Filtration Control – Additives For Water Based Muds

•Several types of filtration-control additives are used in water-base muds.•Clays –sodium bentonite–Attapulgiteand sepioliteare clays but impart no filtration control •Polymers–Polymers are the filtration control products used most often in water-base muds–They can range from natural starches and modified cellulose to sophisticated synthetic polymers capable of providing filtration control under high temperatures and hostile conditions Polymers reduce fluid loss in several ways:–Plugging of openings of the filter cake by polymer particles.–Encapsulating solids forming a larger deformable coating or film which reduces the permeability of the filter cake.–Viscosificationof the liquid phase. •Starch, a natural carbohydrate polymer, has been used to control filtration in drilling fluids since the 1930s. –It is widely available as yellow (untreated) and white (modified) starch. –Starches can be used in seawater, salt water, hard water and complex brines. –The most economical and widely used starches are made from corn or potatoes, but starches made from other agricultural products are also available. •Sodium Carboxymethylcellulose(CMC) is a modified natural polymer used for filtration control.–CMC is an effective fluid-loss control additive in most water-base muds.–It works particularly well in calcium treated systems, where it acts to stabilize properties.–CMC is not subject to bacterial degradation and performs well at an alkaline pH. –CMC’s effectiveness decreases at salt concentrations greater than 50,000 mg/l.–subject to thermal degradation at temperatures exceeding 250°F.–Available in Low, medium and high viscosity grades PolyanionicCellulose (PAC) is a modified natural polymer used for: freshwater, seawater, salt and low-solids muds. –It is a high-molecular-weight, polyanioniccellulose similar to CMC, but has a higher degree of substitution. –It is the most widely used fluid-loss control additive and is generally a much better product than CMC.–Good to 275°F –Available as Ultra low viscosity and regular viscosity •Chemical thinners reduce filtration rates by deflocculating the clays, by increasing the fluid phase viscosity and by changing the solids distribution. –Desco and Lignite are effective at deflocculating and lowering fluid loss. •Also available for fluid loss control: –Complex Resin/lignite blends •For HPHT fluid loss control –Polyacrylites •Not in common use anymore •The API fluid loss of these systems is normally zero, or too low to be an effective measure. •The filtration rate of oil muds, unless otherwise noted, refers to the HTHP filtration. •Most oil-and synthetic-base fluids are emulsions. –Their fluid phase is an emulsion with oil or synthetic as the continuous phase and brine as the emulsified phase. –These systems contain from 10 to 50 volume percent brine, usually calcium chloride. –The emulsified brine forms colloid-sized droplets, which are immiscible in the oil or synthetic. –These brine droplets become trapped in the filter cake and reduce filter-cake permeability and fluid loss. Emulsifiers. –Although emulsifiers are not true filtration-control additives, they can reduce filtration by increasing the emulsion strength if the emulsion is unstable. –A sufficiently stable emulsion should be established before treating with filtration-control additives. –If an emulsifier requires lime to be activated, excess lime should be maintained in the mud. •Viscosifiers. –The primary viscosifier in invert emulsion muds is organophilic clay. –Although this clay does not hydrate, it will reduce the filtration rate by providing a colloidal solid for forming a basic filter cake. •The primary filtration-control additives for invert emulsion muds are: –asphalt, –gilsonite(natural asphalt), –amine treated lignite –various other resins –specialized polymers •The asphaltic materials usually provide better filtration control than the amine-treated lignite at equal concentrations and temperature.

Filtration Control -Fundamentals

•Drilling fluids are slurries composed of a liquid phase and solid particles.
–Filtration refers to the liquid phase of the drilling mud being forced into a permeable formation by differential pressure.
–During this process, the solid particles are filtered out, forming a filter cake
•Mud systems should be designed to seal permeable zones as quickly as possible with thin, slick filter cakes.
–In highly permeable formations with large pore throats, whole mud may invade the formation (depending on the size of the mud solids).
–In such situations, bridging agents must be used to block the openings so the mud solids can form a seal. Bridging agents should be at least one-half the size of the largest openings.
–Such bridging agents include calcium carbonate, ground cellulose and a wide variety of other lost-circulation materials
•Filtration occurs under both dynamic and static conditions during drilling operations.
–Dynamic tests are normally run in a laboratory environment using equipment such as a Fann 90
–Static test are run in the field and include the standard API filter press and the HPHT filter press
•For filtration to occur, three conditions are required:
–A liquid or a liquid/solids slurry fluid must be present.
–A permeable medium must be present.
–The fluid must be at a higher pressure than the permeable medium.
•Factors affecting filtration
–Time
–Pressure differential
–Filter cake permeability
–Viscosity
–Solids
•Orientation and composition
•Dynamic Filtration
–Dynamic filtration is significantly different from static filtration, often with considerably higher filtration rates.
–No direct correlation exists between API and HTHP static filtration measurements and dynamic filtration.
–Experience has shown that a mud which exhibits good static filtration characteristics and stability will have satisfactory performance under actual drilling conditions, indicating the dynamic fluid loss is in a satisfactory range.

Filtration Control

•A basic drilling fluid function is to seal permeable formations and control filtration (fluid loss). •Adequate filtration control and the deposition of a thin, low-permeability filter cake are often necessary to prevent drilling and production problems. •Potential problems from excessive filter-cake thickness: –Tight spots in the hole that cause excessive drag. –Increased surges and swabbing due to reduced annular clearance. –Differential sticking of the drillstring due to increased contact area and rapid development of sticking forces caused by higher filtration rate. –Primary cementing difficulties due to inadequate displacement of filter cake. –Increased difficulty running casing. •Potential problems from excessive filtrate invasion:–Formation damage due to filtrate and solids invasion.–Invalid formation-fluid sampling test.–Formation-evaluation difficulties caused by excessive filtrate invasion, poor transmission of electrical properties through thick cakes–Oil and gas zones may be overlooked because the filtrate is flushing hydrocarbons away from the wellbore, making detection more difficult.

CATION EXCHANGE CAPACITY(MBT)

The Methylene Blue Dye Test, (MBT), is used to determine the Cation Exchange Capacity of the solids present in a water base drilling mud. Only the reactive portions of the clays present are involved in the test and materials such as Barite, Carbonates, and Evaporitesdo not affect the results of the test, since these materials do not adsorb the Methylene Blue •For Bentonite based mud systems, the MBT provides an indication of the amount of reactive clays which are present in the drilling mud solids and for Bentonite free, water based mud systems, the MBT reflects the reactivity of the drilled solids. The test cannot distinguish between the type of clays but, if a reactivity for the drilled solids is known or assumed, it can be used to determine the amount of Bentonite present in the Bentonite based systems Test Procedure: •Using the completely filled, 3 ml syringe, measure 2.0 ml of mud sample to be tested into the Erlenmeyer flask containing 10-15 ml of distilled water. •Add 15 ml Hydrogen Peroxide and 1 ml of 5N Sulfuric Acid. Swirl or stir as required to mixed the solution •Boil gently for approximately 10 minutes, and dilute with 20 ml fresh water. Test Procedure: •Add Methylene Blue Dye in 1.0 ml increments. After each dilution, swirl the flask and stir vigorously for at least 20 seconds, and remove a drop of sample on the end of the stirring rod. •Apply the drop to a piece of filter paper making the drop with the amount of Methylene Blue added between each increment. The approximate end point is reached when a blue ring spreads out from the blue spot on the filter paper. •At this point, without further addition of Methylene Blue, swirl the flask an additional 2 minutes, and place another drop on the filter paper. If the blue ring is again apparent, the end point has been reached. •If the ring did not appear, continue with the Methylene Blue increments until a blue ring permanently forms after two additional minutes of swirling Note: For increased accuracy, 0.5 ml increments may be used as the end point is approached. The blue ring is more apparent on the reverse side of the filter paper from which the drop is placed Calculations: Note:Thereare 2 different strengths of Methylene Blue dye that is used todetermine the Equivalent Bentonite Content. One will have to determine which strength of dye the chemical testing company is supplying •Stronger Strength of Methylene Blue: –kg/m3Reactive Clay ( Equivalent Bentonite Content) = 14.25 X ml Methylene Blue ml of Mud Sample –lb/bbl Reactive Clay ( Equivalent Bentonite Content) = 5 X ml Methylene Blue ml of Mud Sample •Weaker Strength of Methylene Blue –kg/m3Reactive Clay ( Equivalent Bentonite Content) = 10 X ml Methylene Blue ml of Mud Sample –lb/bbl Reactive Clay ( Equivalent Bentonite Content) = 3.5 X ml Methylene Blue ml of Mud Sample

...

SOLIDS CALCULATIONS

•To completely analyze a drilling fluid for the amount of solids present, the following calculations should be used.
Low Density, UnweightedMud (No Oil, No Salt)
•Procedure:
–Measure Mud Density, D (kg/m3)
–Measure Bentonite from Methylene Blue Test, MBT (kg/m3)
•Volume Fraction of Solids, Fs
•Fs = [(D /1000) –1] X 0.625
–Volume Fraction of Water, Fw
•Fw= 1 –Fs
–Total Amount of Low Gravity Solids, LGS (kg/m3)
•LGS = D –(FwX 1000)
–Amount of Drilled Solids, DS (kg/m3)
•DS = LGS –MBT
Low Density, UnweightedMud (With Oil, No Salt)
•Procedure:
–Measure mud density, D (kg/m3)
–Measure Bentonite from Methylene Blue Test, MBT (kg/m3)
–Read the volume fraction of oil from the retort, Fo
•Volume Fraction of Solids, Fs
–Fs = [(D / 1000 –1) + (0.2 X Fo)] X 0.625
•Volume Fraction of Water, Fw
–Fw= 1 –(Fs + Fo)
–Total Amount of Low Gravity Solids, LGS (kg/m3)
•LGS = D –[(FoX 800) + (FwX 1000)]
–Amount of Drilled Solids, DS (kg/m3)
•DS = LGS –MBT
Low Density, UnweightedMud (With Oil, No Salt)
•Note: The oil fraction is obtained from the retort. The volume fraction of solids is obtained from the formula. This is done because small errors in reporting the volume fraction of solids can occur when taken from a retort in a unweightedlow density mud.
Low Density, UnweightedMud (With Salt, No Oil)
Note: These calculations should be used for fluids containing chlorides over 10,000 mg/L.
•Procedure:
–Measure Mud Density, D(kg/m3)
–Measure chloride content, Cl(mg/L)
–Measure Bentonite form Methylene Blue Test, MBT(kg/m3)
–Read the volume fraction of water from retort, Fw
–Read the volume fraction of Oil from retort, Fo
–Read the volume fraction of Salt in the mud from Figure 1.1, F Salt
Low Density, UnweightedMud (With Salt, No Oil)
–Amount of Salt in Mud, S(kg/m3)
•S = [(1.65 X Cl) X (Fw+ Fsalt)] / 1000
–Amount of Low Gravity Solids, LGS(kg/m3)
•LGS = 1.625 {D –[1000 (1 –Fsalt) ] + (160 X Fo) } –(0.375 X S)
–Amount of Drilled Solids, DS(kg/m3)
•LGS = LGS–MBT
–True Volume Fraction of Water, True Fw
•True Fw= [1.625 (1 –Fsalt)] –[(D + S) / 1600]
–Volume Fraction of Solids, Fs
•Fs = 1 –True Fw

Low Density, UnweightedMud (With Salt, With Oil)
Note: These calculations should be used for fluids containing chlorides over 10,000 mg/L.
•Procedure:
–Measure Mud Density, D(kg/m3)
–Measure Chloride content, Cl(mg/L)
–Measure Bentonite form Methylene Blue Test, MBT(kg/m3)
–Read the volume fraction of water from retort, Fw
–Read the volume fraction of Oil from retort, Fo
–Read the volume fraction of Salt in the mud from Figure 1.1, Fsalt

Low Density, UnweightedMud (With Salt, With Oil)
–Amount of Salt in Mud, S(kg/m3)
•S = [(.65 X Cl) X (Fw+ Fsalt)] / 1000
–Amount of Low Gravity Solids, LGS(kg/m3)
•LGS = 1.625 {D –[1000 (1 –Fsalt) ] + (160 X Fo) } –(0.375 X S)
–Amount of Drilled Solids, DS(kg/m3)
•LGS = LGS–MBT
–True Volume Fraction of Water, True Fw
•True Fw= [1.625 (1 –Fsalt)] –[(D + S) / 1600]
–Volume Fraction of Solids, Fs
•Fs = 1 –(True Fw+ Fo)
Weighted Systems
•Procedure:
–Measure the mud density, D(kg/m3)
–Measure the Chlorides, Cl(mg/L)
–Measure the Bentonite from Methylene Blue Test, MBT(kg/m3)
–Read the volume fraction of water from the retort, Fw
–Read the volume fraction of oil from the retort, Fo
–Read the volume fraction of Salt in the mud from Figure 1.1, F Salt
–Determine the volume fraction of solids from the retort, Fs
Weighted Systems
–Amount of Salt in mud, S (kg/m3)
•S = (1.65 X Cl) (Fw+ F Salt)/1000
–Amount of Total UndissolvedSolids, TS (kg/m3)
•TS = D –[(FoX 800) –(FwX 1000)] –S
–Average Relative Density of UndissolvedSolids, Dr
•Dr = TS / (Fs –F Salt) X 1000
–Amount of Barite in Mud, BAR (kg/m3)
•BAR = TS X [2.62 –(6.82/Dr)]
–Amount of Low Density Solids, LDS (kg/m3)
•LDS = TS –BAR
–Amount of Drilled Solids, DS (kg/m3)
•DS = LDS –MBT



Salt Volumes graph

RETORT / SOLIDS ANALYSIS

The retort apparatus is used to determine the amount and type of solids and liquids present in a drilling mud sample. Mud is placed in the steel container and then heated until the liquid portion is vaporized.

The vapor is passed through a condenser in which it is cooled, and then collected in a graduated cylinder.
•The volume of the water and oil is measured as a fraction of the total mud volume.
•For accurate results, a true mud density should be used for calculations, an accurate air free sample must be used, and a volume correction factor should be determined for oil content if it is present in the mud. Test Procedure
•Lift the retort assembly from the insulator block. Using a spatula as a screwdriver, remove the sample cup from the retort chamber.
•Pack the upper chamber with fine steel wool, or add 5-6 drops of “liquid steel wool”to the mud in the sample cup. Test Procedure
•Fill the lower sample cup with a freshly stirred mud sample, and replace the calibration lid, allowing any excess to escape.
•Wipe off any excess mud and screw the lower sample cup (with calibration lid still in place) into the upper chamber, maintaining both upper and lower chambers in the upright position. Screw condenser onto the outlet hose of the upper chamber Test Procedure
•Replace the retort assembly in the insulator block, and close the insulating cover.
•Add a drop of wetting agent (Aerosol) to a 10 cm3or 50 cm3graduated cylinder (depending on the size of retort being used), and place it under the drain of the condenser.
Plug in the retort and turn it on. Continue heating until liquid no linger drips from the condenser.
When using a thermostat retort, the light will go out at the end of the test Solids Calculations
•Most retorts are only accurate to within 1.0-2.0%. For that reason, most low solids muds, i.e.: muds with low mud densities that contain no Barite, salt or oil, use the following formula to calculate the volume fraction of solids:
•Volume Fraction of Solids (% Solids) = [(Mud Weight (kg/m3) / 1000) –1] X 0.625 Solids Calculations
•If a Baroid Retort is used, read the volume of oil and water. Calculate the fractions as follows if a 10 cm3retort is used:
•Fo(volume fraction of oil) = cm3oil / 10
•Fw(volume fraction of water) = cm3of water / 10
•Fs (volume fraction of solids) = 1.00 –total liquid fraction

Filtration Tests

•The filtration and wall building characteristics of a drilling mud are important for providing :
–a relative measure of the amount of mud filtrate invasion into a porous and permeable formation,
–the amount of filter cake that will be deposited on the wall of the wellbore wherever filtration occurs.
–From a drilling view point, these properties give an indication of the amount of water (or oil) wetting that can take place in filtrate sensitive formations,
–and the potential for tight hole or differential sticking problems. For productive, hydrocarbon bearing formations,
–these properties give an indication of the amount of filtrate invasion and permeability damage that can be expected.
•Filtration tests are conducted under two different conditions –standard API filtration test •surface (or room) temperature
–The API High Temperature
–High Pressure test (HT-HP test)
•±150 degrees Celsius (300 degrees F) or bottom hole temperature Standard API Test Procedure:
•Pour the mud sample into the cell, secure the lid and make sure all valves are in the correct positions to permit the application of pressure to the sample to be filtered.
If necessary, place a fresh CO2cartridge in the holding cylinder and screw the cylinder on quickly and securely to puncture the cartridge . Standard API Test Procedure:
•Place an appropriately sized, granulated cylinder under the filtration tube.
•Using the pressure gauge as an indicator, apply 700 kPa(100 psi) pressure to the sample and begin timing the test. Standard API Test Procedure:
•Collect the filtrate in the graduated cylinder for 30 minutes. At this time, remove the graduated cylinder, turn off and relieve the pressure on the test sample.
Standard API Test Procedure:
•Report the volume of collected fluid as the fluid loss in millimeters, making sure the volume is doubled if a “half area”filter press is used. •Disassemble the test cell, discard the mud, and use extreme care to save the filter paper with minimal disturbance to the filter cake. Remove excess mud from the filter cake by light washing, or lightly sliding a finger across the filter cake. Standard API Test Procedure: •Measure the thickness of the filter cake and report in millimeters.
If desirable, the filter cake texture may also be noted as being dry to slick, and mushy to firm to provide an indication of its friction factor and compressibility.
•Wash all components thoroughly fresh water, and wipe dry with a clean cloth or paper towel High Temperature
–High Pressure Filtration Test
•The following is the standard procedure adopted by the API for testing at ±149 degrees C (300 degrees F), and 3450 kPa(500 psi) differential pressure.
•Connect the heating jacket to the correct voltage, place a thermometer in the well of the jacket, and preheat the jacket to 155 deg.
C (311 degrees F). Adjust the thermostat in order to maintain a constant temperature High Temperature
–High Pressure Filtration Test
•Take warm mud from the flowline, and preheat to 50-55 deg.
C (120 –130 degrees F) while stirring.
•Load the cell as recommended by the manufacturer.
Care should be exercised not to fill the cell closer that 15 mm from the top to allow for expansion.
High Temperature
–High Pressure Filtration Test
•Place the cell in the heating jacket with both the top and bottom valves closed.
Transfer the thermometer from the heating jacket to the well of the test cell.
•Place the pressure assembly on the top valve stem and lock into place. Place the bottom pressure receiver and lock into place.
Apply 700 kPa(100 psi) to both pressure units with the valves closed. Open the top valve, and apply 700 kPa(100 psi) while heating.
•When the temperature reached ±149 deg.c (300 deg. F), open the bottom valve and increase the pressure on the top assembly to 4150 kPa( .High Temperature
–High Pressure Filtration Test •When the temperature reached ±149 deg. C (300 deg. F), open the bottom valve and increase the pressure on the top assembly to 4150 kPa( 600 psi) to start filtration.
Collect the filtrate for 30 minutes, maintaining 149 deg.
C (300 deg F) temperature, ±2 deg. C.
•If desired, record the volume after 2 seconds.
If the back pressure rises above 700 kPa(100 psi) during the test, cautiously bleed off pressure by collecting a portion of the filtrate. Record the total volume.
.High Temperature
–High Pressure Filtration Test
•The filtrate volume should be corrected to a filter area of 4581 mm2. Double the filtrate volume and report.
•At the end of the test, close both valves.
Back the T-handle screw off the regulator, and bleed of the pressure from both regulators.
•Caution:
The filtration cell will still contain ±3500 kPa(500 psi) pressure.
Maintain the cell in a upright position and cool to room temperature. After the cell is cool, continue to hole the cell upright (cap down), and loosen the top valve to bleed off the pressure slowly. High Temperature –High Pressure Filtration Test
•After the cell has cooled and the pressure has been bled off, the cell may be inverted to loose the cap screws with an Allen wrench.
Remove the cap with a gentle rocking motion.

Carefully retain the filter cake for analysis and thoroughly clean and dry all components.
•Do not use the filtrate for chemical analysis.
High Temperature
–High Pressure Filtration Test
•If filter cake compressibility is desired, the test can be repeated using 1400 kPa(200 psi) on the top pressure unit, and 700 kPa(100 psi) for the bottom pressure unit.
•Record both temperature and pressure with the results of the filtration test at all times.
The temperature of 149 deg. C (300 deg. F) is normally selected, so as to be within the range where high temperature mud treating procedures and chemicals are required.
High Temperature –High Pressure Filtration Test Note: At any time when utilizing any HT-HP filter press, if the CO2pressure runs out in the middle of the test and a replacement cartridge has to used, remember to shut the top and bottom valves prior to replacing the CO2cartridge.
Remember the filtration cell will still contain 500 psi pressure

Drilling Fluid Rheology

What is Rheology?
“Rheology is the study of deformation and flow







•Rheological properties are very important in drilling fluids
•By making certain measurements on a drilling fluid it is possible to determine how that fluid will flow under a variety of conditions, including temperature, pressure and shear rate.
Rheological measurements.
•In the field, a rotational viscometer having an industry standardized bob and sleeve is used


.
•Shear stress, viscosity, or gel strength is determined from the degree of rotation of the bob under the influence of the shear rate created in the mud by the action of the outer, rotating sleeve.
.•Because most drilling muds are non-Newtonian in behavior (pseudoplasticand thixotropic), stress, viscosity and gel strength measurements must be performed at prescribed shear rates (rotational speeds).
•The industry standard rotational speeds are 600 and 300 rpm for any steady state of rheological parameter and 3 rpm for gel strength (an indication of thixotropy) measurements.
Procedures for rheological measurements.
•Place a recently agitated sample in a suitable container and lower the instrument head until the sleeve is immersed in the drilling mud sample exactly at the scribed line of the sleeve.
•With the instrument set at 600 rpm, rotate the sleeve until a steady dial reading is obtained, (for highly thixotropic muds, this may take some time).
•The 600 rpm dial reading is taken at the point for which the change in dial reading is less than 1 degree (one dial division over a stirring time of one minute).
•When the dial reading has reached this steady value, record this as the 600 rpm dial reading, D600.
•Lower the speed to 300 rpm, and stir the sample at this speed until a steady reading is obtained using the same criteria for the steady state point. Record this value at the 300 rpm dial reading, D300.
Calculations:Apparent viscosity (cP) = D6002Plastic viscosity (cP) = D600–D300Yield point (pa) = D300-PV2Yield point (lb/ft2) = D300-PV

”

Marsh Funnel Viscosity

•Funnel viscosity is an indication of the overall viscosity of a drilling mud.
•It is affected by the concentration, type, size, and size distribution of the solids present, and the electrochemical nature of the drilling mud’s solid and liquid phase
•Consequently, funnel viscosity should only be used to provide an indication of change or consistency of viscosity from time to time. •Since Gel Strength can have a great effect on the magnitude of the funnel viscosity, the measurement should be taken quickly as possible Test Procedure
•With the funnel in an upright position, cover the orifice with a finger and rapidly pour a freshly collected mud sample through the screen, and into the funnel until the mud just touches the base of the screen (1500 ml).
•Immediately remove the finger from the orifice and measure the time required for the mud to fill the viscosity cup to the one (1) litrelevel for sec/l and (1) quart level for sec/q
•Report the result to the nearest second as the marsh funnel viscosity, at the temperature of measurement in degrees Celsius..

Mud Density (Pressurized mud balance)

Pressurized mud balance
•When a drilling mud contains entrapped air, or it is experiencing a foaming problem, the mud density may be accurately determined with a pressurized mud balance.
•This a mud balance is similar in operation to the instrument described above the difference being that the sample is pressurized to expel air or gas. Test procedure (pressure mud balance):
•Fill the sample cup with drilling mud to a level, which is approximately 10 mm below the upper edge of the cup. •Place the lid on the cup with the attached check valve in the down (open) position. Push the lid downward into the mouth of the cup until surface contact is made between the outer skirt of the lid and the upper edge of the cup allowing any excess mud to be expelled through the open check valve.
•Pull the check valve up into the closed position, rinse off the cup and threads, and the screw the threaded cap onto the cup.
•With the plunger in hand, push its handle into place in the inner piston to its lower most position.
Fill the plunger by immersing its nose in the mud to be tested and pulling out the handle until the inner piston is in its upper most position. (The plunger’s operation is similar to a syringe or bicycle pump).
•Place the nose of the plunger onto the mating o-ring surface of the valve on the cap. The sample cup is pressurized by maintaining a downward force on the cylinder in order to hold the check valve down (open), and at the same time forcing the piston inward. Approximately 220 Newton’s of force is required on the plunger handle in order to pressure the cup.
•The check valve in the lid is pressure actuated and will close (move up) under the influence of pressure within the sample cup.
Therefore the valve is closed by gradually easing up on the plunger cylinder while maintaining pressure on the piston. When the check valve closes, disconnect the plunger from the lid, rinse the cup in water and wipe it dry.
•Place the pressurized balance with the knife edge on the fulcrum of the balance stand. Adjust the sliding weight on the balance beam until the bubble oscillates equally to the left and right of the centering mark above the bubble vial. Note the value of the specific gravity at this point.
•The pressure in the mud balance is now released by reconnecting the empty plunger to the lid an pushing to the plunger cylinder while permitting the handle to move freely. To complete the procedure all components should be washed and rinsed thoroughly.

Mud testing

Mud testing•Necessary for a successful drilling operation•The tests are also used as a tool to aid in diagnosing mud related problems.•The mud properties are routinely checked at the well site, and recorded on a daily drilling mud report





Mud Density
•Drilling mud density is required to calculate the hydrostatic pressure that is being exerted by a column of drilling mud at any given depth. Density is also used to provide an indication of the solids content of a drilling mud.
•When the test is performed using a standard mud balance, care must be taken to ensure the cup is full and free of entrapped air.
Test procedure:
•Remove the lid from the cup and completely fill the cup with the mud to be tested. It may be necessary to tap or vibrate the cup lightly to bring the entrapped air to the surface for high viscosity muds.
•Replace the lid and seat it firmly on the cup in a rotating manner. Allow the excess drilling mud to be expelled through the centrally located hole in the lid.
•Wash the mud from the outside of the cup, and dry the mud balance.
.•Place the balance arm on the base with the knife edge resting on the fulcrum.•Adjust the rider until the bubble oscillates equally to the left and right of the centering mark above the level vial.•Read the mud density as shown by the indicator on the rider.•Report the result to the nearest scale division in kg/m3or lb/ga

l.

Transmit Hydraulic Energy to the Tools and Bit

•Hydraulic energy if becoming very important in modern day drilling
–Proper hydraulics program can increase ROP, help minimize hole enlargement, help to clean the hole –Special tools like MWD, LWD and mud motors require an available pressure to function properly •Hydraulic forces are limited to the available pump horsepower.
•All the pressure losses (pipe, bit, annular, tools etc) should be calculated beforehand to ensure adequate pressure is available for tools and hole cleaning. •Density, plastic viscosity, BHA design all affect hydraulics

Protect Formation Productivity

•Protecting the formations productivity is a big concern. After all the well was drilled to produce hydrocarbons, not as a science project.
•Formation damage can happen as a result of solids plugging up the porosity or permeability or through chemical or mechanical interactions with the formation •The type of the completion will determine the level of protect required –For example an open hole completion will require much more protection than a cement and perforation completion
•Consideration should be given to the type of fluid chosen to protect the formation
•Common mechanisms for formation damage are:
–Mud or drill solids invading the formation matrix, plugging pores.
–Swelling of formation clays within the reservoir, reducing permeability.
–Precipitation of solids as a result of mud filtrate and formation fluids being incompatible.
–Precipitation of solids from the mud filtrate with other fluids, such as brines or acids, during completion or stimulation procedures.
–Mud filtrate and formation fluids forming an emulsion, restricting permeability.
•Offset well information can help to predict formation damage
•Return permeability tests run with different fluids on cores will help to determine the best non-damaging fluids

Facilitate the Retrieval of Information from the Wellbore

•Accurate information retrieval is essential to the success of the drilling operation, particularly during exploration drilling
•The chemical and physical properties of the mud affect evaluation –During drilling mud loggers retrieve samples for evaluation
–After drill electric logs must be run in the hole to further evaluate the wells economics
–Logging may be performed while drilling using LWD (Logging While Drilling) tools
–Drill stem test may need to be completed
–Core may have to be cut
•All these techniques and tools may be affected by the mud properties both chemical and physical
–If the cuttings are dispersed mud loggers will have difficulty evaluating cuttings
–Additives (such as lubricants and asphalts) may mask oil shows –Certain electric logs require conductivity through the drilling fluid –Washouts will affect DST packer seats –Poor hole cleaning will make coring difficult

Suspend Cuttings When Circulation is Interrupted

•Drilling muds must suspend drill cuttings, weight materials and additives under a wide range of conditions, yet allow the cuttings to be removed by the solids-control equipment.

•Drill cuttings that settle during static conditions can cause bridges and fill, which in turn can cause stuck pipe or lost circulation.

•Weight material which settles is referred to as sag and causes a wide variation in the density of the well fluid.
•Sag occurs most often under dynamic conditions in high-angle wells, where the fluid is being circulated at low annular velocities
•High viscosity shear thinning fluids (thixotropic) and required to suspend cuttings during connections and other interruptions in circulation.
•Thixotropic fluids have properties that thin when stress is applied (such as circulation of the fluid) and thicken up or gel when static
•Most drilling fluids are thixotropic, polymers added to the fluid increase the low end rheology of the fluid and help to suspend cuttings and barite

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Provide Borehole Stability

•Borehole instability is most often identified by a sloughing formation, which causes tight hole conditions, bridges and fill on trips.

•This means the well must be reamed and cleaned and in extreme cases re-drilled •Borehole stability is greatest when the hole maintains its original size and cylindrical shape. •Once the hole is eroded or enlarged in any way, it becomes weaker and more difficult to stabilize •Hole enlargement leads many problems–low annular velocity–poor hole cleaning–increased solids loading–fill–increased treating costs–poor formation evaluation–higher cementing costs and inadequate cement bonding •Hole enlargement through sand and sandstone formations –mechanical actions: –erosion most often being caused by hydraulic forces and excessive bit nozzle velocities –Need to reduce impact force and nozzle velocity –Weaker sands require a slight overbalenceand good quality filter cake containing bentonite •Hole enlargement through shale –Water based muds can penetrate shale making it swell and soften over time and slough in –Higher mud weights and chemical/polymer inhibitors can reduce or eliminate slough •Highly fractured shales are very unstable –Usually require mechanical methods to clean, they require higher mud weights to control or oil based muds •Extremely water sensitive shales require an oil based or synthetic based fluid to drill successfully –These fluids provide better shale inhibition than water based fluids –Clays and shales do not hydrate or swell in the presence of oil –Osmotic forces created by the emulsified brine phase prevent adsorption of water by the shales

Cool and Lubricate the Bit and Drillstring

Considerable friction and heat by rotational and hydraulic forces of the bit and drillstring
•Circulation of the fluid cools the drillstring and bit distributing it throughout the wellbore.
•The drilling fluid also helps to cool down the bottom hole temperature.
•Drilling fluid also lubrictesthe BHA further reducing frictional heat.
When required lubricaingadditives are put into the fluid to further mitigate the problem •Without the cooling and lubricating action of the drilling fluid many sensitvemotors and components could not function or would fail under the heat. •Indications of poor lubrication are increased torque and drag, abnormal wear and heat checking of the drillstring compenents

Altering the lubricity of the drilling fluid is far from an exact science
•Many different drilling fluids exist from oil-based to silicate water based. •Different methods and additives are available to reduce torque and drag from actual lubricating oils to graphite material to lubricating polymeric beads

Release Cuttings at the Surface

•High concentrations of drill solids are detrimental to almost every aspect of the drilling operation, primarily drilling efficiency and ROP •Drill cuttings increase the mud weight and viscosity, which in turn increases maintenance costs and the need for dilution.

•Drill cuttings also increase the horsepower required to circulate, the thickness of the filter cake, the torque and drag, and the likelihood of differential sticking. •Drilling fluid properties that suspend cuttings must be balanced with those properties that aid in cuttings removal by solids-control equipment.
•Cuttings suspension requires high-viscosity, shear thinning thixotropic properties, while solids-removal equipment usually works more efficiently with fluids of lower viscosity
•Solids-control equipment is not as effective on non-shear-thinning drilling fluids, which have high solids content and a high plastic viscosity.
•For effective solids control, drill solids must be removed from the drilling fluid on the first circulation from the well.
•If cuttings are re-circulated, they break down into smaller particles that are more difficult to remove.
•One easy way to determine whether drill solids are being removed is to compare the sand content of the mud at the flow line and at the suction pit.

Transport Cuttings

Transport cuttings•The well is drilled and cuttings are produced the must be removed from the well
•The drilling fluid is circulated down through the pipe and bit nozzles entraining the cuttings and carrying them up the annulus to surface

•Cuttings removal is a function of cuttings size, shape and density; rotation of the drillstring; and mud properties such as viscosity, density and annular velocity
•Viscosity describes the rheological properties of the drilling fluid
–Cuttings settle faster in low viscosity fluids
–Higher viscosity fluids improve cuttings transport
–Most drilling fluids are thixotropic meaning that they gel under static conditions

•Velocity refers to the annular velocity of the fluid–Generally the higher the annular velocity the better cuttings removal
–If velocity is too high then turbulent flow may occur resulting in less efficient cuttings removal and possible wellbore erosion
–The net velocity is the difference in the slip velocity of the cuttings and the annular velocity
•Transport velocity=Annular velocity -slip velocity

Cuttings transport in high angle wells is more challenging than vertical ones
–Cuttings tend to accumulate at the low side of the hole creating cuttings beds
–The use of thixotropic fluids with high Low-Shear-Rate Viscosity run in Laminar flow can help clean out these cuttings beds
–High flow rate and thin fluid to try and achieve a turbulent flow can keep these wells clean
–Generally a mixture of high LSRV fluids and thin turbulent fluids are required to keep the hole clean

•High density fluid sweeps aid in hole cleaning
–The higher density fluid tends to get into the smaller cuttings beds and push them into the higher section of the hole to be cleaned off
•Pipe rotation
–This helps stir up the cuttings and lets the fluids take them away

Functions of a Drilling Fluid

Drilling fluid is a very important part of the drilling operation.
•Drilling fluid has many functions and is very complex
•The understanding of the uses of drilling fluid can make a drilling operation successful Ten functions of a drilling fluid:
1.Transport cuttings
2.Release cuttings at the surface
3.Control bottom hole pressure
4.Cool and lubricate the bit and drillstring
5.Provide borehole stability
6.Provide buoyancy for the drillstring
7.Suspend cuttings when circulation is interrupted
8.Facilitate the retrieval of information from the wellbore
9.Protect formation productivity
10.Transmit hydraulic energy to the tools and bit