Drilling Fluid Circulation Systems

Drilling Engineering 1 Course3rd Ed. , 3rd Experience

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1. Drilling Fluid Circulation SystemA. IntroductionB. Mud Pumps

a. Duplex PDP & Triplex PDPC. Solids removalD. Solid Control Equipment

a. Shale shakersb. Degasserc. Mud Cleaners

E. Treatment and Mixing Equipment

drilling fluid rolesThe drilling fluid plays several functions in the

drilling process. The most important are:clean the rock fragments from beneath the bit and

carry them to surface,exert sufficient hydrostatic pressure

against the formation to prevent formation fluids from flowing into the well,maintain stability of the borehole walls,cool and lubricate the drillstring and bit.

Fall 14 H. AlamiNia Drilling Engineering 1 Course (3rd Ed.) 4

Drilling fluid circulationDrilling fluid is forced to circulate in the hole at various pressures and flow rates.

Drilling fluid is stored in steel tanks located beside the rig. Powerful pumps force the drilling fluid

through surface high pressure connections to a set of valves called pump manifold, located at the derrick floor.


Drilling fluid circulation (Cont.)From the manifold,

the fluid goes up the rig within a pipe called standpipe to approximately 1/3 of the height of the mast. From there the drilling fluid flows through a flexible

high pressure hose to the top of the drillstring.The flexible hose allows the fluid

to flow continuously as the drillstring moves up and down during normal drilling operations.


swivelThe fluid enters in the

drillstring through a special piece of equipment called swivel located at the top of the kelly. The swivel permits rotating the

drillstring while the fluid is pumped through the drillstring.

A swivel


drilling fluid in wellboreIn wellbore The drilling fluid then flows down

the rotating drillstring and jets out through nozzles in the drill bit at the bottom of the hole. The drilling fluid picks the rock cuttings

generated by the drill bit action on the formation. The drilling fluid then

flows up the borehole through the annular space between the rotating drillstring and borehole wall.


drilling fluid at surfaceAt surfaceAt the top of the well (and above the tank level),

the drilling fluid flows through the flow line to a series of screens called the shale shaker. The shale shaker is designed to

separate the cuttings from the drilling mud. Other devices are also used to clean the drilling fluid

before it flows back into the drilling fluid pits.


Process of mud circulationThe principal

components of the mud circulation system are:pits or tanks,pumps,flow line,solids and contaminants

removal equipment,treatment and mixing

equipment,surface piping and valves,the drillstring.

Rig circulation system


The tanksThe tanks

(3 or 4 – settling tank, mixing tank(s), suction tank) are made of steel sheet. They contain a safe excess (neither to big nor to small)

of the total volume of the borehole. In the case of loss of circulation,

this excess will provide the well with drilling fluid while the corrective measures are taken.

The number of active tanks depends on the current depth of the hole

(bypasses allow to isolate one or more tanks.) The tanks will allow enough retaining time so that

much of the solids brought from the hole can be removed from the fluid.


Mixing and suction tanks


MUD HANDLING EQUIPMENTRig sizing must incorporate

mud handling equipment as these equipment determine the speed of drilling and the quality of hole drilled.The equipment includes:Shale Shakers

The type of mud (i.e. oil-based or water-based) determines the type of the shaker required and the motion of the shaker. Deep holes require more than the customary three shakers.


MUD HANDLING EQUIPMENT (Cont.)

Mud PitsThe number and size of pits is

determined by the size and depth of hole.

Other factors include: size of rig and space available, especially on offshore rigs. The size of a mud pit is usually 8-12 ft wide, 20-40 ft long and 6-12 ft high.

Mud degasserCentrifuges and mud cleanersDesanders and desilters


reciprocating positive displacement pumps vs. centrifugal pumpsThe great majority of the pumps

used in drilling operations are reciprocating positive displacement pumps (PDP).

Advantages of the reciprocating PDP when compared to centrifugal pumps are:ability to pump fluids with high abrasive solids contents

and with large solid particles, easy to operate and maintain,sturdy and reliable,ability to operate

in a wide range of pressure and flow rate.


positive displacement pumps compartmentsPDP are composed of two major parts, namely:Power end: receives power from engines and transform the rotating

movement into reciprocating movement.The efficiency Em of the power end,

that is the efficiency with which rotating mechanical power is transformed in reciprocating mechanical power

is of the order of 90%.

Fluid end: converts the reciprocating power into pressure and flow rate.The efficiency Ev of the fluid end

(also called volumetric efficiency), that is, the efficiency that the reciprocating mechanical power is

transformed into hydraulic power, can be as high as 100%.


Pump configurationsRigs normally have two or three PDPs. During drilling of shallow portions of the hole,

when the diameter is large, the two PDPs are connected in parallel to provide the highest flow rate necessary

to clean the borehole.

As the borehole deepens, less flow rate and higher pressure are required. In this case, normally only one PDP is used

while the other is in standby or in preventive maintenance.


Affecting parameters on flow rateThe great flexibility in the pressure and flow rate is obtained with the possibility of

changing the diameters of the pair piston–liner.The flow rate depends on the following

parameters:stroke length LS (normally fixed),liner diameter dL,rod diameter dR (for duplex PDP only),pump speed N (normally given in strokes/minute),volumetric efficiency EV of the pump.

In addition, the pump factor Fp is defined as the total volume displaced by the pump in one stroke.


Types of the positive displacement pumpsThe heart of the circulating system is

the mud pumps. There are two types of PDP: double-action duplex pump, and single-action triplex pump.

Triplex PDPs, due to several advantages, (less bulky, less pressure fluctuation, cheaper to buy and to maintain, etc,) has taking place of the duplex PDPs in both onshore and offshore rigs.


CENTRIFUGAL PUMPS

This type uses an impeller for the movement of fluid rather than a piston reciprocating

inside a cylinder.

Centrifugal pumps are used to supercharge mud pumps and providing fluid to

solids control equipment and mud mixing equipment.


Duplex vs. Triplex pumps

A basic pump consists of a piston (the liner) reciprocating inside a cylinder. A pump is described as single acting if it pumps fluid on the forward stroke (Triplex pumps)

and double acting if it pumps fluid

on both the forward and backward stokes (Duplex).


Duplex pumps

Piston scheme (double action) A duplex unit


Triplex pumps

Piston scheme (single action). A Triplex unit


Pump linersPump liners fit inside the pump

cavity. These affect the pressure rating and

flow rate from the pump. For a given pump, a liner has the

same OD but with different internal; diameters. The smaller liner (small ID) is used in

the deeper part of the well where low flow rate is required but at much higher operating pressure.

The size of the pump is determined by the length of

its stroke and the size of the liner.


the pump factorThe 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:


VOLUMETRIC EFFICIENCY

Drilling mud usually contain little air and is slightly compressible. Hence the piston moves through a shorter stroke than

theoretically possible before reaching discharge pressure. As a result the volumetric efficiency is always less than

one; typically 95% for triplex and 90% for duplex.

In addition due to power losses in drives, the mechanical efficiency of most pumps is about 85%.


Pump Flow RateFor 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 operating pressure

The horse power requirements of the pump depends on the flow rate and the pressure. The operating pressure depends on flow rate, depth and size of hole, size of drillpipe and

drillcollars, mud properties and size of nozzles used.

A full hydraulics program needs to be calculated to determine the pressure requirement of the pump.


Pump PowerPumps convert mechanical power into hydraulic

power. From the definition of power P=FvIn 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 gal/min (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 DampenersDue 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 dampener


aim of the solids removal systemFine 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.

Recall mud is made up of fluid (water, oil or gas) and solids (bentonite, barite etc).

The aim of any efficient solids removal system is to retain the desirable components of the mud system by separating out and discharging

the unwanted drilled solids and contaminants.


Solids in drilling fluids classification: based on specific gravity, (or density) Solids in drilling, classified by specific gravity, may

be divided into two groups:High Gravity Solids (H.G.S.) sg = 4.2 Low Gravity Solids (L.G.S.) sg = 1.6 to 2.9

The solids content of a drilling fluid will be made up of a mixture of high and low gravity solids. High gravity solids (H.G.S) are added to fluids

to increase the density,e.g. barytes, whilst low gravity solids (L.G.S)

enter the mud through drilled cuttings and should be removed by the solids control equipment.


Solids in drilling fluids classification: based on particle sizeMud solids are also classified according

to their size in units called microns (µ). A micron is 0.0000394 in or 0.001 mm.

Particle size is important in drilling muds for the following reasons:The smaller the particle size,

the more pronounced the affect on fluid properties.The smaller the particle size,

the more difficult it is to remove it or control its effects on the fluid.


particle size classification

The API classification of particle sizes is:Particle Size (µ) Classification Sieve Size (mesh)> 2000 Coarse 102000 - 250 Intermediate 60250 - 74 Medium 20074 – 44 Fine 325 44 - 2 Ultra Fine - 2 - 0 Colloidal -


solids control equipment

Solids contaminants and gas entrapped in mud can be removed from mud in four stages: Screen separation:

shale shakers, scalper screens and mud cleaner screens.Settling separation in non-stirred compartments:

sand traps and settling pits.Removal of gaseous contaminants

by vacuum degassers or similar equipmentForced settling by the action of centrifugal devices

including hydrocyclones (desanders, desilters and micro-cones) Mud cleaners and centrifuges.


Complete mud removal system with mud cleaner and centrifuge


sketch of a typical solids control systemFigure shows

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


a typical two–screen shale shakerThe 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 shaker


Linear shale shaker

The figure shows a layout for

solids control equipment for a weighted mud system.


shale shaker mechanismThe 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 configurations


The procedure

Shale shakers and scalper screens (Gumbo shakers) can effectively remove up to 80% of all solids from a

drilling fluid, if the correct type of shaker is used and

run in an efficient manner.

Removal procedure:Mud laden with solids passes over the vibrating shaker where the liquid part of mud and small solids

pass through the shaker screens and drill cuttings collect at the bottom of the shaker

to be discharged.


types of shaker operation

There are two types of shaker operation: elliptical shakers and

Field experience indicate they work better with water based muds

linear motion shakers. more suited

to oil based muds.

An absolute minimum of three shale shakers is recommended and that

these shakers are fitted with retrofit kits to allow quick and simply replacements.

The shakers should also be in a covered,

enclosed housing with a means of ventilation and each shaker fitted with a smoke hood.


Sample of shale shakers


SETTLING SEPARATION IN NON-STIRRED COMPARTMENTSThe solids control pits work on

an overflow principle. The sand traps are the first of the solids control pits and

are fed by the screened mud from the shale shakers. There should be no agitation from suction discharge

lines or paddles. Any large heavy solids will settle out here and

will not be carried on into the other pits.


DegassersGases 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.


Removal Of Gaseous Contaminants

Gas entrapped in mud must be removed in order to maintain the mud weight to a level needed to

control down hole formation pressures.

Gas is removed from mud using a vacuum degasser. It is a simple equipment containing a vacuum pump and

a float assembly. The vacuum pump creates a low internal pressure which allows

gas-cut mud to be drawn into the degasser vessel and it then flows in a thin layer over an internal baffle plate.


Vacuum degasserThe combination of

low internal pressure and thin liquid film causes gas bubbles to expand in size, rise to the surface of

the mud inside the vessel and break from the mud.

As the gas moves toward the top of the degasser it is removed

by the vacuum pump. The removed gas is

routed away from the rig and is then either vented to atmosphere or flared.


A typical degasser diagram(A vacuum chamber degasser)


FORCED SETTLING BY CENTRIFUGAL DEVICESDesanders and desilters are hydrocyclones and work on the principle of separating solids from a liquid

by creating centrifugal forces inside the hydrocyclone.

Hydrocyclones are simple devices with no internal moving parts. are classified according to the removed particle size 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 process of the Hydrocyclones (Desanders and Desilters)Mud is injected tangentially

into the hydrocyclone the resulting centrifugal

forces drive the solids to the walls of the hydrocyclone and finally discharges them from

the apex with a small volume of mud.

The fluid portion of mud leaves the top of the

hydrocyclone as an overflow and

is then sent to the active pit to be pumped downhole again.


Desanders

The primary use of desanders is in the top hole sections

when drilling with water based mud to help maintain low mud weights.

Desanders should be used if the sand content of the mud rises

above 0.5% to prevent abrasion of pump liners.should never be used with oil based muds,

because of its very wet solids discharge.


The desander

It is a set of two or three 8in or 10in hydrocyclones, and are positioned

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


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

Desilters, in conjunction with desanders, should be used to process low mud weights used to drill top hole sections. If it is required to raise the mud weight this must be

done with the additions of barytes, and not by allowing the build up of low gravity solids. Desilters should never be used with oil based muds.


Solid control equipmentTypical throughput

capacities are:Desanders

12"cone500 gpm per cone.

6" cone125 gpm per cone.

Desilters 4"cone

50 gpm per cone. 2" cone

15 gpm per cone.

(b) Desilter


Particle size classificationA 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.


Decanting centrifugeThe 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 centrifugeThe drums

are enclosed in an external, non–rotating

casing not shown in the figure.


Mud Cleaners

A mud cleaner is a desilter unit in which

the underflow is further processed by a fine vibrating screen, mounted directly under the cones.

The use of mud cleaners with oil based muds should be minimized since experience has shown that mud losses of 3 to 5 bbls/hr

being discharged are not uncommon, coupled with the necessity to adhere to strict

environmental pollution regulations.


mud cleanerInert 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.


mud cleaner schematic The mud

cleaner separates the low

density inert solids (undesirable) from the

high density weighting particles.

Unit of a mud cleaner


HydrocyclonesHydrocyclones 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 cleanerMud 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 cleaner


Drilling fluid componentsDrilling 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 EquipmentWater 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 motions


Sample of Mud agitator


Mud gunsMud 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 gun


mixing hopperThe 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. (CDF) Jorge H.B. Sampaio Jr. “Drilling Engineering Fundamentals.” Master of Petroleum Engineering. Curtin University of Technology, 2007. Chapter 2

2. (WEC) Rabia, Hussain. Well Engineering & Construction. Entrac Consulting Limited, 2002.Chapter 16 and 7

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