons this relief valve discharge

line must be tied down securely with its end facing down into the tank.

CAMERON SHEAR RELIEF VALVE Figure 3.3.16 :Cameron shear relief valve

The Cameron shear relief valve pops open when pressure setting is exceeded. The tripping pressure of the va

is determined by the strength of the shear pin. In this design the valve snaps fully open and there is no erosof the piston or bore. A chart is printed on the manufacturer's name plate from which it is possible to see wh

size of shear pin is needed for the required pressure limitation.

CAMERON TYPE "B" RESET RELIEF VALVE Figure 3.3.17 :Cameron type "B" reset relief valve

The Cameron type "B" reset relief valve provides the following features:

It opens fully when pressure is exceeded.

The pressure setting is indicated by a pointer. The pressure setting can be changed with pressure on the valve, by

turning an adjusting nut.

The valve design prevents leakage or erosion.

All parts are enclosed.

The valve is set by a reset lever.

The valve can be opened at any time by pressing a release button.

Figure 3.3.18 : Operating diagram of the Cameron type "B" reset relief valve

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3.2.5 PULSATION DAMPENERS

The speed of the piston is not constant during the suction anddischarge strokes. During each stroke the speed increases

from zero to maximum at approximately the halfway position

and then decreases to zero during the rest of the stroke (see

Figure 3.3.19).

Figure 3.3.19 :Piston velocity during a stroke

The change in piston speed, and therefore also the fluid

velocity, causes the oscillating action shown in Figure 3.3.20.The effect is less severe for a single-acting pump than for a

double-acting pump.

Figure 3.3.20 :Mud pump delivery curves

The suction dampener

During the suction stroke when the pump requires moreliquid it draws this from the dampener. Once the suction

stroke has been completed the air chamber absorbs the flow

from the tank and in this way dampens the shock in the suction line.

The discharge dampener

The discharge chamber or pulsation dampener, contrary to the suction

dampener, is partly pressurised with nitrogen gas. During the discharge

stroke the gas in the pulsation dampener is compressed. At the end ofthe discharge stroke the compressed gas expands sustaining a reasonable

steady flow in the discharge line and dampening the peaks in dischargepressure.

Figure 3.3.22 shows a commonly used pulsation dampener. It consists ofa steel spherical body in which a diaphragm is fitted. The diaphragm

separates the gas (nitrogen) from the drilling fluid.

A charging valve and a pressure gauge are installed on top of the

pulsation dampener cover to allow regular inspection and

recharging. To achieve a satisfactory dampening effect the pre-charge pressure should be 75 % of the minimum anticipated

pump operating pressure. The maximum pressure should not

exceed 5250 kPa (750 psi).

Figure 3.3.22 :Pulsation dampener

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WARNING: It is of the utmost importance that nitrogen only is used to charge the pulsation dampener. Seri

accidents have been the result of using oxygen instead of nitrogen.

Dampener location

The best dampening effect is achieved when the dampeners

are installed close to the pump's suction and discharge, asshown in Figure 3.3.23. A hose to absorb vibration should beincluded in the connection between the pump and the

delivery line.

Figure 3.3.23 :Location of dampeners

3.2.6 BOOSTER PUMPS

When the pumps are running at the high end of their speed range even thesuction dampeners may not be abl

cope with the peak intake rates. This results in cavitation with the cylinders not being completely filled

shock loads in the pumps. To eliminate such problems booster or charge pumps are hooked up to the pusuction lines in order to maintain a positive pressure at all times.

Attention must be paid to the following points to ensure that the pump cylinders are filled correctly to prev

piston hammering or pressure surges:

The pump suction has to be as low as possible in relation to the suction tank so that a positive fluid h

can be maintained.

The pump has to be as near to the tank as possible so that the suction resistance is minimum. A boo

pump in the suction line may be required (see Figure 3.3.24) if friction losses are excessive.

The suction line must have an internal diameter as large as possible, and the line must be well sealed

secured to prevent air being sucked into it.

The tank has to be kept full to the normal operating level so that the maximum head is maintained on

suction.

Figure 3.3.24 : Correct connection of a mud

pump

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Low pressure centrifugal pumps

Centrifugal pumps have many rig applications e.g.:

For wash-down water.

For brake and engine cooling. For mixing (hopper).

For drilling fluid agitation (mud gun).

For desanding, desilting and degassing the drilling fluid returns

from the well.

For supercharging slush pump suctions (booster pump).

For circulating trip tank contents over well head during trips.

Figure 3.3.25 :Single-stage centrifugal pump with semi-open impeller

A single-stage centrifugal pump with semi-open impeller is thetype usually employed in drilling rig service (Figure 3.3.25). They

are manufactured in a wide range of:

sizes and capacities.

impeller diameter and shaft diameter.

materials which withstand the various chemicals to behandled.

Figure 3.3.26 :Cross section through centrifugal pump

3.3.1 WORKING PRINCIPLE

A centrifugal pump transfers energy to a liquid through the action of a rotating impeller. The liquid, takenthrough the suction line of the pump is directed towards an impeller which is rotated by a drive shaft. The sh

is normally driven by an electric motor. As the impeller spins inside the housing (casing), its guide vanes h

the liquid outward from the axis of rotation. Because the impeller is enclosed in the casing the liquid is forout through the discharge line with a pressure and velocity higher than that when entering the pump.

A cross section through a centrifugal pump is shown in Figure 3.3.26. The housing is shaped like a snail shClose observation shows that the first amount of liquid will leave the impeller at point "a", called the tongue.

point "b", 90 further, an additional amount of liquid has joined, making a total of one quarter of the liq

eventually produced. At point "c" half the volume has passed, at point "d" three quarters and finally at point the total volume passes.

PUMP NOMENCLATURE

A number of manufacturers make centrifugal pumps for the drilling fluid system, referred to as the 17/8" shtype. This type has been used in oilfleld service since the early '50s. A new type on the market now is desig

for higher horsepower and easier maintenance. Its designation is different from the older designation. T

designation of the old type 17/8" pump is written as d1 x d2whereas the designation of the new types of high

rated pump is written as d2 x d1. (where in both cases d1 is the discharge diameter in inches and d2is the suctdiameter in inches). Comparing the designations:

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For 17/8" pumps old type:

5 x 6 R

Discharge size Suction size Rotation clockwise

For heavy-duty pumps new type:

5 x 6 14

Discharge size Suction size Maximum size impeller for case

All new heavy-duty pumps are made for clockwise rotation. The 17/8" pumps are available for both clockw

and counter clockwise rotation, as viewed from the coupling end of the pump.

3.3.2 COMPARISON WITH RECIPROCATING PUMPS

Centrifugal pumps function in a different way from positive-displacement pumps. Although either type can

run at variable speed, the fluid slippage characteristic of a centrifugal pump makes it suitable for constaspeed/variable-delivery operation.

Figure 3.3.27 :Comparison of reciprocating

centrifugal pumps

The explanation of the calculations

development of the characteristics

centrifugal pumps is not within the scof this course. However, extra st

material has been given in the Appen

to this Part.

When a positive-displacement pump

run at constant speed on two systewith different pressure losses, the volu

will remain the same in both syste

only the pressure and required power will differ. When a centrifugal pump is used in the same two systems, pressure in both systems will remain almost the same, but the volume will be higher in the lower pressure l

system (Figure 3.3.27). For example as shown in the graph, a positive-displacement pump produces 30 l/s (4

gpm) at a head of 14 m (46 ft) to put it through system 1. When it is used on system 2 and the volume rema30 l/s (475 gpm) the head required is only 5 m (16 ft). Putting a centrifugal pump on the same systems

constant speed the results are for system 1, 48 l/s (780 gpm), at a head of 27 m (88 ft); for system 2, 68 l/s (1

gpm), at a head of 24 m (79 ft).

For all pumps the power requirements are proportional to the volume times the pressure increase (

A reciprocating pump producing a constant volume will therefore require power in proportion to the out

pressure. Since a centrifugal pump will maintain an almost constant pressure, the power requiremenproportional to the throughput. It is important to be aware of this difference because system overload m

occur. In system overloading with a positive displacement pump, a bypass valve should open to reduce

pressure and thus reduce the power required, whereas with a centrifugal pump the throughput must be loweto lower the power requirements, e.g. by partially closing the discharge valve.

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A SUMMARY OF ADVANTAGES AND DISADVANTAGES

When a centrifugal pump is compared to a piston or plunger pump of the same capacity, the follow

advantages of the centrifugal pump are immediately apparent:

Light weight.

Takes up a small amount of space. Constant flow of liquid.

Quiet running, so that only a light foundation is needed.

High reliability.

Simple drive; direct by electric motor.

The liquid to be pumped may be somewhat contaminated.

Easily adjustable.

Limited maximum pressure, which cannot cause damage to the pump casing or discharge line.

No valves needed.

It must be mentioned however that many centrifugal pumps are provided with a check valve in

suction line, a foot valve. In process technology the check valve is usually fitted in the discharge lThere are two reasons for this:

o To keep the liquid in the pump from flowing back, which ensures that the pump remains fi

with liquid.o With a high lift it is possible that if the drive falls out the direction of rotation of the impeller w

be reversed which can cause the impeller and shaft to come loose causing damage to the pum

This is particularly the case when a mechanical seal is used (slip ring sealing).

On the other hand, centrifugal pumps also have some disadvantages:

The pump is not self-priming, and therefore has to be filled with liquid when starting up. Considerable chance of milling, when air or gas is drawn in.

Less suitable for volatile or hot liquids under atmospheric pressure.

Lower efficiency than plunger pumps.

Low discharge pressure.

3.3.3 PUMP SIZE AND SELECTION

WORKING CONDITIONS

The design point of a centrifugal pump is that point at

which the internal pump losses are minimum and the pumpefficiency optimal (about 75 - 80%).

As has already been shown in Figure 3.3.27 a centrifugalpump can work at various flow rates and pressure heads -

this is called the working range and is illustrated in the

figure below.

Figure 3.3.28 :Example of pump characteristic

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Lower limit

(the left-hand side of the graph)

At low flow rates the liquid velocity becomes so low that solids can settle in suction or discharge lines, or minimum fluid volume for the equipment it supplies has been reached. This can be because the distance fr

the pump to the delivery point is too great or because the size of the line is too small.

For example: if a rig is using a pump mounted on drilling fluid tank #4 to draw fluid from there and discharg

into tank #1 the friction losses may be considerable. That will reduce the transfer rate.

Upper limit

(on the right-hand side of the graph)

The upper limit of the working range is determined by the development of cavitation in the pump. This w

occur when a pump is acting with a very low pressure head resulting in too high a liquid velocity in the suct

line, e.g. pumping water at zero discharge pressure. Cavitation is explained later.

Output pressure

A centrifugal pump produces pressure by increasing the speed of the liquid to the tip of the impeller and t

converting the velocity into usable output pressure. Pressure is here expressed in not normally used units. Si

m/s (or ft/s) velocity is being converted into pressure, the resulting pressure is stated in m (or ft) of flowfluid. Since a centrifugal pump produces the same velocity with any liquid, it produces the same m (or ft)

head of that liquid, regardless of its specific gravity. But when m (or ft) of head are converted to kPa (or p

the density of the liquid must be included. The higher the density, the higher the pressure in a column wouldfor a given head. Therefore, the output pressure in kPa (or psi) of a centrifugal pump varies in direct proport

to the density of the liquid. Calculating centrifugal pump requirements should first be done in m (or ft) so tthe density variable will be eliminated. Friction loss, elevation rise, and other losses should also be calculatedm (ft) of flowing fluid; the pump curve consulted is already rated in m. Only the power required by the pu

needs to be corrected for density. The "water" power obtained from the pump curve is multiplied by

maximum density of the fluid to be handled to determine the necessary capacity of the electric motor.

A pressure gauge should always be fitted to the discharge line to allow performance monitoring.

Delivery rate

Fluid delivery output of a centrifugal pump can be regulated by:

changing the speed of rotation, or:

throttling the discharge valve.

If the driving unit permits changing speed, this is the better method to use. It is preferred because throttling discharge valve always involves waste of power and ultimately damages the throttling valve by fluid erosi

Although centrifugal pumps can be set for zero delivery by closing a valve on the discharge line, excess

throttling can shorten the life of the pump impeller and housing.

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A better method is to provide a small return line to recirculate a small amount of fluid (Figure 3.3.29). T

prevents overheating the fluid in the pump with resulting damage if the unit must continue to run with

discharge shut off.

Figure 3.3.29 :Suction and discharge piping for a centrifugal pump

Varying the impeller diameter

Because the pressure head is governed by the peripheral velocity of the

impeller, it is inuenced not only by the speed of the pump, but also by

the outside diameter of the impeller blades. Reducing the impellerdiameter is therefore a means whereby the pressure head, at constant

speed, of an existing pump can be lowered, enabling the installation to be matched to changing circumstanc

e.g. diminished delivery distance. If more pressure is required within the limits of the pump a larger diamimpeller can be installed.

The nature of the changes in the pump characteristics which result from reducing the impeller diametershown in the figure.

The pressure is approximately proportional to the square of the impeller diameter, and the power approximatproportional to the third power of the impeller

diameter.

Figure 3.3.30 : Pressure head and power with varying impeller

diameter

Example

Assume that for optimal action of a hydrocyclone a

flow rate of 800 gpm and a total head of 80 ft isrequired.

How can the following equipment be deployed?

a 5 x 6 centrifugal pump operating at 1,150 rpm with spare impellers of 9", 10", 11" and 12".

a 6 x 8 centrifugal pump operating at 1,150 rpm with spare impellers of 10", 11", 12", 13" and 131/2".

an electromotor 30 kW (40 hp) - 1,750 rpm.

Reference to Figure 3.3.31a shows that selecting the maximum impeller size of 12" will give a total head

only 70 ft.

This pump cannot be used at the current speed

Figure 3.3.31a Performance curves for a 5 x 6 centrifugal pump

operating at 1150 rpm

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Figure 3.3.31b: Performance curves for a 6 x 8 centrifugal pump operating

1150 rpm

Reference to Figure 3.3.31b shows that if the 13" impeller ismounted in the 6 x 8 centrifugal pump (1,150 rpm) the

performance will be satisfactory.

Figure 3.3.31c: Performance curves for a 5 x 6 centrifugal pump

operating at 1750 rpm

Reference to Figure 3.3.31c shows that if the 5 x 6

centrifugal pump is used in combination with the electricmotor which runs at 1,750 rpm the required performance

will be achieved using a 9" impeller.

Table 3.3.2 shows the most commonly used impellers for

various applications.

Required input power

The power required for a centrifugal pump

used in drilling fluid handling is the water

power at that volume and pressure multiplied

by the maximum density of the drilling

drilling fluid to be used.

Example Table 3.3.2 : Impeller sizes

An electric motor with a capacity of 50 l/s (800 gpm) and a pressure head of25 m (80 ft) is needed for a desander pump.

What is the input power if the pump efficiency is 75% and the density of thedrilling fluid is 1400 kg/m3(gradient = 1.4 x 9.81 kPa/m or 0.608 psi/ft)?

Solution

Power =

= = 22.89 kW

= =30.27 HP Figure 3.3.32Cavitation

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CAVITATION

The phenomenon of cavitation can be described as follows (see The Figure).

If the vacuum on the suction side of the pump rises to the point at which the pressure of the liquid equals vapour pressure, the water will vaporise. The vapour bubbles in the flow are carried to the impeller where

pressure is increased, causing the bubbles to implode.

When mixing drilling fluid there may be air present sucked in by the hopper. These bubbles will undergo

same process.

This process may be accompanied by hissing and rattling, severe vibration, fairly heavy shocks and ot

irregularities. Furthermore, cavitation causes wear and damage to the pump parts, especially the impeller.

If cavitation occurs the Flow rate should be reduced by increasing the back pressure, e.g. throttling a discha

valve.

DESANDER PUMP

The most critical pressure requirement in the drilling fluid treatment system is that for the desander and

desilter. Insufficient pressure will produce poor solids separation, and too much pressure will cause ea

erosion of the desander and desilter cones. Most desander and desilter cones require 23 m (76 ft) of head at inlet of the manifold. Adding differences in elevation and friction loss makes a total of 27 - 30 m (85 - 90

that the pump must produce.

3.3.4 EFFICIENT OPERATION

FLUID LEVEL FOR SUCTION

A uid level that will provide enough submergence of the pump suction line is necessary to prevent air fr

entering the suction end of the pump. If the pump must operate with low suction submergence, the suction should be oversized. On systems already in operation, a vortex breaker may be needed at the suction inlet of

tank piping. This may be as simple as a board arranged to float above the suction line to seal the air off from

pump suction.

SUCTION PIPING

Suction piping should slope upward from the liquid source to the

pump to avoid traps that will accumulate air. Air trapped in the suction

reduces the cross-sectional area of the line and can cause the pump tocavitate, that is, fail to get enough uid in the casing for complete

filling. Air drawn in through the suction piping can also cause thepump to lose prime on start-up. Figure 3.3.33 : Arrangement for avoiding entrained air in a centrifugal pump suction

Many suction and discharge piping installations are arranged so that uid is returned to the tank just above pump suction (Figure 3.3.33). Practices such as this, which permit air or gas to be mixed into the fluid (a

running mud guns or agitators close to the centrifugal pump), can cause the fluid to become air-cut.

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ALIGNMENT

Serious damage to pump and motor bearings, loss of power, and excessive wear to the pump-motor coupl

can result from misalignment. Both vertical and horizontal alignment must be carefully maintained.

LUBRICATION

Centrifugal bearings may be lubricated with either oil or grease. They must not be over lubricated. Excess

greasing may destroy the grease seals; too much oil will make the bearings run hot. Grease does not become

contaminated as oil and can last as long as a year. Oil should be kept clean and changed on schedule. Weither type of lubrication, feeling the outside of the bearing housing periodically may prevent serious dama

Pump bearings can operate at temperatures up to 160F (70C). Any temperature above this and the pump is

hot to be touched by hand for longer than a few seconds. A sudden temperature rise may indicate that a bear

is beginning to fail. If the bearing is replaced before it fails completely, damage to the impeller, shaft and casmay be prevented.

STUFFING BOX

When the packing and shaft are cooled the stuffing box should drip a little.

DRILLING FLUID PROCESSING

In this Topic the ways in which drilling fluid can be treated), and details ofbasic methods of removing sofrom it, are considered

3.4.1 DRILLING FLUID TREATMENT

There are two basic ways of treating liquid drilling fluids.

adding or removing solids or their equivalent

adding chemicals

ADDING SOLIDS OR THEIR EQUIVALENT

This can occur in several ways, including:

the addition of commercial colloidal and soluble solids for specific controls, i.e. to increase yield poand gel strength. They may also be added to decrease filtration rate with minimum density increase

the addition of oil to a water base drilling fluid. The oil emulsifies and the effect of the oil dropletsmuch like that of a colloid. The same is true of the water fraction of a continuous oil-phase drilling flu

the addition of weighting materials

ADDING CHEMICALS

This is known as 'drilling fluid treating'. Specific chemicals are added to counteract the undesirable effects

drilled solids in the drilling fiuid. They are also added to optimise its physical properties. The chemicals actthe colloidal particles, including hydratable shales, and not on the larger inert particles.

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3.4.2 SOLIDS REMOVAL TECHNIQUES

There are two basic solids removal techniques.

settling, where size and density are both important factors

screening, where size of the particle is the important factor

SETTLING

Settling is a process by which the denser particles are separated from a mixture by gravity or the application

some other force. It is an essential part of separation processes in centrifuges and hydrocyclones as describedthe following Topic. Settling due to gravity can occur in the hole or in drilling fluid tanks.

Stoke's Law

The settling or terminal velocity of solid spheres in liquid can be calculated from Stoke's Law according to following expression:

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SCREENING

The term "screening" refers to the separation of particles by passing the drilling fluid over a wire mesh. T

holes in the mesh allow part of the mixture to pass through but particles larger than the holes are kept back.

Screens vary in size and examples are given in the following table

Table 3.3.4 :Examples of Shaker and test screen sizes

The drilling fluid system

The maintenance of the required drillingfluid properties is one of the most important factors contributing

trouble free drilling and effective well control. The functions of the drilling fluid treatment equipment odrilling rig are;

to prepare drilling fluid, or make additional fluid, as required

to treat the circulating drilling fluid and maintain properties as required

to enable the drillingfluid density to be increased quickly during kick control

to separate solids from the fluid returns

to separate gas from the liquid returns

This Topic covers, in turn;

the general arrangement of the drilling fluid system

the mixing equipment

the solids removal equipment

the unitised solids control equipment

the barytes recovery equipment

the gas removal equipment

3.5.1 GENERAL ARRANGEMENT

Figure 3.3.34gives a general layout of a drilling fluid treating system; the diagrams in Figures 3.3.36 and 3.3

depict the flow pattern of the drilling fluid through the different components of the treating equipment through the well.

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To ensure an uninterrupted operation it is essential that the tank capacity is sufficient. The active drilling fl

tanks on a standard rig should have a capacity of approximately 160 m3 (1,000 bbls) and a similar volume

reserve fluid should be available in storage tanks. Some tanks are divided into compartments.

A trip tank (Figure 3.3.35) is usually installed and connected to the flow line. It is used for volumemeasurement during tripping, to monitor the quantity of fluid used to replace the steel removed from the w

and vice versa.

The accuracy of the measurements depends on the correct calibration of the level indicator and on the f

movement of the float and transmitting wire.

3.5.2 DRILLING FLUID MIXING EQUIPMENT

Low-pressure high-volume mixing systems are preferred for mixing drilling fluid. It is necessary to be ablemix/treat large volumes in the shortest possible time. A low pressure system is selected for this purpose.

Large diameter piping (150 - 200 mm or 6" - 8") is used in combination with fluid velocities of 3 m/s or 10

to keep pressure losses to a minimum.

HOPPERS

Hoppers are used to mix the additives from bulk storage or sacks into the liquid system. They consist ofunnel, butterfly valve, vacuum chamber, jet nozzle and a venturi as shown below.

A 6 x 8" centrifugal pump with output of 5.3 - 6 m3/min (1,400 - 1,600 gpm) at 280 - 420 kPa (40 - 60 pcirculates the drilling fluid through the hopper. Its velocity is increased by using jet nozzles. This velocity w

create an under pressure in the vacuum chamber so that the chemicals in the funnel are sucked in via the con

valve. The turbulent jet flow will mix these additives with the liquid to form one homogeneous flow.

The velocity of the drilling fluid is reduced in the expanding tube or venturi and the pressure rises again (kin

energy is converted to potential energy) when the liquid is moved, at a lower speed, to a tank. The buttevalve controls the quantity of additive - otherwise the chemicals would fall, unchecked into the vacu

chamber. This would result in a plugged hopper, overtreatment or incomplete dispersion resulting in a waste

product.

Critical points for correct operation are

that:

the hopper nozzle is the correct

size and not washed out. the size of the venturi tube is

correct.

the butterfly valve operation issmooth.

the lifting head is not

excessive.

Figure 3.3.38 : Hopper

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BULK STORAGE TANKS

Bulk storage tanks or bins can be vertical or horizontal pressure vessels and are used to store cement, benton

or barytes. The vessel is charged with compressed air and is controlled by an assembly of valves.

The powdered product is fed into the vessel, through a special fill valve or line. The vessel is then closed

from the atmosphere and dry air is introduced through an aeration system resulting in an air-solids mixture.the vessel reaches operating pressure (usually 250 - 280 kPa or 35 - 40 psi), the aerated powder is forced ithe conveyor line which brings it to the hopper. Some bulk storage systems have load cells in the tank supp

to measure the quantity of material in them.

Pressure vessels are usually skid mounted and can be part of the drilling unit or can be supplied as individ

items as required.

Air from the compressors must pass through dryers; moisture in the system is disastrous because the b

material may clog and plug the lines at restrictions. Condensation on tank walls or wet piping may result ilayer of hard material being formed. For this reason tanks are often supplied with heaters and hose and pip

have to be blown dry before use..

The operation of a pressure bulk storage vessel is shown in Figure 3.3.39.

AGITATORS

Mixing systems are needed to keep the drilling fluidin the tanks moving to ensure uniform quality andprevent solids from settling.

Paddle stirrers (paddle mixers), mud guns and

bottom jets are used for this purpose. Theequipment should be checked for properfunctioning during operations and inspected for wear and/or erosion during rig moves

3.5.3 SOLIDS REMOVAL EQUIPMENT

An adequate solids removal system should be designed to process drilling uid at the highest probable drill

rates to ensure the correct density and quality under all conditions. This contributes to the best drilling r

good hole conditions, and safe well control. Several treatment techniques are available to control (reduce) volume and/or the size distribution of the solids:

Dilution will reduce the percentage of all types and sizes of solids per unit of volume. But since onlcertain fraction of the solids have to be removed, it is usually cheaper to remove them mechanically.

Mechanical removal can be subdivided into screening and gravity separation.

Equipment used is: shale shaker. clay ball trap.

sand trap. hydrocyclones.

mud cleaners. centrifuge.

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THE CORRECT DESIGN OF THE SOLIDS REMOVAL SYSTEM

In order to be fully effective the various pieces of equipment must be properly integrated into the solids remo

system, taking the following points into account:

To totally process the drilling fluid from the hole, any processing unit must discharge intocompartment downstream from its own suction compartment. This point is dealt with further un

"desanders & desilters".

If two different type units are operated in parallel (taking suction from a common pit and discharginga common pit), neither unit can process the total drilling fluid, regardless of the capacity of either unit

If a drilling fluid system is designed with unnecessary options and complexities (so that the first pit

last pit are completely interchangeable, for instance), the processing equipment will seldom be opera

properly.

If a drilling fluid system does not have enough compartments to prevent paralleling of processing u

that must be run simultaneously, the equipment will never function properly.

Apart from the first three items listed above, solids removal equipment requires a gas-free liquid feed

SUMMARY OF SOLIDS CONTROL EQUIPMENT

The shale shaker and sand trap remove coarse particles in the range of 1,540 - 200 microns and in

sand trap particles down to 74 microns.

The desander removes abrasive drilled solids down to 150 microns.

The desilter removes drilled solids and barytes. It separates mainly in the range of -44 - 1,000 micr

for drilled solids and greater than 30m microns for barytes. Desilters are mainly used continuously

unweighted drilling fluid. In weighted fluid the desilter is not used, because too much barytesexpelled, making the addition of new barytes necessary (unless the underflow is run through

centrifuge and the recovered barytes returned to the system).

The centrifuge separates out particles with a cut-off of 3 microns.

SHALE SHAKER Figure 3.3.41 :Principle of the shale shaker

A shale shaker or vibration screen is a spring

mounted screen which is vibrated by the rotation of

an eccentric shaft mounted on top of the screen frame(Figure 3.3.41).

Screens

The shale shaker is the first mechanical treatment ofthe returning drilling fluid for solids control. None of

the other mechanical devices can cope with solids

control without the pre-treatment of the fluid in theshale shaker.

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The volume of fluid that can be processed over the screen depends on :

the size of the openings in the wire screen(s).

the percentage of open area.

the speed and amplitude of the vibrations.

the type of motion (vibrator position).

its fluid flow properties. the type, size and amount of solids.

The rate of solids discharge depends on :

the type of motion.

the speed and amplitude of vibration.

the mesh design.

the screen strength.

The main function of the screen, to filter out the cutting particles above a certain size, is achieved by the scr

openings which must have a specific size. These openings, referred to as the mesh of the screen, can be squor rectangular. A screen is defined by the number of holes per inch, measured along the wire cross.

The API RP 13E designation for screen cloth gives both the mesh count and the percentage of open area, i.e.:

Mesh x mesh (micron size x micron size, percent open area)

e.g. 30 x 30 (516 x 516, 37.1)

70 x 30 (178 x 660, 40.3).

The rectangular mesh is called "oblong" mesh screen. Its removal size is somewhere between the two msizes. A 70 x 30 mesh performs like a 50 mesh screen. Because of the use of different sizes of wire (length-wand cross-wise) in an oblong screen the advantages of the oblong screen are that it is stronger than an equiva

square screen and that it will have a higher open area percentage than a square screen and therefore a hig

capacity.

Modern shale shakers have double-deck screen arrangement. The coarse screen should be run above the

screen. Selection of the screen should normally be so that during operation 2/3 of the screen area is wet, 1/3dry, though this can vary dependent on the mud and shaker types. Note that each deck should have the sa

size screen over its whole area.

Shale shakers are the primary solids control units for removing drilled solids. When drilling with unweighdrilling fluid there is no theoretical lower limitation to screen size. With weighted fluids a screen of 200 m

will remove some of the coarse barytes.

All the fluid returned from the hole has to be screened, so the required capacity should be set at greater than maximum pump capacity in order to allow for all the returns to pass over the shakers. Usually 150% of

maximum pump capacity is considered adequate.

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Correct design of the flow distribution to the shakers is very important so that each shaker installed can scr

its fair proportion of the mud returns. Be aware that whole mud losses may occur when initially circulating c

muds over fine screens. Either bring up circulation gradually or fine down shaker screens gradually.

Early removal of solids

There are both advantages and disadvantages in the early removal of the majority of solids.

The advantages include:

minimisation of recirculation of cuttings down hole

prevention of overloading of the cyclones

prevention of generation of fines which can not be removed by cyclones

elimination of bit bottom fill

The disadvantages include the loss of fluid if the screen mesh is too fine. This is particularly important wdrilling in the top part of the hole where large volumes of fluid are circulated

Types of shale shakers

Three major types of shale shakers are used.

single deck shakers

differential single deck shakers

double and multiple screen shakers.

Single deck shakers

A single deck shaker is shown in section inFigure 3.3.42. In the past the majority of shakers in use were of type. They had

fairly coarse screens. This meant that only the coarser formation particles (cuttings and cavings and coasand) could be removed, whereas the finer sand and silt remained in the drilling fluid. The other problem w

this type of screen was its low efficiency.

Fig 3.3.42 : Schematic diagram of a single-deck shaker Fig 3.3.43 :Schematic form of a differential single-deck shaker

Differential single deck shakers

The construction of the differential single-deck shaker is shown in Figure 3.3.43. The screens are said to b"parallel" and the angle of the screen slope varies.

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Double and multiple screen shakers

Most modern drilling units now have double deck shakers fitted. These have a second, finer screen in "ser

which removes the majority of the finer particles (see Figure 3.3.44). The size of the second screen can be up

150 mesh (104 m).

Multiple screen shakers have a single-deck construction with three or four screens placed at different levels i"series" arrangement. This type of arrangement is illustrated in Figure 3.3.44.

Characteristics of shale shakers Figure 3.3.44 :Double and three-screen multiple-screen shakers

Shale shakers are characterised in three ways.

amplitude and speed

motion types

slope

Amplitude and speed

The amplitude, or one half of a stroke, of a shaker is determined by the vibrator eccentric weight. Norma

shakers use low amplitudes and high vibrator speeds. Fine screen shakers have high amplitudes at lower speto prevent plugging of the screens. Speed of vibration is important to ensure efcient removal of cuttings fr

the screen. Shale shakers are now available with variable speed control.

Motion types

Unbalanced motion occurs when the vibrator is mounted in the centre above the screen. Motion is created in

form of an ellipse at the feed and discharge, and is circular underneath the vibrator. In this mode of operat

the cuttings build up at the discharge end and to dispose of them the screen must slope towards the sodischarge end. However, sloping the deck may increase the risk of expensive loss of uid.

A balanced screen, in contrast, (e.g.

The Thule VSM 120) has the vibratormounted at the centre of gravity. This

gives a circular motion at all positions

of the screen. An even discharge of thecuttings is obtained with this motion.

The effects of unbalanced and

balanced motion are shown in Figures3.3.45 and 3.3.46.

Figure 3.3.45 :Use of Slope with unbalanced

motion to overcome the solids pile-up

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The direction of motion should be in the direction of flow, otherwise the screening action will be v

inefficient. Reversed rotation is often caused by hooking up the electric motors incorrectly.

Most modem shakers use linear motion. Linear motion shakers (e.g. Thule VSM 100) have the vibr

mounted at the front of the basket through the centre of gravity. Linear motion is achieved by using two counrotating vibrators/shafts which, because of

their positioning and vibration dynamics, willnaturally operate in phase. They are located sothat a line drawn from the shakers centre of

gravity bisects at 90 a line drawn between the

two axes of rotation. This gives a saw tooth

type motion allowing longer residence time onthe screen and increased throughput compared

to unbalanced and balanced motion type

shakers. Figure 3.3.46 :Balanced motion yields even solids flow irrespective of deck angle

CLAY BALL TRAP

Agglomerations of clay cuttings often appear in the form of clay balls when drilling in "gumbo" shale ar

These can cause problems by plugging the fluid return line between the well and the shale shaker, and if treach the shaker they can interfere with its operation.

When clay balls are likely, home-made clay ball traps are sometimes used. Current methods include following:

welding a device around the top of the stove pipe where the clay balls can be removed by hand befentering and plugging the flow line.

equipping the shale shakers with perforated plates where the fluid enters the screening area; the c

balls caught in this way can be removed manually or by water spray.

SAND TRAP

A sand trap is a tank compartment underneath the shale

shaker. This tank is not agitated, thus allowing the larger

solid particles to settle. The shape of the tank (see Figure3.3.47) is such that settled solids can easily be dumped into

the waste pit because the tank is tapered towards a large

door.

This type of separation is called gravity separation and theparticle settling is governed by Stokes' law.

The sand trap receives the fluid passing through the shaleshaker. It should also receive all fluid by-passing the shale

shaker and going to the active tanks. Figure 3.3.47 : Sand trap

Sand traps are also known as "shale traps" or "settling tanks". They are necessary only as a back up to sh

shakers. Back up is required because:

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shaker screens are not always adequate.

shaker screens sometimes develop tears through which oversize solids pass.

shakers sometimes have to be bypassed during drilling (for instance after lost circulation material been added).

Certain points should be noted about the operation of sand traps.

the sand trap is a gravity settling compartment and must not be stirred or used as a suction compartme

whole drilling fluid losses must be minimised by having a discharge control easily and quickly ope

and closed.

the sand trap should only be dumped, not "washed out". If the bottom is not sloped to the solids pangle, the settled solids should be left to form their own sloped sides; "cleaning the bottom", other t

possibly at moving time, serves no purpose but increases the loss of drilling fluid and hence its cost.

since Stoke's Law applies in a sand trap, large quantities of barytes (as well as sand) may be settled fr

weighted drilling fluids; provision for bypassing the undersize screen discharge slurry from the carrypan direct to the next processing compartment is also advisable. As all compartments except the s

trap are stirred in well-designed active systems, this will prevent settling out of barytes. The sand t

must not be by-passed if there is a problem with any other solids removal apparatus. the fluid exit from the sand trap should be over a retaining weir to a stirred compartment.

The sand trap must be dumped frequently to ensure that the fluid velocity will remain adequately l

Sand traps can not however be dumped when using oil- based or pseudo oil based drilling fluids

. Exercise extreme care if considering by-passing the shakers. Drilling a rubber cement plug with the shakers by-passedcan result in the backloading/dumping of the whole active drilling fluid system. Do not leave the shakers by-passed when

drilling as this can quickly lead to a disastrous build up of drilled solids in the circulating system.

If settling of barytes is a problem, the drilling fluid should be treated to suspend the barytes more efficieneither by increasing the gel strength or by circulating and conditioning the mud to maintain the barytes in

appropriate wetted state. If settling of barytes has been caused by contamination circulate and condition the mby the appropriate treament to re-wetthe barytes..

Gravity separation also takes place inhydrocyclones and centrifuges but in a

different fashion.

DECANTING CENTRIFUGES

Operating principles

Figure 3.3.54 shows a sectional viewof a decanting centrifuge equipped

with a conical bowl rotating typically

at 1600 rpm.

Figure 3.3.54 : Operation of a decanting centrifuge

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The operating principles are as follows:

the drilling fluid/liquid is fed through a pipe in the hollow shaft into the centre of the bowl.

water is simultaneously pumped through a small pipe inside the drilling fluid feed pipe and sprayed i

the next segment of the bowl for dilution and better ultimate separation.

the separated solids (barytes, etc.) are scraped towards the discharge openings at the small diameter

of the bowl by a screen-type conveyor which rotates at a slightly slower speed than the bowl, concentrated material can then be returned to the drilling fluid.

the low-density fluid containing clay and chemicals is discarded, to waste, at the other end.

General

The decanting centrifuge, as illustrated in the cross-sectional view shown in Figure 3.3.55, can have two uses

To save fines in weighted drilling fluid.

To save fluid phase in unweighted drilling fluid.

The creation of high gravity forces of 800 to 1000 times g, laminar flow, and long retention time in the machhelp to make this type of unit very efficient. It is capable of making a sharp cut at about 2 - 5 microdepending on the specific gravity of the fluid solids, that is, particles larger than 2 - 5 microns are separated i

one stream and those smaller than 2 - 5 microns into another.

The particle size cut is lower than for cyclones and the "underflow" solids can be highly concentrated beca

of the scraping conveyor. Separation takes place inside the bowl that is rotated at speeds ranging from 1000

1500 rpm. Inside the bowl there is a conveyor that rotates in the same direction but at slightly lower speed (150 rpm less).

The larger, heavier solids will settle on the wall and be scraped to the tapered end of the bowl where they

ejected. The solids contain adsorbed liquid only. The liquid overflow contains dissolved and colloidal partic(up to 3 micron).

Full-flow centrifuging would be very costly. The capacity used in drilling applications ranges from 5 - 10 %

full flow

Figure 3.3.55 : Typical solids decanter centrifuge

Oil based drilling fluids

With weighted oil based fluids the removalof sand and silt is not efficient. The aid of a

centrifuge may be useful to treat the

desander/desilter/mud cleaner underflow.With this, part of the drilled solids are

removed which will help to prevent oily

wastes and, consequently, pollution.

With low density oil based fluids drilled solids can be removed quite efficiently, and the fluid canreconditioned in a central plant.

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Note that for water base drilling fluids the centrifuge feed is normally diluted with water. In oil based fluids t

dilution can be replaced by heating the feed.

UNWEIGHTED DRILLING FLUIDS

With unweighted fluids using the centrifuge can be very cost-effective. It reduces substantially the volume

liquid drilling fluid discarded with the drilled solids, which are removed in almost dry form, particularly wthe desander underflow is also passed via the mud cleaner screen. Consequently the chemical consumptionreduced, and it is also easier to maintain the drilling fluid properties. This setup is ideal for low solids fl

drilling.

The following flow chart shows how the equipment is set up, terminating in the decanting centrifuge.

Double deck shaker: The screen size of this unit is varied to suit the hole size and depth.

then

Desander: Cones vary from 2 x 254 mm (10") to 4 x 508 mm (20").

then

Silt separator set (Mud

cleaner):

This consists of 3 units, each using 8 x 101.6 mm (4") cyclones over a

150, 200 or 325 mesh screen.

then

Centrifuge: The remainder of the unwanted solids are removed here

WEIGHTED DRILLING FLUIDS

With weighted fluids a barytes recovery efficiency of 90-95% is normal. The capacity of most commer

centrifuges is of the order of 0.1-0.4 m3/min (30-100 gpm). These limits should be more than sufficient for

needs in normal drilling.

The centrifuge is able to separate clay from the main fluid stream by dumping liquid. However, this liquid a

contains some silt, chemicals, lubricants, etc. Since the particle size distributions of barytes and silt are vsimilar the separation efficiency will be very low. Most of the silt will be following the path of the bary

Despite this problem, the centrifuges have proved to be capable of recovering so much barytes while keep

the flow properties of the drilling fluid under control that it is an economical proposition to use them.

Centrifuges can also be used for recovering barytes from waste drilling fluids returned from drilling location

a central plant. The barytes recovered with the centrifuge is mixed into a fresh bentonite suspension to proda fresh weighted drilling fluid which is comparatively free of sand and silt.

DESANDERS & DESILTERS

Operating principles

Desanders and desilters are special cases of hydrocyclones.

Hydrocyclones operate according to the principle of the centrifuge. They are cylindrical/conically shap

relatively small vessels in which centrifugal forces are created by injecting the fluid tangentially at high sp

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as shown in Figure 3.3.48a. These forces result in a high (radial) speed of settling of the denser material (so

or heavy liquids) and exaggerates the differences in settling speed of different size particles of the same dens

This allows the different size particles to be separated from each other. In particular sand, silt and clay canseparated. The denser/larger material is driven preferentially outward towards the conical wall and downw

into an accelerating spiral (conservation of angular momentum) along the wall to the discharge point at the a

of the cone. The lighter-phase material moves inwardly and upwardly as a spiralling vortex to the light-ph

discharge connection of the cyclone.

Vessel geometry, the design and positioning of various connections, and their relative dimensions are crit

for efficient cyclone operation and determine the cut-off point (equivalent spherical diameter - see Topic 3

between the solids ejected from the apex and those remaining in the liquid discharge.

Figure 3.3.48b shows the construction of a typical hydrocyclone. A number of equations have been develo

for their design but the optimum is invariably

reached by empirical work.

The size of the particles that can be separated

depends on:

size of the cyclone.

split ratio underflow/overflow.

inlet header pressure

The efficiency of the cyclones depends on the

following factors:

the cyclone design

the rheological properties of the fluid

the range of sizes of the solids to beremoved

operating pressure

Figure 3.3.48 :Principle and construction of a hydrocyclone

Application

Hydrocyclones are used to remove sand and silt particles from the drilling fluid that has already passed the shshaker. Their advantages are that they:

remove fine drill solids

are relatively simple in design

have no moving parts

are easy to operate

have a large capacity

Figure 3.3.49 A desander

When treating the drilling fluid to remove a specific size range 100% of the fluid stream must be process

because particles not removed the first time are circulated back down the hole again. Not only do they t

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increase the erosion of the pipe and open hole, they themselves are subject to abrasion and regrinding under

bit. The particles may then become too fine to be easily removed on their return to the surface. A build up

solids in the drilling fluid results.

Given that the complete fluid stream must be processed the hydrocyclone capacity for each treatment shouldin excess of the maximum pump volume of the rig pumps. And since the size, and thus capacity, of

hydrocyclone is in practice fixed by the size of particle it is designed to remove, the only way to achieve required processing capacity is to increase the number units working in parallel. A 6" cone can procapproximately 2.5 bbls/min (380 l/min) and a 4" cone 11.25 bbls/min (190 l/min).

A battery of 6" to 12" hydrocyclones working in parallel as shown in Figure 3.3.49, is thus used to remove sand is known as a desander. A desilter is a similar battery of 2" to 4" units. In each case the number of unit

the battery depends on the maximum expected circulating rate in the well.

Performance

The performance characteristics of hydrocyclone cones are

shown in Table 3.3.5.

Table 3.3.5 : Hydrocyclone performance

Experience shows that the best desanders (150 mm or 6") will remove almost 100% of particles greater thanm and the best desilters 100% of particles greater than 50 m. The median cut of these units would be >

m for desanders and > 15 m for desilters .

Barytes particles, because of the higher s.g. (4.2) and hence higher equivalent spherical diameter ratio (1.5) w

always be removed more effectively than sand and silt. For this reason hydrocyclones can only be used for

desanding and desilting of unweighted drilling fluids. If the fluid is weighted with barytes there will

excessive loss of valuable densifying material. Figure 3.3.50 Pressure drop nomogram for different hydrocyclone sizes

Pressure operating range

The smaller the diameter of the

cyclone, the higher is the operatingpressure and the smaller the particles

that can be removed.

The practical pressure operating range

for hydrocyclones is 200-350 kPa (30-

50 psi) with the smaller desiltersrunning at a higher pressure than the

desanders. The normal pressure drop

for each diameter size is shown inFigure 3.3.50.

Too low a pressure results ininefficient separation; too high a

pressure will give a better separation but the bladders will wear too rapidly.

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The underflow

When in use the underflow of the cyclones should be discharged as a spray. This indicates that the cones

operating at maximum efficiency. If discharge from the cone forms a solid stream of liquid heavily laden w

solids it is said that the cone is "roping" and the aperture in the apex must be adjusted by opening it furtherrope-type discharge indicates the cyclone is overloaded; separation will be inefficient and rig pump wear will

excessive. Figure 3.3.51: Types of discharge

Once the correct "spray" discharge is obtained the amount of

underflow can also be regulated by opening/closing the apex. An

underflow rate of some 3 % of throughput is required to avoidbottom plugging. Another reason for a minimum of 3 % underflow

is that, at lower rates, the size of particles that will be removed is

unfavourably affected, as too much solid will remain in the fluid.

The installation of desanders/desilters Table 3.3.6 : Operating problems

The desanders and desilters must be installedcorrectly, following the guidelines enumerated

earlier in this Topic. To repeat the critical point,each solids removal unit must process at least

100% of the flow from the well. There is onlyone correct way to install the equipment,depending on what is available; all other

installations will clean less effectively.

Figure 3.3.52 shows the right and wrong ways

of installing a single desander or desilter unit,

the same unit combined with a degasser or a mixing hopper, and a desander plus a desilter. The efficiencyeach arrangement is calculated, i.e. the fraction of the fluid flow that is treated.

Problems with hydrocyclones

The following problems may be encountered when using hydrocyclones;

the centrifugal pump and cyclone operate with entrapped air; this is sometimes caused by air be

sucked in via vortexes in the suction tank if its level is low; the suction tank requires at least a 1.5 mft) fluid column above the suction of the pump.

the apexes become plugged with solids, chemicals, etc.; this can usually be avoided with screens on

centrifugal pump suction.

uneven feed distribution in multi-cone sets.

irregular operation due to faulty manifolding; each cyclone unit should have its own pump and,

example, not be part of the hopper system; each pump should be dedicated to only one task.

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The following symbols are used in these examples:

Case 1:

Single stage, desilting or desanding;R = 400; D = 500; a minimum of two

compartments are required.

Percentage of mud from hole desilted

or desanded

1a. Correct ==125%

1b. Incorrect =

= = 55.6%

1c. Incorrect = = 55.6% Figure 3.3.52 :Correct installing of desanders/desilters

Case 2:

Single stage, desilting or desandingcombined with another process

(degassing, drilling fluid hopper

operation, etc); R = 400; D = 500;

DGM = 500; a minimum of threecompartments are required.


or desanded

2a. Correct = =

125%

2b. Incorrect

50%

2c. Incorrect = = 55.6%

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Percentage of mud from hole degassed

2a. Correct = = 125%

2b. Incorrect = 50%

2c. Incorrect = 55.6%

Case 3:

Two-stage desanding and desilting; R = 400; DA = 500; DI = 500; a minimum of three compartments required (except in 3c).

Percentage of mud from hole desanded

3a. Correct = 125%

3b. Incorrect = 55.6%

3c. Incorrect = 250%


3a. Correct = 125%

3b. Incorrect = 125%

3c. Incorrect = 50%

MUD CLEANERS

The mud cleaner consists of a battery of 101.6 mm (4") desilters, mountedover a fine screen shaker. The original reason for its introduction was toseparate and save barytes in weighted muds. However, they are now also

used for low solids muds and oil muds.

With weighted muds, the drilled solids can be removed by selecting thecorrect screen (200 mesh). However, this screen can never remove the silt,

which has the same particle size range as the barytes. Figure 3.3.53 : Mud cleaner

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With low solids drilling fluids, especially in areas where fluid and cutting disposal present a problem, the m

cleaner is useful in combination with a centrifuge for reducing the volume of liquid waste.

With oil based fluids, desanders and desilters alone are generally inefficient. The liquid lost via the underf

has often resulted in pollution and disposal problems. Under these circumstances a mud cleaner can helpremove drilled solids. The liquid can either be returned to the main stream or passed through a centrifug

necessary. The oil is then saved and the material to be disposed of is in dry form.

Mud cleaners are very inefficient and the need for their use has been replaced by the advent of linear mot

shakers combined with the use of centrifuges.

3.5.4 UNITISED SOLIDS CONTROL EQUIPMENT

It is common, particularly in offshore operations, to have all drilling fluid solids control equipment, pippumps and tanks mounted as an

integrated unit. This system is referred

to as "unitised solids control". The

complete assembled weight of such aunit is of the order of 25 tonnes.

The unitised solids control unit is

usually hooked up before drilling

commences and picked up and movedashore for complete overhaul after

completion of drilling operations. Figure 3.3.56 :Schematic diagram of a solids control package for drilling fluid

A schematic diagram of a typical solids control package is shown in Figure 3.3.56.

In Figures 3.3.57 and 3.3.58 examples are given of actual arrangements, using unitised solids control, forunweighted drilling fluidand a weighted one. The pressures shown on Figure 3.3.57 are the operating pressu

of the cyclones, see Figure 3.3.50. Table 3.3.7 :Required capacities per 3800 litres/min (1000 gpm) pump rate

The main difference between the two

systems is that for the weighted

drilling fluid a mud cleaner (i.e. adesilter over a fine screen shaker) and

a second centrifuge are in use for

separating out the barytes. With theunweighted fluid two systems of

desanders are in use. If the desanderswere used with the weighted fluid

there would be excessive loss ofbarytes.

Experience has shown that the

capacity of various components in the package has tended to be too low, especially when drilling in top h

Table 3.3.7 indicates the order of magnitude of the capacities required.

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CENTRIFUGES

Centrifuges were originally introduced for the recovery of barytes. When drilling with weighted drilling flu

through thick shale layers, where the shales have a tendency to disintegrate and disperse in the fluid,

viscosity will increase sharply. Up to a certain point thinning chemicals can control this viscosity, but when much clay has been absorbed, this system ceases to work. The two alternative solutions are then watering b

and mechanical control.

Watering back: Water and barytes are added to the drilling fluid simultaneously in order to lower

clay content while maintaining the density. However, this causes a large increase in fluid volume

large quantities have to be dumped. Clearly this is costly, especially as the dumped fluid contabarytes at its operating concentration.

Mechanical control: Here either a centrifuge, or so-called clay-jector, is used to recover barytes

dispose of unwanted drilled solids.

The centrifuge will recover the barytes and return it to the fluid stream. At some time water has to be supp

to maintain the original fluid density. The drilled solids (clay with a small proportion of silt) are dumped in

waste pit by the centrifuge. The centrifuge does not operate continuously and can only handle a small part oftotal fluid stream. Otherwise the properties of the fluid become too disturbed

If two centrifuges are available they can be hooked up to operate in either series or parallel mode. The mod

approach is to use two or three centrifuges capable of being operated in either mode. In unweighted muds centrifuges are operated in parallel mode to remove fine drilled solids. It may also be economic to operatethis mode with weighted fluids beIow 135 SG to control LGS build up. At densities above 135 SG

centrifuges are operated in series to recover barytes (first centrifuge) and remove fine drilled solids (

centrifuge).

BARYTES RECOVERY CYCLONES

These provide an alternative approach to the use of special cyclones for the separation of clay/barytes.

example, they were used very successfully in deep-well drilling in Trinidad, where the unit was invariably u

for periods that equalled circulation times, and quite often one cyclone of the four available was sufficientmaintain good fluid properties.

The cyclones used in the barytes recovery units are of the 50.8 mm or 76.2 mm (2" or 3") type; that is, of "desilter" type. A unit may contain up to 4 hydrocyclones. The fluid is fed to the cyclones by a pump, wh

diluting water is supplied by another pump via a mixing valve. The volume of water is controlled by a "f

rater". The capacity of a typical unit is in the range of 70 litres/min undiluted fluid.

The operating limits of barytes recovery cyclones are as follows.

the separating efficiency depends on the amount of dilution and for normal operation rather la

volumes of water are required (about 5 times the quantity required for a centrifuge); this means thatample water supply is an absolute necessity.

excess treatment time/volume will result in low viscosities, followed by barytes settling; part of the cl

and chemicals is also disposed of. It is therefore good practice to add these products in the coursetreatment.

sand and silt are returned with the barytes to the fluid; this will lead to a high drilled solids content.

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Most of these conditions are met in the degasser:

Low pressure: A vacuum pump keeps a vacuum of at least 2" (50 mm) of mercury with a maximum

25" (640 mm). The vacuum pump is protected against liquid entry by an automatic regulating va

which will shut off the liquid.

High temperature: This factor is not controlled and the temperature will be that of the fluid as it en

the unit. Movement of the liquid: A jet pump (jet nozzle and vacuum chamber) in the discharge will cause

fluid to flow through the degasser.

Large contact area: the large contact area between liquid and vacuum is created as the fluid has to fl

over a corrugated baffle inside the vessel (see Figure 3.3.60)

Two points to note are that:

the fluid flow to the jet nozzle should be adjusted to pull at least as much fluid through the degasser a

being circulated. This is to prevent overflow from the mud/gas separator tank into the active system.

the capacity of the degasser is directly related to the jet pump pressure and jet pump flow rate. T

higher the density of the drilling fluid the higher the supply pressure and the flow rate of the jet puwill have to be.

The following Table indicates some of the problems that can occur with a vacuum degasser, along with

causes/solutions.

Symptom Cause/Remedy

Output too low

Increase pressure on jet pump

Partially or fully plugged jet nozzle

Suction inlet covered by sand or plugged

Mud after degasser is

air/gas cut Leaks in jet pump/vacuum chamber

Output too high

Reduce mud flow to jet nozzle

Throttle butterfly valve

Check vacuum pump by closing valve 5 (vacuumshould be above 28" Hg)

Check all valves and pipe connections. for leakage

Drain automatic liquid shut-off

Check condition of the jet nozzle

Check whether the degasser is clogged with drymud

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3.3.5 TROUBLE SHOOTING

Table 3.3.3 is a troubleshooting guide and a start-up checklist for use with centrifugal pumps.

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