Drilling Engineering 1 Course3rd Ed. , 3rd Experience
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.
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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.
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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.
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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
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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.
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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.
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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
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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.
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Mixing and suction tanks
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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.
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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
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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.
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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%.
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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.
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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.
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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.
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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.
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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).
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Duplex pumps
Piston scheme (double action) A duplex unit
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Triplex pumps
Piston scheme (single action). A Triplex unit
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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.
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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:
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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%.
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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.
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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.
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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:
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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%.
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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:
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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.
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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
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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.
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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.
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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.
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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 -
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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.
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Complete mud removal system with mud cleaner and centrifuge
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sketch of a typical solids control systemFigure shows
a sketch of a typical solids control system (for unweighted fluid).
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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
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Linear shale shaker
The figure shows a layout for
solids control equipment for a weighted mud system.
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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
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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.
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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.
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Sample of shale shakers
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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.
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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.
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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.
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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.
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A typical degasser diagram(A vacuum chamber degasser)
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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.
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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.
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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.
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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).
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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.
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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
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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.
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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.
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Internal view of a centrifugeThe drums
are enclosed in an external, non–rotating
casing not shown in the figure.
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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.
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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.
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mud cleaner schematic The mud
cleaner separates the low
density inert solids (undesirable) from the
high density weighting particles.
Unit of a mud cleaner
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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.
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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.
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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
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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.
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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.
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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.
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Mud agitator
Tank agitators or blenders toroidal and whirl motions
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Sample of Mud agitator
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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
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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.
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Mud hopper
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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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