Advantage Mud Manual .pdf

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GLOSSARY Chapter 1

Drilling Fluid Test Procedures

Chapter 2

Water Base Mud Systems

Chapter 3

Oil Base Mud Systems

Chapter 4

Drilling Fluid Contaminants

Chapter 5

Mud Related Drilling Problems

Chapter 6

Solids Control

Chapter 7

Product Data Information

Chapter 8

Hydraulics

Chapter 9

Engineering Data

TABLE OF CONTENTS – CHAPTER 1 Chapter 1

Return to Glossary Drilling Fluid Test Procedures

Return to Table of Contents

TOPICS 1.1 1.2 1.3 1.4 1.5 1.6 1.7 1.8 1.9 1.10 1.11 1.12 1.13

1.14 1.15

1.16 1.17 1.18

1.19

1.20 1.21

1.22 1.23 1.24 1.25 1.26 1.27 1.28 1.29 1.30 1.31

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MUD DENSITY (Unpressurized Mud Balance) MUD DENSITY (Tru-Wate Pressurized Mud Balance 1.2.1 OBTAINING TRU-WATE DENSITY WITH AN UNPRESSURIZED BALANCE MARSH FUNNEL VISCOSITY RHEOLOGICAL MEASUREMENTS(Viscometers) FILTRATION TESTS SAND CONTENT LIQUID AND SOLIDS CONTENT (RETORT / SOLIDS ANALYSIS) 1.7.1 SOLIDS CALCULATIONS CATION EXCHANGE CAPACITY pH DETERMINATION CHLORIDE DETERMINATION FILTRATE HARDNESS (Total Hardness, Calcium & Magnesium) GYPSUM (Calcium Sulfate) CONCENTRATION MUD FILTRATE ALKALINITY 1.13.1 Pf / Mf Method 1.13.2 P1 / P2 Method 1.13.3 GARRET GAS TRAIN METHOD (Carbonates) ALKALINITY OF THE MUD (Pm) SULFATE ION CONCENTRATION 1.15.1 Sulfate Ion – QUALITATIVE TEST 1.15.2 Sulfate Ion – QUANTITATIVE TEST AMMONIUM SULFATE TEST ( Hach Ammonia Nitrogen Test Kit (N1-8) SULFITE ION CONCENTRATION HYDROGEN SULFIDE CONCENTRATION 1.18.1 HACH H2S TEST 1.18.2 GARRETT GAS TRAIN (H2S HYDROGEN SULFIDE SCAVENGING ABILITY AND ZINC CARBONATE 1.19.1 ESTIMATION of ZINC CARBONATE CONCENTRATION (Qualitative 1.19.2 H2S SCAVENGING ABILITY and ZINC CARBONATE CONCENTRATION IRONITE SPONGE TEST POTASSIUM ION CONCENTRATION 1.21.1 HAND CRANK CENTRIFUGE METHOD 1.21.2 POTASSIUM TEST STRIPS POLYACRYLAMIDE (PHPA) POLYMER CONCENTRATION DAP AND PHOSPHATE CONCENTRATION NITRATE ION CONCENTRATION DETERMINATION OF AMOUNT OF CORINOX IN MUD FILTRATE LOST CIRCULATION MATERIAL CONCENTRATION BIOCIDE CONCENTRATION BACTERIA DIPSLIDE TEST POLYGLYCOL CONCENTRATION STABLE-K CONCENTRATION SODIUM SILICATE CONCENTRATION

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CHAPTER 1 DRILLING FLUID TEST PROCEDURES In order to ensure that the mud has optimum properties, certain tests are performed. These tests are used to make sure that the mud properties necessary for a successful drilling operation are achieved and maintained. 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.

1.1

MUD DENSITY (Unpressurized Mud Balance) Return to Table of Contents

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. Mud Balance Calibration: 1. 2. 3. 4.

Remove the lid and completely fill the cup with distilled water at room temperature. Replace the lid carefully, and wipe the entire balance dry. Place the balanced arm on the base with the knife edge resting on the fulcrum. With the rider placed at 1000 kg/m3 (S.G. – 1.0 or 8.33 lbs./gal), the bubble of the level vial should oscillate the same distance to the left and right of the centering mark above the vial. If not, the calibration screw at the end of the balance should be adjusted until the oscillations are equal. Some mud balances do not have an adjustment screw and required lead shot to be removed or added through a calibration cap. Note: A more accurate reading is obtained if the mud balance is permitted to oscillate on its knife edge, rather than allowing it to come to rest with the bubble centered over the centering mark.

Test Procedure: 1. 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. 2. 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. 3. Wash the mud from the outside of the cup, and dry the mud balance. 4. Place the balance arm on the base with the knife edge resting on the fulcrum. 5. Adjust the rider until the bubble oscillates equally to the left and right of the centering mark above the level vial. 6. Read the mud density as shown by the indicator on the rider. 7. Report the result to the nearest scale division in kg/m 3.

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Calculations: The SI density units in kg/m 3 can be found from three of the four different scales on the mud balance as follows: kg/m3 = lb/gal X 119.82 kg/m3 = lb/ft3 X 16.02 kg/m3 = Relative Density (gm/cm3) X 1000 The fourth scale on the balance is a mud gradient scale with units of psi/1000 ft. The SI unit for mud gradient is kPa/m. kPa/m = 22.62 X psi/ft Return to Table of Contents

1.2

MUD DENSITY (Tru-Wate 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 in Section 1.1 – the difference being that the sample is pressurized to expel air or gas. Test Procedure: 1. Fill the sample cup with drilling mud to a level, which is approximately 10 mm below the upper edge of the cup. 2. 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. 3. Pull the check valve up into the closed position, rinse off the cup and threads, and the screw the threaded cap onto the cup. 4. 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). 5. 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. 6. 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. 7. 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.

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8. 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. NOTE: For trouble free operation, the valve, lid and cylinder should be greased frequently with a water proof grease such as “Lubri-Plate. Calculations: The SI density units in kg/m 3 can be found from three of the four different scales on the mud balance as follows: kg/m3 = lb/gal X 119.82 kg/m3 = lb/ft3 X 16.02 kg/m3 = Relative Density (gm/cm3) X 1000 The fourth scale on the balance is a mud gradient scale with units of psi/1000 ft. The SI unit for mud gradient is kPa/m. kPa/m = 22.62 X psi/ft Return to Table of Contents

1.2.1

OBTAINING TRU-WATE DENSITY WITH AN UNPRESSURIZED BALANCE

If aeration becomes a problem in the mud system, and it is necessary to find a true mud density with a pressurized Tru-Wate mud balance, it may be obtained through the use of an unpressurized mud balance. 1. 2. 3. 4.

In a viscosity cup, add 500 ml of water. Slowly add the aerated mud to the water into the viscosity cup. Agitate the water / mud mixture to release the entrapped air. Continue adding mud to the mixture until the final volume of water and mud is at 1000 ml, and all the air is released from the mixture. 5. The true mud density can then be taken as follows. Calculations: 0.5 (Water Density) + 0.5 (Unknown Mud Density ) = Mud Balance Density Example: Water Density = 1000 kg/m3 (500 ml) Mud Balance Density = 1060 kg/m3 Unknown Mud Density = x 0.5 (1000) + 0.5 (x) = 1060 kg/m 3 500 + 0.5 (x) = 1060 0.5 (x) = 1060 - 500 0.5 (x) = 560 x = 560 0.5 x = 1120 kg/m3 The tru-wate or density of the mud is 1120 kg/m3

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1.3

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 as quickly as possible. Marsh Funnel Calibration: With the funnel in an upright position, fill it with freshwater (at 20 C) to the level of the screen with a finger placed over the orifice. With the aid of the measuring cup (viscosity cup) the time taken for one litre of water to pass through the funnel orifice tube should be 27.5 seconds (± 0.5 sec). The Marsh Funnel viscosity can be corrected using the following formula:

27.5 sec/L Measured Flow Of Water (sec/L)

=

X Measured Flow of Mud Sample (sec/L)

X = True Marsh Funnel Viscosity NOTE: The marsh funnel orifice is a tube, 50.8 mm in length and 4.76 mm in internal diameter. The orifice may be cleaned by passing a 4.76 mm (3/16 inch) drill through it by hand. Test Procedure: 1. 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). NOTE: It is also permissible to overfill the funnel to some level above the screen, and begin timing when the mud level reaches the screen. This is sometimes done in conjunction with not placing the finger over the orifice. In this manner, the effect of Gel Strength on funnel viscosity is minimized. 2. Immediately remove the finger from the orifice and measure the time required for the mud to fill the viscosity cup to the one (1) litre level. 3. Report the result to the nearest second as the Marsh Funnel Viscosity, at the temperature of measurement in degrees Celsius.

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1.4

RHEOLOGICAL MEASUREMENTS


In the field, the rheological characteristics of a drilling mud are determined with a concentric rotational viscometer having an industry standardized bob and sleeve. 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 (pseudoplastic and 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. The most common field viscometers are: Baroid Rheometer Model 280 The operation of these models is similar. The hand crank models have three speeds which are changed by a shift lever and internally controlled by a slip clutch. The stirring speed is obtained by moving the shift lever counter clockwise as far as possible. The 600 rpm speed is obtained by moving the shift lever clockwise from the stirring speed to the first detent position. The 300 rpm rotational speed is obtained by moving the shift lever to its next detent clockwise from the 600 rpm position. Gel strength is obtained by rotating the knurled hand wheel. Fann Model HC34A This hand crank model has two speeds which are changed by a shift knob (or wheel) on top of the instrument. The 600 rpm speed is obtained with the shift knob pushed down while the sleeve is rotating, and the 300 rpm rotational speed is obtained by moving the shift knob all the way up while the sleeve is moving. A neutral position is located by a detent half way between the 600 and the 300 reading position. Gel strengths are determined by rotating the knurled wheel (located below the shift knob) by hand with the shift knob in the neutral middle position. Fann Model 34A This model is a 3 speed electric version of the Fann Model HC34A. The stirring speed is obtained by pressing the button on the left side of the upper body. The 600 rpm speed is obtained with the top shift knob pushed down while the sleeve is rotating, and the 300 rpm speed is obtained by moving the top shift knob all the way up while the sleeve is rotating. A neutral position is located by a detent half way between the 600 and 300 rpm position. Gel strengths are determined by rotating the knurled wheel (located below the shift knob) by hand, with the shift knob in the neutral middle position.

PROCEDURES FOR RHEOLOGICAL MEASUREMENTS In conventional field practices, the steady state rheological description of a drilling mud is given in terms of the parameters which describe the fluid as an ideal Bingham Plastic. These parameters are the Plastic Viscosity and Yield Point, or Yield Stress. The time dependent nature of the drilling mud (thixotropy) is measured in terms of Gel Strength. The temperature at which rheological measurements are taken should be constant and always be recorded.

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1. Plastic Viscosity and Yield Point 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). Consistency of results can be achieved if 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). Rheological Measurements: 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 (mPa.s) = D600 2 Plastic Viscosity (mPa.s) = D600 – D300 Yield Point (Pa) = D300 - PV 2 2. Gel Strength Gel Strength measurements can be made as a continuation of the steady state measurements. Measurements are taken at two rest periods; 10 seconds and 10 minutes. a. Stir the mud sample at 600 rpm until a steady reading has been achieved. (If all time dependence has been taken out of the mud sample, this reading should be the same as the previous 600 rpm dial reading). b. Stop rotation of the sleeve. (For the Fann Model HC34A or 34A, the shift knob must be simultaneously brought to the neutral position). c. Allow a rest time of 10 seconds, then slowly (at 3 rpm) and steadily rotate the Gel Strength wheel (counter clockwise for the Fann instruments; clockwise for all others). d. Record the maximum dial deflection as the initial Gel Strength dial reading, D0. e. Repeat steps (a)-(b), and in step (c), allow a rest time of 10 minutes. f. Record the maximum dial reflection as the 10 minute Gel Strength dial reading, D10.

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Calculations: Initial Gel Strength, G0 (Pa) = D0 2 Ten Minute Gel Strength, G10 (Pa) = D10 2 Note: If the initial and the 10 minute Gel Strengths are equal, the mud has no thixotropy, i.e.: the mud has no ability to build structure while it is at rest. This type of mud does not have any real Gel Strengths, or increased suspending power while it is at rest. For this type of mud, the “gel break” is not very evident, rather it will be a gradual increase to a steady value. This is indicated by a lower ten minute Gel Strength in comparison to a higher initial Gel Strength. 3. Instrument Care After every usage, the instrument should be thoroughly cleaned. a. Run the rotor immersed in water (or solvent for oil base mud) at high speed for a short period of time. b. Remove the sleeve: - hold the spindle, twist and carefully pull straight down for the Fann instruments. - hold the spindle and unscrew the sleeve for all other instruments. c. Wipe the bob and other parts thoroughly clean with a dry, clean cloth or paper towel. Caution: The bob is hollow and from time to time accumulated moisture inside the bob can be eliminated by removing the bob and drying it out. Immersion of the hollow bob in extremely hot mud can result in a serious explosion. Care should be taken not to immerse the sleeve deeper into the mud than the scribed line on the sleeve. This may result in damage to the bearings holding the bob shaft in place. Similarly care must be taken not to splash water or solvent up into the sleeve housing when the bob and its shaft are cleaned.

1.5

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, and 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.

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Filtration tests are conducted under two different conditions. 1. The standard API filtration test is conducted at surface (or room) temperature and 700 kPa (100 psi) pressure for 30 minutes. For this test, the fluid loss is the volume (in millimeters) of filtrate collected in this time period, and the filter cake thickness (in millimeters) is the thickness of the cake that is deposited on the filter paper in this time period. 2. The API High Temperature – High Pressure test (HT-HP test) is conducted for thirty minutes of filtration at a temperature normally at ±150 degrees Celsius (300 degrees F), and a differential pressure of 3450 kPa (500 psi). If the bottom hole temperature is known, then the filtration temperature may be run at that temperature. For this test, the filtrate mud be collected under a back pressure of 700 kPa (100 psi), in order to prevent vaporization of the filtrate. For all filtration test, the filter paper characteristics are Whatman 50, or equivalent, and the filtration area is 4560 mm2. Many filtration tests are conducted with a “half area” filter press. In this event, the filter cake thickness will be the same, but the fluid loss must be corrected to the full size paper by doubling the collected filtrate volume in the 30 minute time period. All HT-HP instruments are half area presses.

Standard Filtration Test Instruments: 1. Rig Style, Standard Filter Press This type of filter press has a test cell with a removable lid and base that is placed onto the cross beam of a frame with a screw handle at the top for holding these component parts together during the test. The instrument is assembled in the following order: a. Base cap with filtrate tube, rubber gasket, screen, filter paper, rubber gasket fixed to the mud cell (cylinder) using the locking dowel. b. Pour drilling mud into the cell to within 10 mm from the top. c. Place the rubber gasket, filter paper, and lid onto the cross beam of the test cell frame. d. Then screw down the handle firmly and connect the pressure source making sure the pressure relief valve is closed. 2. Baroid, OFI Half Area Filter Press This type of instrument is typical of a “half area” cell for which the filtrate volume must be doubled when the fluid loss is reported. This instrument is self contained with a CO2 cartridge in a cylinder for its pressure source that is adjusted using the T-handle of the built-in regulator at the top of the instrument. The mud cell is a “rubber boot” that is placed inside a holding cup to separate the mud for the pressure source. The lip of the boot serves as the sealing surface onto which the half area filter paper is placed prior to securing the lid into place. The lid, in the form of a screw cap or other locking device, is either knurled on the inside to simulate a screen, or it may contain an actual, fixed screen. The relief valve (sliding bar) on the side of the cell must be open to apply pressure to the outside of the boot, and closed when the filtration test is complete, in order to permit pressure to be relieved.

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3. Fann Model MB (Magcobar Style) Filter Press This instrument consists of a mud cell assembly, pressure regulator and gauge mounted on the top of the carrying case. The cell is attached to the regulator by means of a coupling adapter by simply inserting the male cell coupling into the female filter press coupling, and turning clockwise ¼ turn. The cell is closed at the bottom by a lid fitted with a screen, by placing the lid firmly against the filter paper, and turning to the right until hand tight. This forces the filter paper against the O-ring fitted in the O-ring grove at the base of the cell. Pressure is supplied by a CO2 cartridge, and may be released by a bleed-off valve prior to uncoupling the cell. (The bleedoff valve is screwed in).

Standard API Test Procedure: 1. 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 CO2 cartridge in the holding cylinder and screw the cylinder on quickly and securely to puncture the cartridge. 2. Place an appropriately sized, granulated cylinder under the filtration tube. 3. Using the pressure gauge as an indicator, apply 700 kPa (100 psi) pressure to the sample and begin timing the test. 4. 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. 5. 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. 6. 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. 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. 7. Wash all components thoroughly fresh water, and wipe dry with a clean cloth or paper towel.

High Temperature – High Pressure Filtration Test 1. Baroid, OFI HT - HP Filter Presses These instruments are O-ringed valve stems that act as valves which are closed when the stem is tightened in the mud cell, and opened by unscrewing the valve stem approximately ½ turn. The pressure regulator and back pressure cylinder is attached to the valve stems with locking pins. The cell of this type of instrument is loaded by unscrewing the set screws in the cell body until the cap can be removed.

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With the valve stem in the body and closed (tightened), mud is added to the cell to within 1015 millimeters from the top. Filter paper is place on top of the O-ring which has its own groove in the cell body. The cap is placed in the cell making sure that the set screw seats in the cap match the screws in the cell. The pressure source is a CO2 cartridge located in the barrel of the regulator assembly. The back pressure attachment is required only for tests conducted at temperatures above 95 degrees C. The mud cell is placed into the heating jacket, and seated on the alignment pin located in the jacket. The filtrate volume obtained from this instrument must be doubled in order to correct the volume to the full sized paper.

2. Magcobar, OFI HT – HP Filter Presses These instruments are threaded valve stems with valves to which the pressure regulator assembly and back pressure assembly are secured using a lock ring and slip coupling assembly. The cell is filled by closing the valve on the cell, inverting it and then adding the drilling mud to within 10-15 mm from the top. Filter paper is placed on the O-ring in its groove. The cap of the cell is secured using set screws and lowered into the heating jacket which has provision to pass the valve and valve stem assembly of the cell through its base. The back pressure assembly is used for test with temperatures in excess of 95 degrees C. Pressure is supplied from CO2 cartridges in the barrel of the regulator assembly. The cartridge is punctured when the barrel is tightened onto the regulator assembly. This is a half area instrument whose filtrate volume must be doubled to correct it to the standard full size test.

High Temperature – High Pressure Filtration Test Procedure: 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. 1. 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. Adjust the thermostat in order to maintain a constant temperature. 2. Take warm mud from the flowline, and preheat to 50-55 deg. C while stirring. 3. 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. 4. 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. 5. 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. 6. 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.

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7. The filtrate volume should be corrected to a filter area of 4581 mm 2. Double the filtrate volume and report. 8. 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. 9. 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. 10. 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. 11. Do not use the filtrate for chemical analysis. 12. 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. 13. 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. Note: At any time when utilizing any HT-HP filter press, if the CO2 pressure 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 CO 2 cartridge. Remember the filtration cell will still contain 500 psi pressure.

1.6

SAND CONTENT


The API sand content is defined to be that portion of the drilling mud solids whose size is greater than 74 microns. The test can be used to give a qualitative, relative indication of the solids removal equipment effectiveness, the relative amount of coarse Barite present, and the abrasiveness of the mud. Equipment: The sand content set consists of a 63.5 mm, 74 micron (200 mesh) sieve, a small funnel to fit snugly over the sieve, and a conical glass tube graduated in percent, and having two fluid level indicator lines. Test Procedure: 1. Fill the glass measuring tube to the indicated mark with the mud to be tested. Add water to the next mark. Close the mouth of the tube and shake vigorously. 2. Pour the mixture onto the screen tapping it lightly to aid passing of the diluted mud through the screen. Add more clean water, and repeat this wet screening procedure until the wash water in the tube is clear. Wash the sand retained on the screen to free it of any remaining mud. 3. With the sieve in an upright position, fit the funnel over the sieve. Invert slowly and fit the funnel tip into the mouth of the cleaned measuring tube. Back wash the sand from the sieve using a fine spray of clean water with the measuring tube positioned vertically upright, allowing the sand to settle in the tube for a few minutes. Report the sand content as the volume fraction of sand, (the volume percent divided by 100). For example, if the sand content is read as ¼%, the volume fraction is reported as 0.0025%

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1.7

LIQUID AND SOLIDS CONTENT (RETORT / SOLIDS ANALYSIS) Return to Table of Contents

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: Fann Ministill 1. Fill the lower chamber with a freshly obtained mud sample. 2. Place the calibration lid on the chamber allowing any excess mud to escape. 3. Remove the calibration lid from the chamber, and scrape any excess mud from the lid into the chamber. 4. Add 5-6 drops of “liquid steel wool” to the mud in the sample cup, or pack steel wool around the upper portion of the immersion heater. 5. Screw the lower retort chamber into the upper chamber while maintaining both chambers in an upright position. 6. Screw the immersion heater into the cup/chamber assembly. 7. Attach the assembled retort to the condenser. 8. Add a drop of wetting agent (Aerosol) to a 100% by volume graduated cylinder, and place it under the drain of the condenser. Heating time is usually 20-30 minutes depending on mud type. Removable Retort 1. Lift the retort assembly from the insulator block. Using a spatula as a screwdriver, remove the sample cup from the retort chamber. 2. Pack the upper chamber with fine steel wool, or add 5-6 drops of “liquid steel wool” to the mud in the sample cup. 3. Fill the lower sample cup with a freshly stirred mud sample, and replace the calibration lid, allowing any excess to escape. 4. 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. 5. Replace the retort assembly in the insulator block, and close the insulating cover. 6. Add a drop of wetting agent (Aerosol) to a 10 cm 3 or 50 cm3 graduated 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.

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Handling and Instrument Care: 1. Use the spatula to scrape the dried mud form the mud chamber an lid to assure correct volume. 2. Use the high temperature lubricant on the threads of the mud chamber and lid to make dismantling easier. 3. Remove and replace any mud caked steel wool. 4. Use a pipe cleaner to clean the drain tube and condenser. 5. The retort should be cooled prior to dismantling. It is extremely hot during and after the test.

1.7.1

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/m 3) / 1000) – 1] X 0.625 If a Fann Ministill is used, the % by volume water and oil is read directly. The volume fraction of each constituent is the % by volume divided by 100. If a Baroid Retort is used, read the volume of oil and water. Calculate the fractions as follows if a 10 cm3 retort is used: Fo (volume fraction of oil) = cm 3 oil / 10 Fw (volume fraction of water) = cm3 of water / 10 Fs (volume fraction of solids) = 1.00 – total liquid fraction To completely analyze a drilling fluid for the amount of solids present, the following calculations should be used. UNWEIGHTED SYSTEMS 1. Low Density, Unweighted Mud (No Oil, No Salt) Procedure: 1. Measure Mud Density, D (kg/m3) 2. Measure Bentonite from Methylene Blue Test, MBT (kg/m3) a.

Volume Fraction of Solids, Fs Fs = [(D /1000) – 1] X 0.625

b.

Volume Fraction of Water, Fw Fw = 1 – Fs

c.

Total Amount of Low Gravity Solids, LGS (kg/m3) LGS = D – (Fw X 1000)

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d.

Amount of Drilled Solids, DS (kg/m3) DS = LGS – MBT

Example (No Oil, No Salt): 1. Density, D = 1080 kg/m3 2. Bentonite, MBT – 75 kg/m3 a.

Volume Fraction of Solids, FS Fs = [(D /1000) – 1] X 0.625 Fs = [(1080 / 1000) – 1] X 0.625 = (1.08 – 1) X 0.625 = 0.08 X 0.625 = 0.05

b.

Volume Fraction of Water, Fw Fw = 1 – Fs Fw = 1 – 0.05 = 0.95

c.

Total Amount of Low Gravity Solids, LGS (kg/m3) LGS LGS

d.

= D – (Fw X 1000) = 1080 – (0.95 X 1000) = 1080 – 950 = 130 kg/m3 of Low Gravity Solids

Amount of Drilled Solids, DS (kg/m3) DS = LGS – MBT DS = 130 – 75 = 55 kg/m3 of Drilled Solids

2. Low Density, Unweighted Mud (With Oil, No Salt) Procedure: 1. Measure mud density, D (kg/m3) 2. Measure Bentonite from Methylene Blue Test, MBT (kg/m3) 3. Read the volume fraction of oil from the retort, Fo a.

Volume Fraction of Solids, Fs Fs = [(D / 1000 – 1) + (0.2 X Fo)] X 0.625

b.

Volume Fraction of Water, Fw Fw = 1 – (Fs + Fo)

c.

Total Amount of Low Gravity Solids, LGS (kg/m3) LGS = D – [(Fo X 800) + (Fw X 1000)]

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e.

Amount of Drilled Solids, DS (kg/m3) DS = LGS – MBT

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 unweighted low density mud. Example (With Oil, No Salt): 1. Density, D = 1080 kg/m3 2. Bentonite, MBT = 75 kg/m3 3. Volume Fraction of Oil, Fo = 0.02 (from the retort) a.

Volume Fraction of Solids, Fs Fs = [(D / 1000 – 1) + (0.2 X Fo)] X 0.625 Fs = [(1080 / 1000) – 1) + (0.2 X 0.02)] X 0.625 = [(1.08 – 1) + (0.004)] X 0.625 = (0.08 + 0.004) X 0.625 = 0.084 X 0.625 = 0.0525

b.

Volume Fraction of Water, Fw Fw = 1 – (Fs + Fo) Fw = 1 – (0.0525 + 0.02) = 1 – 0.0725 = 0.9275

c.

Total Amount of Low Gravity, LGS (kg/m3) LGS LGS

d.

= D – [(Fo X 800) + (Fw X 1000)] = 1080 – [(0.02 X 800) + (0.9275 X 1000)] = 1080 – (15 + 927.5) = 1080 – 942.5 = 137.5 kg/m3 Total Solids

Amount of Drilled Solids, DS (kg/m3) DS = LGS – MBT DS = 137.5 – 75 = 62.5 kg/m3 Drilled Solids

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3. Low Density, Unweighted Mud (With Salt, No Oil) Note: These calculations should be used for fluids containing chlorides over 10,000 mg/L. Procedure: 1. 2. 3. 4. 5. 6.

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 a.

Amount of Salt in Mud, S (kg/m3) S = [(1.65 X Cl) X (Fw + Fsalt)] / 1000

b.

Amount of Low Gravity Solids, LGS (kg/m3) LGS = 1.625 {D – [1000 (1 – Fsalt) ] + (160 X Fo) } – (0.375 X S)

c.

Amount of Drilled Solids, DS (kg/m3) LGS = LGS – MBT

d.

True Volume Fraction of Water, True Fw True Fw = [1.625 (1 – Fsalt)] – [(D + S) / 1600]

e.

Volume Fraction of Solids, Fs Fs = 1 – True Fw

Example: 1. 2. 3. 4. 5. 6.

Mud Density, D = 1120 kg/m3 Chlorides, Cl = 20,000 mg/L Bentonite, MBT = 45 kg/m3 Volume Fraction of Water, Fw = 0.91 (from retort) Volume Fraction of Oil, Fo = 0.00 (from retort) Volume Fraction of Salt, Fsalt = 0.011 (From Figure 1.1) a.

Amount of Salt is Mud, S (kg/m3) S S

= [(1.65 X Cl) X (Fw + Fsalt)] / 1000 = [(1.65 X 20,000) X (0.91 + 0.011)] / 1000 = ( 33000 X 0.921) / 1000 = 30393 / 1000 = 30.4 kg/m3 Salt

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b.

Amount of Low Gravity Solids, LGS (kg/m3) LGS LGS

c.

Amount of Drilled Solids, DS (kg/m3) LGS

d.

= 1.625 {D – [1000 (1 – Fsalt) ] + (160 X Fo) } – (0.375 X S) = 1.625 {1120 – [1000 (1 – 0.011) ] + (160 X 0} – (0.375 X 30.4) = 1.625 {1120 – (1000 X 0.989) + 0} – 11.4 = 1.625 (1120 – 989) – 11.4 = (1.625 X 131) – 11.4 = 212.9 – 11.4 = 201.5 kg/m3 Low Gravity Solids

= LGS – MBT = 201.5 – 45 = 156.5 kg/m3 Drilled Solids

True Volume Fraction of Water, True Fw True Fw = [1.625 (1 – Fsalt)] – [(D + S) / 1600] True Fw = [1.625 X (1 – 0.011)] – [(1120 + 30.4) / 1600] = [(1.625 X 0.989) – (1150.4 / 1600) = (1.607) – (0.719) = 0.89

e.

Volume Fraction of Solids, Fs Fs = 1 – True Fw Fs = 1 – 0.89 = 0.11

4. Low Density, Unweighted Mud (With Salt, With Oil) Note: These calculations should be used for fluids containing chlorides over 10,000 mg/L. Procedure: 1. 2. 3. 4. 5. 6.

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 a.

Amount of Salt in Mud, S (kg/m3) S = [(.65 X Cl) X (Fw + Fsalt)] / 1000

b.

Amount of Low Gravity Solids, LGS (kg/m3) LGS = 1.625 {D – [1000 (1 – Fsalt) ] + (160 X Fo) } – (0.375 X S)

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c.

Amount of Drilled Solids, DS (kg/m3) LGS = LGS – MBT

d.

True Volume Fraction of Water, True Fw True Fw = [1.625 (1 – Fsalt)] – [(D + S) / 1600]

e.

Volume Fraction of Solids, Fs Fs = 1 – (True Fw + Fo)

Example: 1. 2. 3. 4. 5. 6.

Mud Density, D = 1120 kg/m3 Chlorides, Cl = 30,000 mg/L Bentonite, MBT = 45 kg/m3 Volume Fraction of Water, Fw = 0.90 (from retort) Volume Fraction of Oil, Fo = 0.05 (from retort) Volume Fraction of Salt, Fsalt = 0.016 (From Figure 1.1) a.

Amount of Salt in Mud, S (kg/m3) S S

b.

= [(.65 X Cl) X (Fw + Fsalt)] / 1000 = [(1.65 X 30,000) X (0.90 + 0.016)] / 1000 = ( 49500 X 0.916) / 1000 = 45342 / 1000 = 45.3 kg/m3 Salt

Amount of Low Gravity Solids, LGS (kg/m3) LGS LGS

c.

Amount of Drilled Solids, DS (kg/m3) LGS

d.

= 1.625 {D – [1000 (1 – Fsalt) ] + (160 X Fo) } – (0.375 X S) = 1.625 {1120 – [1000 (1 – 0.016) ] + (160 X 0.05} – (0.375 X 45.3) = 1.625 {1120 – (1000 X 0.984) + 8} – 16.99 = 1.625 {(1120 – 984) + 8} – 16.99 = (1.625 X 144) – 16.99 = 234 – 16.99 = 217 kg/m3 Low Gravity Solids

= LGS – MBT = 217 – 45 = 172 kg/m3 Drilled Solids

True Volume Fraction of Water, True Fw True Fw = [1.625 (1 – Fsalt)] – [(D + S) / 1600] True Fw = [1.625 X (1 – 0.016)] – [(1120 + 45.3) / 1600] = [(1.625 X 0.984) – (1165.3 / 1600)] = (1.599) – (0.728) = 0.87

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e.

Volume Fraction of Solids, Fs Fs = 1 – (True Fw + Fo) Fs = 1 – (0.87 + 0.05) = 1 – 0.92 = 0.08

WEIGHTED SYSTEMS Procedure: 1. 2. 3. 4. 5. 6. 7.

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 a.

Amount of Salt in mud, S (kg/m3) S = (1.65 X Cl) (Fw + F Salt)/1000

b.

Amount of Total Undissolved Solids, TS (kg/m3) TS = D – [(Fo X 800) – (Fw X 1000)] – S

c.

Average Relative Density of Undissolved Solids, Dr Dr = TS / (Fs – F Salt) X 1000

d.

Amount of Barite in Mud, BAR (kg/m3) BAR = TS X [2.62 – (6.82/Dr)]

e.

Amount of Low Density Solids, LDS (kg/m3) LDS = TS – BAR

f.

Amount of Drilled Solids, DS (kg/m3) DS = LDS – MBT

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1. Example Weighted Mud (With Oil, No Salt) 1. 2. 3. 4. 5.

Mud Density, D = 1560 kg/m3 Bentonite, MBT = 65 kg/m3 Volume Fraction of Water, Fw = 0.73 (from Retort) Volume Fraction of Oil, Fo = 0.01 (from Retort) Volume Fraction of Solids, Fs = 0.26 (By Difference) a.

Amount of Salt in mud, S (kg/m3) No Salt in Mud = 0

b.

Amount of Total Undissolved Solids, TS (kg/m3) TS = D – (Fo X 800) – (Fw – 1000) – S = 1560 – [(0.01 X 800) – (0.73 X 1000)] - 0 = 1560 – (8) – (730) – 0 = 822 kg/m3

c.

Average Relative Density of Undissolved Solids, Dr Dr = TS / (Fs – F Salt) X 1000 = 822 / (0.26 – 0) X 1000 = 822 / 0.26 X 1000 = 822 / 260 = 3.16

d.

Amount of Barite in Mud, BAR (kg/m3) BAR = TS X [2.62 – (6.82/Dr)] = 822 X [(2.62 – (6.82/3.16)] = 822 X (2.62 – 2.16) = 822 X 0.46 = 378 kg/m3

e.

Amount of Low Density Solids, LDS (kg/m3) LDS = TS – BAR = 822 – 378 = 444 kg/m3

f.

Amount of Drilled Solids, DS (kg/m3) DS = LDS – MBT = 444 – 65 = 379 kg/m3

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2. Example Weighted Mud (With Oil, With Salt) 1. 2. 3. 3. 4. 5. 6.

Mud Density, D = 1680 kg/m3 Chlorides, Cl = 20000 mg/L Bentonite, MBT = 30 kg/m3 Volume Fraction of Water, Fw = 0.65 (from Retort) Volume Fraction of Oil, Fo = 0.05 (from Retort) Volume Fraction of Solids, Fs = 0.30 (By Difference) Volume Fraction of Salt, F Salt = 0.008 (From Figure 1.1) a.

Amount of Salt in mud, S (kg/m3) S

b.

= (1.65 X Cl) (Fw + F Salt) / 1000 = (1.65 X 20000) (0.65 + 0.008) / 1000 = (33000) (0.658) / 1000 = 21714 / 1000 = 21.7 kg/m3

Amount of Total Undissolved Solids, TS (kg/m3) TS = D – (Fo X 800) – (Fw – 1000) – S = 1680 – [(0.05 X 800) – (0.65 X 1000)] – 21.7 = 1680 – (40) – (650) – 21.7 = 968 kg/m3

c.

Average Relative Density of Undissolved Solids, Dr Dr = TS / (Fs – F Salt) X 1000 = 968 / (0.30 – 0.008) X 1000 = 968 / 0.292 X 1000 = 968 / 292 = 3.32

d.

Amount of Barite in Mud, BAR (kg/m3) BAR = TS X [2.62 – (6.82/Dr)] = 968 X [(2.62 – (6.82/3.32)] = 968 X (2.62 – 2.05) = 968 X 0.57 = 552 kg/m3

e.

Amount of Low Density Solids, LDS (kg/m3) LDS = TS – BAR = 968 – 552 = 416 kg/m3

f.

Amount of Drilled Solids, DS (kg/m3) DS = LDS – MBT = 416 – 30 = 386 kg/m3

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Figure 1.1

WATER IN MUD, volume fraction

Page-23

VOLUME FRACTION SALT (As NaCl) in the WATER PHASE

Chloride Content (mg/L) 5000 10000 20000 30000 40000 60000 80000 100000 120000 140000 160000 180000 188650

1.8

Volume Fraction (Salt) 0.003 0.006 0.012 0.018 0.023 0.034 0.045 0.057 0.070 0.082 0.095 0.108 0.114

CATION EXCHANGE CAPACITY

Specific Gravity 1.004 1.010 1.021 1.032 1.043 1.065 1.082 1.098 1.129 1.149 1.170 1.194 1.197


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 Evaporites do not affect the results of the test, since these materials do not adsorb the Methylene Blue.

The Cation Exchanged Capacity of some typical clays is:

Clay

CEC (milliequiv. / 100 gm moisture free) 75 45 10 8-12

Wyoming Bentonite Soft Shale Kaolinite Drilled Cuttings

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.

Page-24

Equipment: 1. 2. 3. 4. 5. 6. 7. 8. 9. 10.

Erlenmeyer flask Hot plate or bottle warmer Stirrer Rod Hydrogen Peroxide Solution (3%) Sulfuric Acid – 5N Methylene Blue Solution: (solution strength may vary depending upon supplier) 10 ml pipette 3 ml syringe No. 4 Whatman Filter Paper ( Standard filter paper may be substituted) 25 ml Graduated Cylinder

Test Procedure: 1. 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. 2. Add 15 ml Hydrogen Peroxide and 1 ml of 5N Sulfuric Acid. Swirl or stir as required to mixed the solution 3. Boil gently for approximately 10 minutes, and dilute with 20 ml fresh water. 4. 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. 5. 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: There are 2 different strengths of Methylene Blue dye that is used to determine the Equivalent Bentonite Content. One will have to determine which strength of dye the chemical testing company is supplying. 1.

Stronger Strength of Methylene Blue: kg/m3 Reactive Clay ( Equivalent Bentonite Content) = 14.25 X ml Methylene Blue ml of Mud Sample

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2.

Weaker Strength of Methylene Blue (as supplied by Canamera United Supply Ltd.) kg/m3 Reactive Clay ( Equivalent Bentonite Content) = 10 X ml Methylene Blue ml of Mud Sample

Care of Reagents: The Methylene Blue Dye and Hydrogen Peroxide should be stored in a cool, dark place to extend the life. These solutions should be replaced every 4 months.

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1.9

pH DETERMINATION


The acidity or alkalinity of a drilling mud is indicated by the Hydrogen ion concentration, which is commonly expressed in terms of pH. A perfectly neutral solution has a pH of 7.0, whereas alkaline (basic) solutions have a pH range between 7.0-14.0, and acidic solutions have a pH less than 7.0. The pH measurement is used as well to indicate the presence of contaminants such as cement or anhydrite. The two most common field methods for determining pH are described as follows: pHydion Paper: 1. This method may be used on the mud filtrate, or whole mud directly. 2. Place a 25 mm (1 inch) strip of indicator paper on the surface of the mud to be tested and allow it to remain until the liquid has wet the surface and the color has stabilized. This takes approximately 1 minute. 3. Compare the color standards provided with the test paper (which was not in contact with the mud solids) to the color standards provided with the test paper, and estimate the pH of the mud accordingly. Color pH Strips: 1. This method applies only to the mud filtrate. 2. After obtaining a sample of mud filtrate, totally immerse the colored portion of the color pH strip into the filtrate, and remove immediately. 3. After a short period of color stabilization (10-15 seconds), compare the color of the wetted strip with the color standards provided in the color pH plastic container. An estimate may be necessary if a color does not exactly match a particular pH value.

1.10

CHLORIDE DETERMINATION


Chloride ions exist in a mud system as Salts of Sodium, Magnesium, Calcium, or Potassium. The determination of the Chloride ion present in the mud filtrate may give an indication of a Salt water flow, or the presence of a Salt formation or stringer. In mud systems to which Salt has been added, the Chloride measurements show the amount of salinity present in the mud. Equipment: 1. Silver Nitrate solution: - 0.0282 N for low Chloride concentrations - 0.282 N for high Chloride concentrations 2. Potassium Chromate indicator 3. Sulfuric Acid (N/50) 4. Phenolphthalein indicator 5. Pipettes (1 ml) 6. White titration dish 7. Stirring rod

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Test Procedure: 1. Measure 1.0 ml of filtrate into a white titration dish and dilute to a convenient volume with distilled water. 2. Add a few drops of Phenolphthalein indication solution. If a pink color develops, add N/50 Sulfuric Acid until the pink color completely disappears. It is not necessary to record the volume of N/50 Sulfuric Acid added. 3. Add 4-5 drops of Potassium Chromate indicator to obtain a yellow color. 4. Add Silver Nitrate while swirling or stirring until the color changes from yellow to orange-red (brick red), and persists for 30 seconds. Calculations: 1.

If 0.0282 N Silver Nitrate is used: mg/L Chlorides = 1000 X ml of Silver Nitrate added

2.

If 0.282 N Silver Nitrate is used: mg/L Chlorides = 10000 X ml of Silver Nitrate added

Remarks: 1. mg/L Salt (NaCl) = 1.65 X mg/L Chlorides 2. The Chloride test may be run on the same sample used in the Pf determination, if the Mf test was not performed. 3. Avoid contact with the Silver Nitrate solution. Wash immediately with water if Silver Nitrate gets on the skin or clothing. 4. The end point of the reaction is when the Silver Chromate is when the first detectable permanent color change from yellow to a light brick red occurs. When using the weak Silver Nitrate solution, the end point is approached very gradually. Therefore, the formation of the Silver Chromate can be seen by a color change for yellow to brick red. If the strong Silver Nitrate is used, the end point is approached much more rapidly. Hence the early formation of the Silver Chromate, and is brick red color may be missed due to the larger amounts of Silver Nitrate being added. The color change will go from yellow to red. As soon as the red color is seen, the titration is complete. 5. White lumps of Silver Chloride form when titrating high concentrations of Salt. This should not be mistaken for the end point. 6. A high pH will precipitate Silver Oxide.

1.11

FILTRATE HARDNESS (Total Hardness, Calcium & Magnesium)

Return to Table of Contents Water containing large amounts of Calcium or Magnesium Salts is commonly referred to as “hard water”. Make up waters that are hard make it difficult to obtain the maximum yield from Bentonite, so it becomes necessary to treat out excess Calcium. As a general rule, the total hardness as Calcium should be brought to less tan 40 mg/L. The presence of Calcium in the mud filtrate may also indicate the presence of contaminants, such as anhydrite or cement.

Page-28

Equipment: 1. 2. 3. 4. 5. 6. 7. 8.

Titraver Solution, 1 ml = 1 mg CaCO3 Strong Buffer Solution Manver Indicator 1 ml Pipettes Distilled Water Stirring Rod Calver II Indicator (to distinguish Calcium form Magnesium) Potassium Hydroxide (8N) solution to distinguish Calcium from Magnesium)

Test Procedures: Total Hardness (as Calcium): 1. Using a pipette, measure 1.0 ml of filtrate into a white titration dish, and dilute to a convenient volume with distilled water. 2. Add 4-5 drops of strong Buffer solution, and 2-3 drops of Manver Indicator. A red or wine color will develop if Calcium is present. 3. While swirling or stirring continuously, add Titraver with a pipette until the color changes from red to blue. At this end point, record the number of milliliters of Titraver added. Calculations: mg/L Hardness (as Calcium) = 400 X ml Titraver added

Calcium Hardness: 1. Using a pipette, measure 1.0 ml of filtrate into a white titration dish, and dilute with a small amount of distilled water. 2. Add 2-3 drops of 8N KOH (Potassium Hydroxide) solution. 3. Add several grains of Calver II, and swirl or stir to mix. 4. Using a pipette. Titrate with Titraver solution to a color change from red to blue. Calculations: mg/L Calcium Ion = 400 X ml Titraver added Magnesium Hardness: The Magnesium hardness is calculated as follows: mg/L Magnesium = mg/L Total Hardness (as Calcium) – mg/L Calcium

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1.12

GYPSUM (Calcium Sulfate) CONCENTRATION Return to Table of Contents

This test essentially repeats the test for total hardness as performed on the mud filtrate, but this test uses a sample of whole mud. The result in terms of total Gypsum is then deducted. Equipment 1. Versenate Solution, 0.01M EDTA 2. Strong Buffer (made up from 7.0 grams Ammonium Chloride in 970 ml Ammonium Hydroxide made up to 1000 ml with distilled water) 3. Calmagite (1 gram per litre in distilled water)

Test Procedure 1. Add 5 ml of mud to 245 ml of distilled water. Stir the mixture for 15 minutes, then filter with an API filter press through standard test paper. Discard any cloudy filtrate. 2. Pipette 10 ml of the clear filtrate into a titration dish. 3. Continue as per the procedure for total hardness to titrate with Standard Versenate. Record the number of ml Versenate = Vt. 4. Titrate 1 ml of mud filtrate obtained as per the standard fluid loss test procedure, using the standard total hardness test procedure. Record the number of ml of Versenate = Vf.

Calculations Total Gypsum (Calcium Sulfate) kg/m3 = 6.8 X Vt Excess Gypsum kg/m 3 = 6.8 Vt – 1.97 Vf X Fw Where Fw = volume fraction of water

1.13

MUD FILTRATE ALKALINITY


Acidity is one measure of alkalinity that is indicated by the pH. However, the nature and amount of other ions such as Carbonates or Bicarbonates can also effect mud filtrates alkalinity. For fresh water mud systems, these ions can be indicative of the rheological stability of such mud systems. Concentrations of either ion can result in high, low shear rate viscosity (Yield Point) and high, progressive Gel Strengths. Three methods can be employed for the determination of Carbonate and Bicarbonate concentration. The very common Pf / Mf method is restricted to mud systems having a low organic content, whereas the P1 / P2 method or Garret Gas Train may be used for better, more quantitative method, especially in the systems with high organic content.

Page-30

1.13.1 Pf / Mf Method


Equipment: 1. 2. 3. 4. 5. 6. 7.

Phenolphthalein Indicator Solution Bromo Cresol Green Indicator Solution Distilled Water N/50 Sulfuric Acid White Titration Dish Stirring Rod 1 ml Pipette

Test Procedure: 1. Using a 1 ml pipette, measure 1 ml of filtrate into a white titration dish. Dilute with distilled water. 2. Add 2-3 drops of Phenolphthalein Indicator. - if no color change occurs, then the Pf = 0; continue to step 4 - if a pink or red color develops, the Pf > 0; continue to step 3 3. Using a pipette, add N/50 Sulfuric Acid continuously while swirling or stirring until the sample changes from pink to colorless (or original filtrate tint). 4. The number of ml of N/50 Sulfuric Acid to reach this point is recorded as the Pf value. 5. To the sample, which has been titrated to the Pf end point, add 2-3 drops of Bromo Creosol indicator solution to obtain a light blue color. Continue titrating with swirling (or stirring) until the color changes from light blue to apple green (pH 4.0-4.5). This end point is recorded as the Mf end point. Calculations: Use the following table to estimate the Carbonate (CO3), Bicarbonate (HCO3), or Hydroxyl (OH) alkalinity present in the mud system. Pf / Mf Relation Pf = 0 Pf = Mf 2Pf = Mf 2Pf > Mf 2Pf < Mf

1.13.2 P1 / P2 Method

Bicarbonate (mg/L HCO3) 1220 X Mf 0 0 0 1200 (Mf – 2Pf)

Carbonate (mg/L CO3) 0 0 1200 X Pf 1200 (Mf – Pf) 1200 X Pf

Hydroxyl (mg/L OH) 0 340 X Mf 0 340 (2Pf – Mf) 0


Inorganic ions such as Borate, Silicate, Sulfide, and Phosphate ions can have a real effect on mud alkalinity. Additionally, organic compounds (ex: anionic organic thinners, fluid loss additives, or other Polymers) and their degradation by-products, may also affect the determination of the relative amounts of Carbonate, Bicarbonate, or Hydroxyl ion in solution. The P1 / P2 method eliminates these effects.

Page-31

Equipment: 1. 2. 3. 4. 5. 6. 7. 8.

Sodium Hydroxide Solution (0.1 N) Barium Chloride Solution Phenolphthalein Indicator Solution N/50 Sulfuric Acid White Titration Dish Stirring Rod Distilled Water Pipettes (1 ml)

Test Procedure:

1. Determine the Pf end point as outlined in steps 1-3 of the Pf/Mf method. If the Pf = 0, there are no carbonates present. 2. Place 1 ml of filtrate into a white titration dish, and dilute with distilled water. 3. Add a measured 2 ml of 0.1 N Sodium Hydroxide solution to convert all Bicarbonate to Carbonates. Check the pH – if it is less than 11.5, continue to add 0.1N Sodium Hydroxide in 1–2 ml increments, until the pH exceeds 11.5. Make a record of the total amount of Sodium Hydroxide added in this step. 4. Add a measured amount (2-4 ml) of Barium Chloride to precipitate all the possible Carbonates. Add 2-4 drops of Phenolphthalein solution and stir with a stirring rod. 5. Using a 1ml pipette, tritrate immediately to the end point with N/50 Sulfuric Acid. Record the number of ml’s N/50 Sulfuric Acid added as the P1 end point. 6. Place exactly the same amounts of 0.1N Sodium Hydroxide, Barium Chloride, and indicator into 25 ml of distilled water, and titrate to the end point using N/50 Sulfuric Acid, and record this as the P2 end point. Calculations: Pf = 0 There are no Carbonates present P1 > P2: mg/L Bicarbonates (HCO3) = 0 mg/L Carbonates (CO3) = 1200 [Pf – (P1-P2)] mg/L Hydroxyls (OH) = 340 (P1-P2) P2 > P1: mg/L Hydroxyls (OH) = 0 mg/L Carbonates (C03) = 1200 x Pf mg/L Bicarbonates (HCO3) = 1220 (P2 – P1) WARNING: The reagents may be hazardous to the health and safety of the user if inappropriately handled.

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1.13.3 GARRET GAS TRAIN METHOD (Carbonates) Return to Table of Contents Either of the above methods is still subject to some error and certain situations may required yet another method. The Garret Gas Train separates gas from liquid, thereby preventing contamination of the CO2 detecting Drager tube by the liquid phase. The CO2 Drager tube responds to the CO2 passing through it by progressively staining (purple) along its length as the hydrazine chemical and the CO2 react, causing a methyl violet indicator to turn purple. The stain length is dependent on the amount of CO2 present, and the total gas volume that passed through the tube. Consequently, for accurate results, the gas exiting the train must first be captured in a one litre gas bag to allow the CO2 to mix uniformly with the carrier gas. Then the contents of the bag are drawn through the tube using 10 strokes of the Drager hand pump. This will draw exactly one (1) litre of gas through the tube. Test Procedure: 1. Be sure the Gas Train is clean, dry, and on a level surface 2. With the regulator T-handle backed off, install and puncture a Nitrogen (N2) gas cartridge. 3. Add 20 ml distilled water to Chamber #1. (The chambers are numbered beginning at the regulator). 4. Add 5 drops of Octanol Defoamer to Chamber #1. 5. Install the top of the Gas Train and evenly hand tighten to seal all the O-rings. 6. Attach the flexible tubing from the regulator onto the dispersion tube of Chamber #1. 7. Inject with syringe an accurately measured sample of filtrate into Chamber #1. See table below: Drager Tube Identification

Carbonate Range mg/L 25-750 50-1500 250-7500

Sample Volume 10.0 2.5 1.0

Drager Tube Identification

Tube Factor

CO2 0.01 / A

25000

8. Flow carrier gas through the Gas Train for 1 minute to purge the system of air. Stop gas flow. 9. Install one end of a piece of flexible tubing onto the stopcock which is fitted directly into the gas bag. Have the gas bag full collapsed. Fit the other end of the tubing onto the outlet tube of Chamber #3. 10. Slowly inject 10 ml of Sulfuric Acid solution into Chamber #1 through the septum using the syringe and needle. Gently shake the Gas Train to mix acid with the sample in Chamber #1. 11. Open the stop cock on the gas bag. Restart Nitrogen flow gently and allow the gas bag to fill. When the bag is full, (DO NOT burst it) shut off and close the stop cock. Immediately proceed to the next step. 12. Remove the tubing from Chamber #3 outlet and re-install it onto the upstream end of the CO2 0.01% / A Drager Tube. (Observe that the arrow indicates the gas flow direction). Attach the Drager hand pump to the other end of the Drager Tube.

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13. Open the stop cock on the bag. With a steady hand pressure, fully depress the hand pump then release it so that the gas flows out of the bag, and through the Drager Tube. Operate pump 10 times. This should essentially empty the bag. 14. Observe a purple stain on the Drager Tube if CO2 is present. Record the stain length in the units marked on the Drager Tube. Calculations: mg/L CO2 = 25000 X Tube Stain Length ml of sample volume

Care and Cleaning: To clean the Gas Train, remove the flexible tubing and gas train top. Wash out the chambers using a brush with warm water and mild detergent. Use a pipe cleaner to clean the passages between the chambers. Wash, rinse, and then blow out the dispersion tube with air or nitrogen gas. Rinse the unit with distilled water, and allow to drain dry.

Garret Gas Train

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1.14

ALKALINITY OF THE MUD (Pm)


This test measures the alkalinity of the whole mud. When used in conjunction with the filtrate alkalinity determination, the amount of excess Lime present in the mud can be determined.

Equipment 1. 2. 3. 4. 5.

Titration dish Syringe, 3 ml Distilled water Phenolphthalein indicator solution N/50 (0.02 N) Sulfuric Acid

Test Procedure 1. 2. 3. 4. 5.

Measure 1 ml of a freshly stirred sample of mud into a titration dish using a syringe. Dilute the mud in the dish with about 50 ml of distilled water. Add 4-5 drops of Phenolphthalein indicator solution. If the sample does not change color, record the Pm as 0. If the sample turns pink, titrate rapidly with N/50 Sulfuric Acid until the pink color disappears.

Calculations Report the alkalinity of the mud, Pm as the number of ml of N/50 Sulfuric Acid added until the pink color disappears. Note: If the mud sample is deeply colored and the color change is hard to see, use 0.5 ml of mud, and report the Pm as the volume of Sulfuric Acid added X 2.0. If N/10 (0.1N) Sulfuric Acid is used, the Pm is reported as the volume of acid added to 1 ml of mud X 5.0.

1.15

SULFATE ION CONCENTRATION


Sulfate ions are present in many natural, ground and surface waters. In Bentonite based mud systems, flocculation and a high viscosity can result from Sulfate ion concentrations approaching or exceeding 2000 mg/L. A qualitative or more quantitative test can be performed to establish the Sulfate concentration.

1.15.1 QUALITATIVE TEST Equipment: 1. Dropper bottle of Barium Chloride. 2. Dropper bottle of strong Nitric Acid. 3. Test Tube.

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Test Procedure: 1. Place 2-4 ml of filtrate in a test tube and add a few drops of Barium Chloride. 2. Shake the tube gently, and observe the presence of a milky, white precipitate. This indicates the presence of Carbonates and/or Sulfates. 3. Add a few drops of Nitric Acid and shake again. If the precipitate dissolves and disappears, completely, only carbonates were present. If the precipitate remains, its intensity can be used for a qualitative estimate of the Sulfate concentration. Results: “Trace”

- the precipitate is barely discernable - less than 50 mg/L Sulfate ions are present

“Show”

- the precipitate is a translucent white suspension - up to 500 mg/L Sulfate ions are present

“Light”

- the precipitate is a milky white suspension - up to 1000 mg/L Sulfate ion are present

“Heavy”

- the precipitate is a heavy “curdly” white suspension - more than 1500 mg/L Sulfate ions are present - the precipitate could be diluted for a more accurate determination of the concentration

1.15.2 QUANTITATIVE TEST


One method of quantitatively determining the Sulfate ion concentration is with the use of the Hach Model SF-1 Sulfate Test Kit. 1. Fill the calibration tube to the top with filtrate to be tested. 2. Pour this sample into the mixing tube. 3. Add the contents of one Sulfaver IV powder pillow. Swirl to mix. A white, turbid precipitate will appear if Sulfates are present. 4. Allow to stand for 5 minutes. 5. Hold the calibrated tube in such a manner so that it can be viewed through the top. Slowly pour the prepared sample into the tube. Continue pouring until the image of the black cross on the bottom of the tube just disappears from view. At this point, the tube will appear as a uniform field of view. 6. Read mg/L of Sulfates (SO4) from the scale on the side of the calibrated tube. Note: The difference between mg/L and ppm is not significant until the Sulfate concentration exceeds 7000 mg/L. Warning: The reagents may be hazardous to the health and safety of the use if inappropriately handled.

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1.16

AMMONIUM SULFATE TEST ( Hach Ammonia Nitrogen Test Kit (N1-8) Return to Table of Contents

Sample Preparation Add 0.25 ml filtrate to a 100 ml graduated cylinder. Dilute with distilled water to the 100 ml mark. Cover with palm of hand and invert cylinder several times. From this 100 ml solution, pipette 1.0 ml to the 10 ml graduated cylinder. Dilute to the 10 ml mark with distilled water. Invert the cylinder several times. Fill one tube to the white line with this solution. Fill the other tube to the white line with distilled water. 1. Add 3 drops Nessler solution to each tube and swirl. Allow 10 minutes for color development. 2. Insert the filtrate containing tube in the right opening in the top of the color comparator. 3. Insert the distilled water sample in the left opening in the top of the color comparator. 4. Hole the color comparator up to a light such as the sky (preferable), a window of lamp and view through the two openings in the front. Rotate the color disc until a color match is obtained. Read the number in the scale window. Calculation: Ammonium Sulfate (NH4)2SO4, kg/m3 = 19 X number in scale window

1.17

SULFITE ION CONCENTRATION


In many mud systems, especially those which contain high levels of Salt, it is necessary to use an Oxygen scavenger to reduce the dissolved Oxygen content in the mud in order to reduce drill string corrosion to acceptable levels. One method of reducing Oxygen corrosion is with the use of an Oxygen seeking ion, like the Sulfite (SO3) ion, which will react with the dissolved Oxygen present in the drilling mud. In order to minimize Oxygen corrosion, it is necessary to maintain a residual Sulfite concentration in the drilling mud at all times. Usually, residual concentrations in the order of 300 mg/L or greater are required to reduced corrosion levels to an acceptable range. Corrosion results should always be verified with the use of corrosion rings. One method of determining the residual Sulfite concentration is with the use of the HACH Model SU-5 Sulfite Test Kit. The Sulfite concentration may be determined using mud or filtrate.

Equipment: Hach Model SU-5 Sulfite Test Kit

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Test Procedure: 1. 2. 3. 4.

Measure a sample by filling the sample bottle to the indicated mark, (10 ml). Add the contents of Sulfite #1 reagent powder pillow. Swirl to mix. Add the contents of one Sulfamic Acid powder pillow. Swirl to mix. Tritrate with Sulfite #3 reagent using the eye dropper, (low and high range Sulfite #3 reagent is available). Add the reagent drop wise with continual swirling of the sample until a permanent gray-blue color develops. Note the number of drops required to reach the end point.

Calculations:

mg/L Sulfites (SO3) = 0.64 X No. of drops “low” range Sulfite #3 mg/L Sulfites (SO3) = 6.4 X No. of drops “high” range Sulfite #3

Warning: The reagents contained in the kit are harmful. Avoid contact with eyes and skin. Do not ingest. Read warning on chemical container.

1.18

HYDROGEN SULFIDE CONCENTRATION


In many areas Hydrogen Sulfide is found by itself, or in association with hydrocarbons, especially gas. Hydrogen Sulfide gas (H2S) is not only very lethal, but also extremely corrosive. Therefore, when H2S is encountered in the mud, it must be reduced to acceptable levels so that it does not pose a health hazard, or create a drill string failure. The concentration of Hydrogen Sulfide present may be determined using the Hach Model HS-7 Hydrogen Sulfide Test Kit, or more quantitatively, using the Garrett Gas Train.

1.18.1 HACH H2S TEST Equipment Hach Model HS-7 Hydrogen Sulfide Kit Test Procedure 1. Fill the sample vial to the 25 ml mark with recently filter pressed filtrate from the mud to be tested. (If 25 ml is not available, use a known amount of filtrate and dilute to 25 ml using distilled water. Five or more ml of filtrate is recommended). Note: For most accurate results, the test should be performed using a recently obtained mud sample. If the sample has been aerated or allowed to stand for some time, much if not all of the Hydrogen Sulfide gas will be lost by aeration or oxidation.

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2. Place a circle of Hydrogen Sulfide test paper (lead acetate paper) inside the cap of the sample vial. 3. Add an Alka Seltzer tablet to the sample and IMMEDIATELY snap the cap containing the test paper onto the vial. 4. After allowing ample time for the tablet to dissolve, remove the cap and test paper. 5. Compare the color of the test paper with the color chart accompanying the test kit, and record the amount of H2S gas present. Calculations H2S Present = 25 X H2S recorded ml of filtrate used

1.18.2 GARRETT GAS TRAIN (H2S)


Equipment 1. 2. 3. 4. 5.

Garrett Gas Train with H2S Drager tubes, and floating ball flow meter Lead Acetate Hach paper discs as an alternative to Drager tubes (for a more qualitative test) Sulfuric Acid, 5N Dropper bottle with Octanol Defoamer or equivalent Hypodermic syringe (10 ml with 21 gauge needle)

Test Procedure 1. Be sure the Gas Train is clean, dry and on a level surface. Note: Moisture in the flow meter can cause the ball to float erratically. 2. With the regulator T-handle backed off, install and puncture a CO2 gas cartridge. 3. Add 20 ml distilled water to Chamber #1 (the chambers are numbered beginning at the regulator). 4. Add 5 drops of Octanol Defoamer to Chamber #1. 5. Measure the sample into Chamber #1 according to the following table: Drager Tube Identification Sulfide Range (mg/L) 1.5-30 3.0-60 6.0-120

Sample Volume

Drager Tube Identification

Tube Factor

10.0 5.0 2.5

H2S 100/a

15

60-1020 120-2040 240-4080

10.0 5.0 2.5

H2S 0.2% / A

600

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6. Select the proper Drager tube in accordance with the identification table. Break the tips from each end of the tube, and apply Lubriseal to each end. 7. Install the tube with the arrow pointing downward into the bored receptacle. Likewise, install the flow meter with the word “TOP” upward. Be sure the O-rings seal around the body of each tube. 8. Install the top on the gas Train, and evenly hand tighten to seal all O-rings. 9. Attach the flexible tubing from the regulator onto the dispersion tube of Chamber #1, and from the outlet tube of Chamber #3 to the Drager tube. 10. Adjust the dispersion tube of Chamber #1 to within 5 mm from the bottom. 11. Flow CO2 gas gently through the Train for 10 seconds to purge the system of air. Stop the gas flow. 12. Slowly inject 10 ml Sulfuric Acid into Chamber #1 through the septum using the syringe and needle. 13. Immediately restart CO2 flow. Using the regulator, adjust the flow so that the ball remains between the two lines on the flow meter tube. Note: One CO2 cartridge should provide 15-20 minutes of flow at the rate. 14. Observe a color change on the Drager tube if H2S is present. In the units marked on the tube, note and record the maximum darkened length before the front start to smear. Continue flow for 15 minutes, although the front may attain a diffuse, feathery coloration. On the high range tube, an orange color may appear ahead of the black front if sulfites are present. The orange region should be ignored when recording the darkened length. Calculations mg/L Sulfides = Tube Factor X Tube Stain Length ml Sample Volume

Care and Cleaning To clean the Gas Train, remove the flexible tubing and Gas Train top. Take the Drager tube and flow meter out of the receptacles, and plug with stoppers to keep them dry. Wash out the chambers using a brush with warm water and mild detergent. Use a pipe cleaner to clean the passages between the chambers. Wash, rinse and then blow out the dispersion tuber with air or CO2 gas. Rinse the unit with distilled water and allow to drain dry. Note: A lead acetate Hach paper disc fitted below the O-ring of Chamber #3 can be substituted for the Drager tube in the Gas Train. The lead acetate paper, although not preferred for quantitative work, will show the presence of Sulfides. WARNING: The reagents in this kit may be hazardous to the health and safety of the user if inappropriately handled. Please read all warnings before performing the test and use appropriate safety equipment.

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Garret Gas Train

1.19

HYDROGEN SULFIDE SCAVENGING ABILITY AND ZINC CARBONATE Return to Table of Contents

When Zinc Carbonate is used as a drilling mud additive to scavenge Hydrogen Sulfide (H2S) in a sour gas well, it is possible to obtain an estimate of the scavenging ability of the drilling mud, as well as the amount of Zinc Carbonate present. Quantitatively, the scavenging ability of the mud and therefore the amount of Zinc Carbonate present, can be determined using the Garret Gas Train. A more qualitative method to determine the amount of Zinc Carbonate present employs the Hach Hydrogen Sulfide test kit.

1.19.1 ESTIMATION of ZINC CARBONATE CONCENTRATION (Qualitative) Return to Table of Contents Equipment and Reagents 1. 2. 3. 4. 5. 6. 7. 8.

Hach Model HS-7 Hydrogen Sulfide Kit Filter Press Hamilton Beach mixer or equivalent Hypodermic syringe, 5 ml Fresh Sodium Sulfide (Na2S), stock solution – 100 gm Na2S/litre Concentrated Hydrochloric Acid (18%), or 5N Sulfuric Acid Distilled Water Octanol Defoamer or equivalent.

Test Procedure

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1. Using the hypodermic syringe, add 2.5 ml of Sodium Sulfide stock solution (Na2S) to 250 ml of mud, 2. Agitate the sample in the mixer at medium speed for 5 minutes. 3. Using the filter press, obtain at least 3 ml of filtrate for each test. 4. Place a circle of Hydrogen Sulfide test paper (lead acetate paper) inside the cap of the sample vial. 5. Measure 2 ml of filtrate into the sample vial using the syringe and dilute the sample with approximately 20 ml of distilled water. Acidify the solution with 2 drops of acid, quickly drop an Alka Seltzer tablet into the solution, and close the sample vial with the cap. 6. After allowing ample time for the tablet to dissolve, remove the cap and test paper. The presence of brown coloration on the lead paper indicated that the Zinc Carbonate concentration is less than 1.1 kg/m3. 7. If the acetate paper is white (negative), the Zinc Carbonate concentration is more than 1.1 kg/m3. In order to define the end point more accurately, repeat the entire test using an additional 2.5 ml of Sodium Sulfide stock solution each time until a brown coloration is apparent on the lead acetate paper.

Calculations Approximate kg/m3 Zinc Carbonate = 0.44 X Maximum Number Milliliters Sodium Sulfide Solution Used

1.19.2 H2S SCAVENGING ABILITY and ZINC CARBONATE CONCENTRATION Return to Table of Contents Equipment and Reagents 1. Garrett Gas Train with H2S Drager tubes and floating ball flow meter, and CO2 gas cartridges. 2. Sulfuric Acid, 5N 3. Dropper bottle with Octanol Defoamer or equivalent. 4. Hypodermic syringe with 21 gauge needle, 10 ml 5. 2, minimum 400 ml jars with lids 6. Osterizer blender, blade type, 10 speed 7. Filter press 8. Fresh Sodium Sulfide (Na2S) stock solution (100 grams Na2S per litre) Test Procedure 1. 2. 3. 4.

Label 2 jars, “A” and “B”. Measure 350 ml of drilling mud into jar “A”. Measure 350 ml of distilled water into jar “B”. Measure 20 ml of stock Sodium Sulfide (Na2S) solution into each jar. Close both jars and shake vigorously by hand for 30 seconds. Transfer the contents of jar “A” to the Osterizer mixing jar, replace the lid, and stir at the slowest speed for 15 minutes. Transfer the drilling mud – H2S system back to jar “A”. Note: Some drilling muds will thicken severely when the Na2S solution is added. If thickening occurs, add a dispersant from the rig stock at about 3 kg/m 3 (roughly a cone shaped pile on a dime). If thickening is observed during the first of a series of tests, the mud should be pretreated with a dispersant prior to a Na 2S addition.

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5. Extract 10 ml of dilute Sodium Sulfide (Na2S) stock solution from jar “B” and label this filtrate “B”. 6. Prepare the Garrett Gas Train for testing as outlined below. a. Be sure the Gas Train is clean, dry, and on a level surface. Note: Moisture in the flow meter can cause the ball to float erratically. b. With the regulator T-handle backed off, install and puncture a CO2 gas cartridge. c. Add 20 ml distilled water to Chamber #1 (the chambers are numbered beginning at the regulator). d. Add 5 drops of Octanol Defoamer to Chamber #1. e. Install the top on the Gas Train and evenly hand tighten to seal all O-rings. f. Select a high range Drager tube (H2S 0.2% / A tube factor is 1500) for installation. g. Break off the ends of the tube, apply Lubriseal to both ends and install the tube with the arrow pointing downward into the bored receptacle. Likewise, install the flow meter with the word “TOP” upward. Be sure O-rings deal around the body of each tube. h. Attach the flexible tubing from the regulator onto the dispersion tube of Chamber #1 and from the outlet tube of Chamber #3 to the Drager tube. Note: Use only latex rubber or inert plastic tubing. Do not clamp tubing. Unclamped tubing provides a pressure relief in the event the Gas Train is over pressured. i. j. 7.

8. 9. 10.

Adjust the dispersion tube of Chamber #1 to within 5 mm from the bottom. Flow CO2 gas gently through the Train for 10 seconds to purge system of air. Stop the gas flow. Proceed to the Garrett Gas Train operating procedure outlined below: a. Using the hypodermic syringe, inject 4.0 ml of filtrate (“B”) into Chamber #1. b. Slowly inject 10 ml 5N Sulfuric Acid solution into Chamber #1 through the septum using the syringe and needle. c. Immediately restart CO2 flow. Using the regulator, adjust the flow so that the ball remains between the 2 lines on the flow meter tube. One CO2 cartridge should provide 15-20 minutes of flow at this rate. d. Observe a color change on the Drager tube. In the units marked on the tube, note and record the maximum darkened length before the front starts to smear. Continue flow for 15 minutes although the front may attain a diffuse, feathery coloration. On the high range tube, an orange color may appear ahead of the black front if Sulfites are present. The orange region should be ignored when recording the darkened length. Label the darkened, stained length as “B”. Filter the mud (“A”) to obtain at least 4 ml of filtrate, label filtrate “A”. Clean the Gas Train as outlined below:

To clean the Gas Train, remove the flexible tubing and Gas Train top. Take the Drager tube and flow meter out of the receptacles, and plug with stoppers to keep them dry. Wash out the chambers using a brush with warm water and mild detergent. Use a pipe cleaner to clean the passages between the chambers. Wash, rinse and then blow out the dispersion tuber with air or CO2 gas. Rinse the unit with distilled water and allow to drain dry. 11. Run the Gas Train using 4.0 cm 3 of filtrate “A” (from the mud) repeating paragraphs 6 and 7. Label the darkened length “A”. 12. Be sure to clean the Gas Train after each test.

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Calculations mg/L H2S Scavenging Ability = 375 (B-A) kg/m3 Zinc Carbonate = 0.0037 X mg/L H2S Scavenging Ability WARNING: The reagents in the kit may be hazardous to the health and safety of the user if inappropriately handled. Please read all warnings before performing the test and use appropriate safety equipment. NOTE: The 100 gram/L Na2S solution can deteriorate with time. If the 4.0 cm3 of filtrate “B” results in Drager tube lengths which are too short, the filtrate volumes can be increased. If filtrate sample volume is indeed increased, the equation used to calculate H2S scavenging ability is changed from: mg/L H2S Scavenging Ability = 375 (B-A) to: mg/L H2S Scavenging Ability = 1500 (B-A) new volume (ml)

1.20

IRONITE SPONGE TEST


One method of scavenging H2S in a sour gas well is with the use of Ironite Sponge. The reaction of Hydrogen Sulfide with Ironite Sponge can easily be monitored in the field. The test is based on the fact that Ironite Sponge is attracted to a magnetic field, whereas Iron Sulfide (the reaction product of Ironite Sponge and Hydrogen Sulfide), is not attracted to a magnetic field. Equipment 1. Strong magnet (22 Decanewton, 50lb) pulling force. 2. Sand content tube and screen 3. Large container, e.g. 500 ml beaker

Test Procedure 1. Fill the sand content tube to water mark (100 ml) with a sample of mud to be tested. 2. Using water to dilute and rinse, transfer all the contents of the sand content tube to a large container (e.g. 500 ml beaker). 3. While holding the strong magnet against the container carefully, pour off all the diluted mud containing drilled solids, and the non-magnetic Ironite Sponge reaction products. The magnet should be place near the top of the container on the side that the diluted mud is being poured, in order to prevent the un-reacted Ironite Sponge from becoming part of the effluent. 4. Add more water and repeat step 3 until only Ironite Sponge and silty solids remain. At this point with the magnet in position, rapidly pour off the silty solids.

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5. Add more water and pour the remaining suspension back into the sand content tube through the sand content screen to remove any large solids or steel filings as a result of casing or pipe wear. Use additional water as a flush to ensure that all Ironite Sponge is transferred back. 6. Shake the sand content tube and then allow any remaining non-magnetic material to settle out while the magnet is rapidly being moved up and down along the side of the sand content tube. 7. Draw the Ironite Sponge to the bottom of the sand content tube and allow it to settle. Tap the sand content tube lightly, and then record the percentage of Ironite Sponge present subtracting the non-magnetic solids if they are present at the bottom of the tube. Calculations kg/m3 Ironite Sponge = 4 X % Ironite Sponge Recorded

1.21

POTASSIUM ION CONCENTRATION


When a drilling mud containing Potassium Chloride or Potassium Sulfate is used, the primary purpose is to prevent, or at least minimize hydration of water sensitive formations. Inhibition of hydration is provided by the Potassium ion (K+), which is attracted to negative charges appearing through the flat surface. Therefore, it is extremely important to know the Potassium ion concentration at all times in these mud systems. There are two different methods of determining the amount of Potassium in a mud system; one utilizing a hand crank centrifuge, and the other utilizing Potassium test strips.

1.21.1 HAND CRANK CENTRIFUGE METHOD


Equipment 1. Hand cranking centrifuge with 18:1 gear ratio 2. Two graduated 15 ml centrifuge tubes 3. 750 gm/L Sodium Perchlorate precipitating solution

Test Procedure 1. In order to balance the centrifuge, measure 14 ml of fresh water in the other centrifuge tube, and place it into the centrifuge. 2. Add 4.0 ml Sodium Perchlorate to 10.0 ml of filtrate to be tested in the centrifuge tube. A white precipitate which forms immediately indicates the presence of Potassium. 3. Invert slowly for 1 minute and place in the centrifuge. 4. Centrifuge for 1 minute at a cranking speed of 120 RPM (10 revolutions every 5 seconds). 5. Remove the centrifuge tube, and not the amount of centrifuged precipitate as the FLOC VOLUME in milliliters. Do not discard the centrifuged filtrate at the this point. 6. Determine the Potassium ion concentration from the table below:

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Note: For Potassium ion concentrations above 55,000 mg/L, save the centrifuge filtrate, clean the tubes, split the centrifuged filtrate evenly into each tube, add 4 ml Sodium Perchlorate to each tube, and centrifuge again. Record the total floc volume as the sum of the original floc volume, plus any additional floc volume obtained by double centrifuging.

Potassium Ion Concentration

Floc Volume (milliliters) 0.00 0.25 0.50 0.80 1.10 1.30 1.50 1.70 1.90 2.10 2.30 2.50 2.70 2.90 3.10 3.30

Potassium Ion Concentration (mg/L) 0 5000 7500 10000 15000 19000 24500 31000 38000 45000 53000 59000 65000 70000 75500 81000

NOTE: 5250 mg/L K+ is approximately 10 kg/m3 KCl

1.21.2 POTASSIUM TEST STRIPS


For Low Levels of Potassium (up to 1500 mg/L) 1. Insert the miniature test tube into the tube holder and add 10 drops of reagent solution. 2. Dip the test strip into the mud filtrate for 1 second. Remove the strip and shake excess filtrate from the strip. 3. Place the test strip in the miniature test tube containing the reagent solution for 1 minute. 4. Remove the test strip, and compare the color to that of the color scale. 5. Report filtrate Potassium in mg/L.

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For Levels of Potassium (1500-35000 mg/L) 1. Dilute the mud filtrate by adding 1.0 cm 3 of filtrate to a clean 25 ml graduate and adding distilled water to the 25 ml mark. 2. Place your thumb over the opening in the graduate, and invert the graduate several times to thoroughly mix the filtrate in the distilled water. 3. Proceed with the test as described above. 4. Multiply the results by 25. For Levels of Potassium Ranging up to 140,000 mg/L If the filtrate Potassium exceeds 35000 mg/L, further dilution will be required. The following chart shows the volume of filtrate, volume of distilled water, the multiplier, and the maximum concentration of filtrate Potassium which can be measured.

Filtrate Volume (cm3) 1.0 0.5 1.0

1.22

Distilled Water Volume (cm3) 24.0 24.5 99.0

Multiplier

25 50 100

Maximum Potassium (mg/L) 35000 70000 140000

POLYACRYLAMIDE (PHPA) POLYMER CONCENTRATION Return to Table of Contents

Very often, mud systems may utilize a Partially Hydrolyzed Polyacrylamide (PHPA) Polymer to provide or enhance inhibition by encapsulation of the Polymer around the hydratable clays that are encountered while drilling. In order for this method of inhibition to be effective, a residual PHPA concentration must be present in the drilling mud filtrate. Equipment 1. 2. 3. 4. 5. 6.

Hand Cranking Centrifuge, 18:1 gear ratio Two Graduated Centrifuge Tubes Floc Developer Solution Cresol Red Indicator Hydrochloric Acid, 0.2 N Sodium Hydroxide, 0.2 N

Test Procedure 1. Measure 12 ml of fresh water into test tube and place in centrifuge tube for balance. 2. Measure 10.0 ml filtrate in the graduated centrifuge tube. 3. Add 6 drops of Cresol Red indicator and with the tube covered, invert gently. A reddish purple color will develop to indicate a pH greater than 7.0. 4. Add 0.2 N Hydrochloric Acid drop by drop, inverting gently each time until the solution just turns an orange-yellow. 5. Add 2 ml floc developer solution.

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6. Invert the tube gently to mix for 15-20 seconds, and allow the solution to stand for 3-4 minutes. 7. Invert the centrifuge tube a few times and place it in the centrifuge. 8. Centrifuge for 1 minute at a cranking speed of 120 RPM (same as 10 revolutions every 5 seconds). 9. Remove the centrifuge tubes and note the amount of centrifuged precipitate as milliliters of precipitate. Calculations kg/m3 of Polyacrylamide (PHPA) = 1.4 X ml of Precipitate

1.23

DAP AND PHOSPHATE CONCENTRATION


In a low temperature and low pH environment, Diammonium Phosphate (DAP) can be used very successfully as an inhibitor to prevent or minimize hydration of water sensitive formations. The inhibiting Ammonium ion is difficult to measure, however, the phosphate and DAP concentrations are readily determined. Equipment 1. 2. 3. 4. 5. 6.

Manver indicator solution 2% Calcium Chloride solution Strong buffer solution White titrating dish Distilled water 1 ml pipettes

Test Procedure 1. Pipette 1 ml of filtrate into the titrating dish. 2. Add 7 drops strong Buffer, and 3 drops of Manver while swirling to mix. 3. Using 2% CaCl2, titrate to a distinct color change. Note: For low DAP concentrations, the color change is from dark purple to bright red. For high DAP concentrations, the color change is from dark blue to dark red. If a small amount of distilled water is used in the titration, the color change will be from wine to bright red, and purple to dark red for low and high DAP concentrations respectively.

Calculations kg/m3 DAP = 14.3 X ml 2% CaCl2 Added mg/L Phosphate (PO4) = 719 X DAP Concentration

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1.24

NITRATE ION CONCENTRATION


In some instances, after a potential producing horizon is drilled, it is desirable to know how much drilling mud filtrate has permeated the zone. In order to differentiate drilling mud filtrate from formation water, a “tracer” is often introduce into the drilling mud. The Nitrate ion is often used as such a tracer. Equipment HACH Model NI-11 Nitrate test kit, 0-50 mg/L Test Procedure To obtain accurate test results, please read carefully before proceeding. Samples containing above 50 mg/L Nitrate, Nitrogen can be tested by diluting the sample before running the test. For example, a 1 to 5 dilution can be made by using 1 ml of the water to be tested, and 4 ml of distilled water. Use the calibrated dropper provided in the kit for the dilution. The results of a 1 to 5 dilution are multiplied by 5 to obtain the correct mg/L Nitrate Nitrogen. The results of other dilutions will follow the same procedure as above; for example, the results of a 1 to 3 dilution would be multiplied by 3. A small portion of the Nitraver reagent will remain undissolved and fall to the bottom of the color viewing tube. This will not affect the test results, but should be rinsed from the tube between tests. WARNING: The reagents in this kit may be hazardous to the health and safety of the user if inappropriately handled. Please read all warnings before performing the test and use appropriate safety equipment. 1. Rinse a color viewing tube several times with the water to be tested. Then fill to the 5 ml mark. 2. Use the clippers to open 1 Nitraver 5 Nitrate reagent powder pillow. Add the contents of the pillow to the tube. Stopper the tube and shake vigorously for exactly 1 minute. 3. An amber color will develop if Nitrates are present. 4. Allow the prepared sampled to set undisturbed for 1 minute. Then place the tube of prepared sample in the right opening of the comparator. 5. Fill the other viewing tube to the 5 ml mark with some of the original water sample, and place it in the left opening of the comparator. 6. Hold the comparator up to a light source such as a window, the sky, or a lamp and view through the openings in front. Rotate the disc until a color match is obtained. Read the mg/L Nitrate Nitrogen (N) through the scale window. 7. Test results can be converted from mg/L Nitrate Nitrogen (N) to mg/L Nitrates (NO 3) by multiplying the scale reading X 4.4.

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1.25

DETERMINATION OF AMOUNT OF CORINOX IN MUD FILTRATE Return to Table of Contents

This method can be used to measure the amount of Organic Phosphorous Corinox corrosion inhibitor in a mud filtrate. Four (4) ml of filtrate are required to perform the test. If the endpoint is not reached after using 2 ml of Thorium Nitrate Tirtating solution, the test should be repeated using a 1 ml sample of filtrate. Test Method Thorium Nitrate Titration Test Procedure 1. Add a 4.0 ml sample of filtrate to a glass titrating bottle. Dilute the sample with 20 ml of distilled water. 2. Add one (1) drop of Meta-Cresol purple. 3. Add 1N Hydrochloric Acid (HCl) to reduce the pH to 2.5-3.5. Check the pH every 2-3 drops with the pH paper. DO NOT OVER ACIDIFY (typically 5-17 drops are required). 4. Add ten (10) drops of Fluoride Masking agent. 5. Add one (1) scoop of reagent #3 using a measuring scoop. If organic phosphorous compounds are present the sample will turn yellow. Calculations

Corinox / KD-700 (mg/L) = 2500 X (ml) Thorium Nitrate X (4 / Sample Size)

1.26

LOST CIRCULATION MATERIAL CONCENTRATION Return to Table of Contents

The following is a quick and easy method of determining the approximate concentration of lost circulation material (LCM) in a drilling mud. Test Procedure 1. Pour 1000 ml of mud through a sieve or strainer into a viscosity cup. 2. Place all the LCM material retained by the strainer into a clean viscosity cup. 3. Tap the cup sharply to level the contents. Read the volume in cubic centimeters (cm 3). Calculations LCM Concentration (kg/m3) = Volume of LCM (cm3) X 0.2 Example The LCM material strained from 1000 cm3 of mud filled the viscosity cup to the 300 cm 3 mark. 300 X 0.2 = 60 kg/m3 of LCM material in the mud

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1.27

BIOCIDE CONCENTRATION


When a Biocide or preservative is being used, it is important that the level be maintained adequately to prevent fermentation of certain products. This test offers a simple means of monitoring the level of Biocide in a mud system. The test involves a reaction between Sodium Sulfite and Glutaraldehyde that results in a change of pH. The amount of change is related to the amount of Biocide in the system. Equipment 1. 2. 3. 4. 5. 6.

Titration dish Pipettes Sodium Sulfite Solution N/50 Sodium Hydroxide N/50 Sulfuric Acid Phenolphthalein Solution

Note: The Sodium Sulfite solution deteriorates rapidly. If older than 30 days, it should be replaced with a fresh solution. Test Procedure 1. Pipette 2 ml of filtrate into a titration dish. 2. Add 2-3 drops of Phenolphthalein indicator. 3. Tritrate with N/50 Sulfuric Acid (if pink or red), or N/50 Sodium Hydroxide (if colorless) as required until a faint pink color remains. Add 1-2 drops of acid to dispel the color. 4. To the neutralized filtrate, add 1 ml of Sodium Sulfite solution. A red color will develop. 5. After approximately 30 seconds, titrate with N/50 Sulfuric Acid until the color just disappears. 6. Repeat steps 3 and 4 using distilled water, instead of filtrate. Calculations Biocide (litres/m3) = (ml Acid for Filtrate – ml Acid for Distilled Water) ml of Filtrate

1.28

BACTERIA DIPSLIDE TEST


Panatest dipslides are used to semi-quantitatively measure aerobic bacteria. The test procedure is very simple, but the results are not available for 24-48 hours, as the bacteria have to incubate inside the sealed tubes.

Equipment The test slides, tubes, and comparison chart are supplied as a kit.

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Test Procedure 1. Remove the white plastic cap seal. 2. Remove the slide from inside the tube, without touching the lower, pale yellow portion of the slide. 3. Immerse the lower portion of the slide in a sample of mud for approximately 10 seconds. 4. Remove the slide from the mud and allow to drain for approximately 10 seconds. Do not wash or rinse the slide. 5. Replace the slide in the plastic tube and seal with the white cap. 6. Complete the sample details on the label attached to the plastic tube. 7. Keep the tube upright and incubate for 24-28 hours at 30-37 degrees C. 8. At the end of the incubation period, compare the slide with the comparison chart on the underside of the test kit lid. 9. Record bacteria as organisms per ml.

Note: Dispose of the used slides by incineration. Do not open test tubes until they are required for use. Do not open used tubes after the incubation period.

1.29

POLYGLYCOL CONCENTRATION


Polygylcols can be added to drilling fluids as a primary shale inhibitor. The Glycol will slowly deplete from the drilling fluid as it is adsorbed into the shale formations as drilling progresses. This test procedure can be used to measure the concentration of different types of Glycols in a drilling fluid system.

Equipment 1. API standard retort kit, 50 ml is preferred for accuracy. It must be fitted with a temperature control, which will permit heating at 150 degrees C (302 degrees F) and 510 degrees C (950 degrees F).

Test Procedure 1. Place a known volume of mud in the loser part of the retort cell, It is important that this sample contains as little entrained air as possible. Insert fine steel wool, as required into the upper part of the cell. 2. Assemble the cell and seal the threads with a silicone high temperature grease to reduce leakage through the threads. 3. Set the temperature controller to 150 degrees C. Heat the retort until all the water has been collected (approximately 90 minutes) 4. Note this volume as V1. 5. Re-adjust the temperature to 510 degrees C, and continue to distil over the remainder of the liquid phase. 6. Note the final volume as V2.

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Calculations Volume Glycol % = (V2 – V1) X 100 Sample Volume (ml)

Note: The presence of other liquids with high boiling points, such as lubricants, will interfere with the result of this test.

1.30

STABLE-K CONCENTRATION


Many KCl clay-stabilizing substitutes determine residual concentrations of the product by an indirect method. Typically these methods will analyze for counter ions of the substance that is providing the clay stabilization. While this method will work if both the clay stabilizer and the counter ion are adsorbed by the clay. If substitution of Sodium in the clay lattice occurs, the counter ion will stay in solution. If this clay stabilization mechanism is prevalent, then analysis of the mud using the countered ion method will show levels of clay stabilizer much higher than is actually present. One way to avoid this inaccuracy is a direct method of analysis. The procedure is designed to determine the available concentration of Stable-K. Since drilled solids will contain some clays, some of the Stable-K will be tied up with these solids. Stable-K that is tied up with the solids is unavailable to provide clay stabilization. Due to its unique structure, analysis of Stable-K by a direct method is possible. This method is able to distinguish between total Stable-K concentrations and available Stable-K concentrations using standard mud kit apparatus. For most purposes, determining available Stable-K concentrations should be sufficient. If residual concentrations of Stable-K are much lower than expected, determining the total concentration of Stable-K will aid in assessing whether the product is being consumed downhole or in the drilled solids. Equipment 1. 2. 3. 4. 5. 6. 7.

8N KOH Solution N/50 Sulfuric Acid Phenolphthalein Indicator Solution Mud Retort 10 ml Pipette 50 ml Beaker Steel Wool

Test Procedure Available Stable-K: 1. Collect a minimum of 4 ml or a maximum of 9 ml of filtrate from the fluid loss test. Record the number of ml of filtrate. The more filtrate that is collected, the more accurate the results will be. 2. Add 1 ml of 8N KOH to the filtrate, and bring to a total volume of 10 ml (if necessary) using distilled water. 3. Remove the retort assembly from the insulator block if required. Remove the lower mud chamber from the retort assembly and thoroughly clean with the spatula provided.

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4. Pack the upper chamber of the retort assembly with steel wool. Failure to pack the upper chamber with steel wool will result in transfer of the KOH into the receiving vessel, invalidating the results. 5. Transfer the filtrate to the mud chamber of the retort assembly. Place the leveling lid on the assembly and wipe off any excess fluid. There should be minimal if any excess fluid. 6. Grease the threads of the mud chamber with a high temperature grease, and screw the mud chamber into the upper chamber, tightening with the spatula provided. 7. Place a 10 ml graduated cylinder under the condenser tube. Plug in the retort and continue heating until the light goes off. (Fluids may appear to have stopped coming form the condenser tube prior to this, however more accurate results are obtained by proceeding until the pilot light goes out). 8. Transfer the distillate from the 10 ml graduated cylinder into a 50 ml beaker. Rinse the 10 ml cylinder with distilled water, and transfer to the 50 ml beaker. Bring to a total volume of approximately 30 ml with distilled water. 9. Add 2 drops of phenolphthalein to the solution. If Stable-K is present, the solution should tune to a pink color. If the solution remains clear, then no Stable-K is present. 10. Fill a 10 ml pipette to the 10 ml mark with N/50 Sulfuric Acid solution. Add dropwise to the solution from Step 9 while swirling until the color changes form pink to clear. Be sure that all traces of pink color are removed form the solution. Record the ml. of N/50 Sulfuric Acid required. Total Stable-K: 1. Add 9 ml of air free drilling mud to a 10 ml graduated cylinder. Bring to a total volume of 10 ml with 8 N KOH solution. Invert and mix the solution. 2. Follow Steps 3 through 10 of the available Stable-K procedure. Calculations: 1.

Available Stable-K: litres/m3 Available Stable-K in Water Phase = (ml N/50 Sulfuric Acid) X 3.65 ml of filtrate collected litres/m3 Available Stable-K in Mud = litres/m3 Available Stable-K in Water Phase X Volume Fraction in Mud

2. Total Stable-K: litres/m3 Stable-K in Mud = (ml N/50 Sulfuric Acid) X 0.406 Notes: A 9 ml filtrate sample with 3 litres/m3 Stable-K will take approximately 7.4 ml of N/50 Sulfuric Acid. Smaller filtrate samples will take proportionately less; e.g.: a 6 ml sample will require 6/9 as much N/50 Sulfuric Acid. Higher loadings of Stable-K require proportionately more N/50 Sulfuric Acid; e.g. at 6 liters/m3, 9 ml of filtrate will take approximately 14.8 ml of N/50 Sulfuric Acid. If the results are unexpectedly high, then it is likely that some of the fluid from the mud chamber “bumped’ over to the condenser without distilling. If this is the case the retort should be allowed to cool, then dismantled and repacked with new steel wool. The test should be rerun to verify results. Note: Fluid additives containing Ammonia Salts and organic amines will interfere with this test.

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1.31

SODIUM SILICATE CONCENTRATION


For the Silicate mud systems, there is one specific additional test to measure the level of Sodium Silicate in the mud. The test is described below. If KCL (Potassium Chloride) is used, it is normally measured by the conventional centrifuge method with a factor incorporated to account for Silicate precipitation in the filtrate. Due to the attraction of Silicate to the semi-permeable membranes of ion selective probes, unreliable readings are obtained, while the centrifuge test method was shown to give reliable and repeatable results. Silicate Test Methods: There are two methods for testing the Silicate level in the system. 1. Hach Color Test Method 2. Titration Method Both methods should be available on the rig, however the Hach Test method has a selfcontained kit, which is easy to use, and is the preferred method for oilfield purposes. The titration method is more suited to laboratory situations. 1. Hach Color Test Method This test kit is complete with instructions and chemical reagents to test the filtrate for Silicate, The result is indicated in grams per litre or SiO2. With a density of l.475 S.G. for Ancosil and an activity of 3O.3% by weight SiO 2, % by volume Sodium Silicate = g/L SiO2 + 0.2237 2. Titration Method Due to the affinity of SiO2 to glass, the titration’s should be carried out in plastic beakers. If this is not possible, the beakers must be washed out thoroughly after use. This procedure describes the method for determining Silica (SiO2), by titration. The test is in two stages, the first determines the Sodium Oxide (Na2O) alkalinity which is due in part to the molar ratio of Na2O to SiO2 present in the Silicate product, the second to determine Silica. The Silica is reacted with Sodium Fluoride which is then titrated with strong acid. Equipment: 1. 2. 3. 4. 5.

pH meter with Calomel electrode Balance, accurate to 0.1 gram Magnetic stirrer complete with small stir bar 2 ml and 5 ml pipettes 100 ml beakers

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Reagents: 1. 2. 3. 4. 5. 6.

Distilled Water 0.2 N Hydrochloric Acid 2.0 N Hydrochloric Acid Methyl Red Indicator Solution Sodium Fluoride, Reagent Grade pH Buffers; pH 4.0 and pH 10.0

Procedures: Blank Titration: A blank titration is first performed to compensate for Silica present in the reagents. 1. 2. 3. 4 5

Pipette 5 ml of distilled water into a small beaker. Add I drop of methyl red. Add 0.2 N Hydrochloric Acid until the color first changes to pink. Add I gram of Sodium Fluoride. The color changes to yellow. Titrate with 2.O N Hydrochloric Acid to a pink color change, at pH 6.0 Record the amount of acid used ( Vol. A).

Alkalinity (Sodium) Content: 1. Ensure the pH meter is calibrated. 2. Pipette 5ml of distilled water into a small beaker and add I drop of Methyl Red indicator. 3. Set the beaker on a stirrer, and insert the pH electrode. The indicator solution is used as a guide, but accurate measurements are against the pH value. 4. Add a few drops of 0.2N Hydrochloric Acid, until the color is pink. 5. Pipette 2 ml of filtrate into this beaker. The color changes to yellow. 6. Titrate with 0.2N Hydrochloric Acid to pH 5.5, where the color change to pink is noted. 7. Record the ml’s of acid used ( Vol. B). Silica (SiO2) Content: 1. To the sample titrated above, add I gram of Sodium Fluoride. The color changes to yellow, and the pH will rise to 8.0-9.0. 2. Titrate with 2.ON Hydrochloric Acid to pH 6.0, and record the ml’s of acid used ( Vol. C). Calculations: Alkalinity: For a 2ml sample: Na2O (mg/L) = 31000 X (Vol. B) X 0.2 2 Where Vol. B is the volume of 0.2N Hydrochloric Acid used

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Silica ( SiO2): For a 2nd sample: mg/L SiO2 = 15000 X N{ (Vol. C) – (Vol. A)} 2

g/L SiO2 = 15 X N{ (Vol. C) – (Vol. A)} 2

Where Vol. C is the volume of 2.O N Hydrochloric Acid used in the titration, Vol. A is the volume of acid used in the blank correction ( typically <0. I ml), and N is the normality of the acid ( 2N). To convert g/L SiO2, to % by volume Sodium Silicate in the system: % volume Sodium Silicate = g/L SiO2 X 0.2237 Where the S.G. of Sodium Silicate is 1.475, with an SiO2 activity of 30,3% by weight Test method for K+ (Potassium) Ion: As indicated above, the K+ ion should be measured using the centrifuge method as outlined in Section No. 1.21.1. In order to account for precipitated Silicate it is necessary to perform a control centrifuge test with the standard volume of filtrate, adding 3 ml’s of water instead of the Sodium Perchlorate. This will indicate the amount of suspended Silicate which may have passed through the filter paper. When this is centrifuged, the volume of precipitate should be measured. (Vc) The Potassium should be centrifuged in the conventional way, and the total filtrate measured. (Vt) The volume of Silicate precipitate should be subtracted from this volume, and this final volume used to quantify the level of Potassium. (VK+) Volume of filtrate to determine Potassium = Vt - Vc


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TABLE OF CONTENTS – CHAPTER 2 Return to Glossary

Chapter 2

Water Base Mud Systems Return to Table of Contents

TOPICS

2.1

2.2

2.3 2.4 2.5

2.6 2.7 2.8 2.9 2.10 2.11 2.12 2.13

PAGE

SPUD MUDS 2.1.1 Water / Native Spud Muds 2.1.2 Water / Gel Lime Slurry 2.1.3 Bentonite Slurry 2.1.4 ABI High Yield Bentonite Slurry Water Drilling 2.2.1 SAPP Water / Drilling Detergent 2.2.2 Flocculated Clear Water Drilling Gel Chemical Systems Dispersed Gel Chemical Systems Potassium Based Mud Systems 2.5.1 Potassium Chloride (KCl) Muds 2.5.2 Potassium Sulfate (K2SO4) Muds 2.5.3 Potassium Formate (KCOOH) Muds Ammonium Sulfate Mud Systems GYP Mud Systems Saltwater Mud Systems Clay Free Polymer Muds (“Clear Fluid”) Stable-K / “K2” Mud Systems Polyglycol Mud Systems Silicate Mud Systems Mixed Metal Hydroxide (MMH) Mud Systems

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1 1 1 2 2 3 3 4 7 9 11 12 16 18 18 21 23 27 28 30 32 37

CHAPTER 2 WATER BASE MUD SYSTEMS

Before building a mud system, a complete analysis of the make up water should be made. If the water contains excess Calcium, it should be reduced to 40 mg/L of less with additions of Soda Ash. Magnesium in the make up water can also be removed by increasing the pH to 10.5+ if needed. The salinity of the water should also be checked, and noted if excessively high. The chlorides should be below 1000 mg/L for optimum yield of Bentonite. If the make up water contains above 7000 mg/L of Chlorides, it may be necessary to prehydrate Bentonite in fresh water.

2.1

SPUD MUDS

2.1.1

WATER / NATIVE SPUD MUDS

In many areas of Western Canada, the wells are spudded in with water. In many of these areas, the shallow formations contain significant amounts of Bentonite clay or shale. The viscosity increases naturally with the incorporation of Bentonitic or swelling clays into the water. The viscosity builds with continued circulation. Small amounts of Bentonite, Caustic Soda, or Lime may be added to increase the viscosity further if required. This system is very economical.

2.1.2

WATER / GEL LIME SLURRY


Used extensively throughout Western Canada as a cost effective method of drilling surface hole. The system is made up as follows: 1. Fill the earthen pits with water, or if a conductor pipe is set, fill the mud tanks with water. Maintain the circulating volume at a minimum to keep treating costs to a minimum for drilling the surface hole. 2. Check the hardness and salinity of the make up water. If the Calcium content is above 40 mg/L, then treat out the excess hardness with Soda Ash as required. Note: To determine the amount of Soda Ash required to treat out the total hardness, use the following formula. Soda Ash Required (kg/m3) = Total Hardness, mg/L X 0.0004 2.85 3. Normally the well is spudded in with water allowing native clays to build viscosity. 4. If a further increase in viscosity is required to clean the hole, add approximately 0.75-1.0 kg/m3 of Caustic Soda through the chemical barrel to increase the pH to ±9.5.

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5. Add Bentonite through the hopper at approximately 5-7 min’s/sx. until a viscosity of ± 45-50 sec/L is obtained.

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6. For a further increase in funnel viscosity (in particular an increase in Yield Point), or if the viscosity has to be increased prior to running the surface casing, small amounts of Lime can be added to flocculate the Bentonite. Normally 1 sack of Lime is added for every 15-20 sacks of Bentonite that was initially mixed to build the slurry, or a concentration of ±1.5 kg/m3. The Lime should be added through a chemical barrel. 7. The Bentonite / Lime slurry is normally diluted with water, or discarded when the surface hole is finished. 8. If mud rings are a problem in the area, it is recommended that no Lime be added, as it may cause the clays to swell, and create mud rings.

2.1.3

BENTONITE SLURRY


A Bentonite slurry is generally premixed prior to spudding, and is used in the deeper wells where more than 2-3 days is expected to drill surface hole. The system is made up as follows. 1. The mud tanks should be clean, and filled ½-¾ full with fresh water. Keep the surface volume to a minimum in order to keep the treating costs as low as possible. 2. The Calcium and salinity of the make up should be checked. Treat out soluble Calcium to 40 mg/L or less with additions of Soda Ash, as required. If the make up water contains above 7000 mg/L of Chlorides, another water source will be required. 3. Add approximately 0.75-1.0 kg/m3 of Caustic Soda through the chemical barrel to increase the pH of the water to 9.0-9.5. 4. Add approximately 65-75 kg/m3 of Bentonite at 5-7 min’s/sx. to increase the funnel viscosity to ±40-45 sec/L. Let the Bentonite slurry hydrate as long as possible prior to spudding the well. As drilling progresses, increase the viscosity as required with further additions of Bentonite to ensure adequate hole cleaning is being maintained. The mud density and solids content should be maintained as low as possible with water dilution, dumping the sand trap and/or shaker compartment, and utilizing all the solids control equipment of the rig. It may be possible depending upon the rig tank and/or sump design for water drilling, to save the surface hole mud for future use after drilling with flocculated water.

2.1.4

ABI HIGH YIELD BENTONITE SLURRY


ABI High Yield Bentonite is a premium grade of Bentonite that has been peptized to achieve approximately double the viscosity of regular Bentonite with the same amount of product mixed. This product is ideal for spudding in with a larger surface hole size, i.e.: 444.5 mm hole or larger, and where high pump outputs are required to achieve a high enough annular velocity to drill the larger surface hole size. The system is made up as follows. 1. Fill the mud tanks ½-¾ full with fresh water. 2. It is important to check the Calcium make up of the water with type of system. Note: Calcium free make up water will be required. A minimum of 1-2 sacks of Soda Ash should be mixed to the make up water prior to adding the High Yield Bentonite.

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3. Increase the pH of the water to 9.0-9.5 with Caustic Soda. 4. Add ABI High Yield Bentonite through the hopper at approximately 5-7 min’s/sx. to increase the funnel viscosity to ±40-45 sec/L. Let the High Yield Bentonite slurry hydrate as long as possible prior to spudding the well. As drilling progresses, increase the viscosity as required with further additions of HYB to ensure adequate hole cleaning is being maintained. The mud density and solids content should be maintained as low as possible with water dilution, dumping the sand trap and/or shaker compartment, and utilizing all the solids control equipment of the rig. The purpose of any spud mud is to drill surface hole as economical as possible. Mud volumes and additions should be minimized to maintain treating cost as low as possible.

2.2

WATER DRILLING

2.2.1

SAPP WATER / DRILLING DETERGENT


SAPP (Sodium Acid Pyrophosphate) is a very powerful thinner having a pH of 4.0. Drilling Detergent is an anionic, surface wetting agent (surfactant) that comes in both a liquid (Drilling Detergent “L”) and a powdered (Drilling Detergent “P”) form. Both products are used primarily of shallow water drilling or on surface hole to minimize mud rings, and bit balling. Mud rings and bit balling are caused by a rapid build up of native Bentonitic solids, that are not removed froth the wellbore quickly enough. In some instances, the build up of solids and viscosity is rapid enough to plug off the flowline. Generally SAPP water drilling is only recommended for water drilling to a maximum of 600-700 metres of open hole. This will depend upon the sump volume and design. 1. Fill the sump ½-¾ full with fresh water. Drill out the cement and shoe with water while circulating the sump. If circulating the mud tanks, dump as necessary to maintain the mud density as low as possible. 2. Treat out any excess Calcium from the cement cuttings with 1-2 sacks of Sodium Bicarbonate. 3. Drill ahead with water, adding 1 viscosity cup (± 1 kilogram) of SAPP (dry) in the box end of the drill pipe every connection to prevent bit balling and the build up of mud rings. 4. At the same time, trickle in or add small amounts of Drilling Detergent “L” or Drilling Detergent “P”. Normally add Drilling Detergent “L” down the trough to the suction tank at a concentration of 0.2-0.6 litres/m3. If Drilling Detergent “P” is being used, add in a concentration of ±0.75-1.5 kg/m3. If mud rings become a severe problem, additional treatments may be necessary. Mix ½-1 sack of SAPP into a chemical barrel full of water, and add as close to the pump suction as possible. Additional treatments of Drilling Detergent may also be required to disperse any mud rings. Return to Table of Contents

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There must be sufficient volume in the sump, and constructed properly with a dyke for SAPP water drilling. The mud density should be maintained as low as possible; i.e. 1050 kg/m 3 with further additions of water. An annular velocity of 50-55 metres/min. is recommended. The easiest method to prevent mud rings is to circulate the hole long enough between connections, or prior to surveys or trips, etc., maintain the annular velocity high enough, and keep the fluid sufficiently dispersed with SAPP to minimize and rapid build up of native solids. Some drilling contractors may object to adding SAPP down the drill pipe due to its acid nature. If so, then add the SAPP through a chemical barrel into the suction tank as required.

2.2.2

FLOCCULATED CLEAR WATER DRILLING


There are 2 basic requirements essential to the success of a flocculated clear water drilling system:  

Adequate water volume Sufficient settling space and time

The flocculated particles formed in this system are bulky and very light. The settling pits, or mud tanks used must have sufficient area to handle the large volume of solids which will settle. Fluid movement must be arranged so that sufficient time is allowed for settling of solids to prevent recirculation. It is possible to utilize this system with either mud or floc tanks, or an earthen pit or sump. However for large intervals of Bentonitic shales or clays (more than 1000-1500 metres of 222 mm hole), an earthen pit or sump with a minimum of 300-400 m3 of water is recommended for optimum results. As a rule of thumb, if you take the anticipated mud up depth, subtract the surface casing depth from that value, and multiply that factor by 0.4. This will equal the minimum amount of water in cubic metres that will be required to successfully drill the interval with clear water. Example:

Surface Casing Depth: 300 metres Anticipate Mud Up Depth: 1200 metres

Minimum Amount of Water Required = (1200-300) X 0.4 = 900 X 0.4 = 360 m3 of water This is only a rule of thumb, but is fairly accurate in the field. Ideally, a wall should be constructed between 2 pits, with a dyke or weir located to provide a maximum circulating distance between the flowline and suction. The pits should be constructed for a fluid depth of approximately 1.5-2.0 metres, particularly in the case of the suction pit, where the suction should be as close to the surface as possible. If absolutely necessary, a flocculated system can also be used in properly arranged rig or floc tanks. For best results, a minimum surface vole of 100 m 3 is recommended. Again, if extensive intervals (in excess of 1000-1500 metres of 222 mm hole) is to be drilled, a larger volume would be beneficial, but not absolutely necessary. A minimum of 2 tanks with compartments should be required to flocculate in the tanks.

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Return to Table of Contents Flow between the tanks must be over the top with no possibility of bottom communication. Flow patterns should be arranged to provide maximum surface distance between the shale shaker and the suction, Tanks must be constructed with bypass troughs to allow cleaning of individual compartments. 1. Fill the sump or tanks with clear water. 2. Drill out the surface casing shoe and cement with water. Do not treat out any excess Calcium from the cement as it will assist in flocculation. 3. Circulate the sump, and add approximately 1-2 kg/m3 of Envirofloc and 2-4 kg/m3 of Gypsum to the water to increase the Calcium content of the water to ±300-400 mg/L. Add Envirofloc and Gypsum in a 1:2 ratio respectively over a circulation. Note: Envirofloc (Calcium Nitrate) and Gypsum (Calcium Sulfate) are the most commonly used products to increase the Calcium ion of the sump throughout Western Canada. Gypsum is normally added in 2:1 ratio with the Envirofloc to cut down on the costs. Envirofloc is very soluble is water (even in winter when the water is cold), and goes into solution very easily and quickly. Both products do not contain any Chlorides, therefore are environmentally acceptable. Calcium Nitrate (Envirofloc) is a common fertilizer, which can be “land farmed” while drilling ahead, or after the well is finished. There are other “Salts” or products that can be utilized to increase the effectiveness of the flocculant(s). These products and concentrations are as follows: Gypsum Alone: Ammonium Sulfate: Potassium Chloride: Potassium Sulfate: Calcium Chloride:

3-5 kg/m3 10 kg/m3 10 kg/m3 10-15 kg/m3 1-3 kg/m3

Note: These concentrations may vary somewhat, depending upon the sump or tank volume and size. 4. Begin adding a flocculant when the first cutting reaches the shale shaker. There are many flocculants available to settle the solids. One common one is Mud Floc II. Mud Floc II is readily dispersible in water, and therefore does not have to mixed with diesel first. Add 1 (2 lb.) bottle of Mud Floc II into a chemical barrel full of water. 5. The chemical barrel should be located as close to the flowline discharge as possible. If possible, a chemical agitator should be clamped onto the barrel to provide for optimum mixing. 6. Normally, add 1 Mud Floc / water mixture for every 20-30 metres of new hole drilled (based on 200 or 222 mm hole). This mixture must be added continuously. This takes a conscientious effort from the derrickman, as clear water can only be obtained if the flocculent / water mixture is added uniformly throughout the interval, particularly in the wintertime. Return to Table of Contents

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Return to Table of Contents Other flocculants that are available is listed below. The majority of these products are added in a similar fashion. The concentration levels may vary – refer to the product data on each of these products. Alcomer 110RD Alcomer 120L Alkapam C-1803 Enkapsafloc Percol 351

Alcomer 120P Alkapam A-1103D and A-1703D Alkapam N-1003D Percol 338 Percol 728

7. 1-2 sacks of Envirofloc and 2-4 sacks of Gypsum should be added every tour, to maintain the Calcium level at a minimum of 200-400 mg/L. 8. If the water becomes “dirty” or “cloudy” at the suction, increase the concentration of Envirofloc and Gypsum by adding ±5-10 sacks over a circulation. The flocculant will also have to be increased along with added dilution to clear up the water. 9. The following properties should be maintained and monitored throughout the clear water drilling interval. Mud Density: Funnel Viscosity: pH: Calcium:

1000-1020 kg/m3 26-28 sec/L Neutral 200-400+ mg/L

Caution: 1. While drilling with water, do not stop the tools for any extended period of time. Annular velocities of 50-55 metres/min. are recommended. 2. When cleaning out fill after trips, do not stop to break down stands. Break down prior to reaming or picking up from the pipe rack. 3. Circulate for 15-20 minutes, or “bottoms up” prior to trips, in order to clean the hole of cuttings. Watch closely for tight hole on connections, or trips. 4. When starting the pump, it is important that the annular flow is not restricted, as this may result in induced fractures to the formation. 5. Any signs of hole instability, mud up immediately. Additions of Envirofloc and Gypsum should be discontinued ±50 metres prior to mud up depth. Additions of flocculant should be discontinued ±20-30 metres prior to mud up depth. Clear fluid from the circulating sump may be used for mud up after treating the Calcium content to < 40 mg/L with additions of Soda Ash as required. Try to reduce as much volume in the sump as possible. If excessive torque, drag or tight hole becomes a problem while clear water drilling, the hole may be “slugged” with a high viscosity pill of prehydrated Bentonite. This will ascertain if hole cleaning is the problem. If a hole cleaning problem is apparent, begin mud up procedures immediately. Return to Table of Contents

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2.3

GEL CHEMICAL SYSTEMS


Gel Chemical mud systems are the most common systems used throughout Western Canada. They provide good lifting capacity, favorable shear thinning characteristics, good fluid loss control, and are economical for the operator. Make Up: 1. For best results, the mud system should initially be free of all drilled solids. Ensure the mud tanks are thoroughly cleaned before mudding up. 2. Fill the mud tanks ½ to ¾ full with fresh water, or water from the sump from the clear water drilling section. 3. Water properties are important. Excessive Salt or hardness in the make up water will interfere with the hydration of the Bentonite. Check the hardness of the make up water, and lower the Calcium to < 40 mg/L with additions of Soda Ash. The salinity of the water should also be checked, and noted if excessively high. The chlorides should be below 1000 mg/L for optimum yield of Bentonite. If the make up water contains above 7000 mg/L of Chlorides, it may be necessary to prehydrate Bentonite is fresh water. 4. Adjust the pH of the make up water to ± 9.5 with approximately 0.75-1.0 kg/m3 of Caustic Soda through the chemical barrel. Add the Caustic Soda to the make up water prior to adding the Bentonite. 5. Add Bentonite through the hopper at 5-7 min’s/sx. The rate should be slow enough and agitation vigorous enough, that “clogging”, balling, or waste of clay does not result. The initial yield depends in part on the quality of the surface mixing equipment, but normally the mud will thicken with time and agitation. As a rule of thumb, 60-70 kg/m3 of Bentonite should produce a mud with a funnel viscosity of approximately 38-42 sec/L. 6. A natural fluid loss of approximately 12.0-15.0 cm3 should be obtained from the Bentonite slurry. Normally, a fluid loss in this range is sufficient to begin drilling.

Maintenance: 1. The mud density should be maintained as low as formation pressures will permit. These systems can be weighted up with additions of Barite or Calcium Carbonate if required. 2. The funnel viscosity should be maintained just high enough for effective hole cleaning with additions of Bentonite as required. 3. The Plastic Viscosity (PV) will correlate with the solids content of the mud, and should be maintained as low as possible with dilution, dumping, and maintaining effective use of the solids control equipment. 4. Generally, the Yield Point (YP) will run approximately ½ that of the Plastic Viscosity in a conventional Gel Chemical mud system. The Yield Point can be increased with further additions of Bentonite, or a viscosifying Polymer such as Kelzan XCD Polymer if added hole cleaning is needed. 5. Gel Chemical mud systems are not considered to be very corrosive in nature. To obtain the maximum hydration from the Bentonite, the pH should be maintained between 9.0-10.0 with additions of Caustic Soda as required. The Mf alkalinity should be approximately twice as high as the Pf alkalinity. If there is a large disparity between the Pf and Mf alkalinity, a build up of Carbonate and/or Bicarbonate ions may be indicated (refer to Section 4.5) Return to Table of Contents

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6. A fluid loss of 12.0-15.0 cm3 should be obtained naturally from the Bentonite slurry. Normally as drilling progresses, and prior to entering the potential productive zones of interest, the fluid loss is lowered to an approximate range of 6.0-10.0 cm3 with additions of Drispac or Staflo as required. A concentration of 1.0-1.5 kg/m3 of Drispac or Staflo is generally added to lower the fluid loss in this range. Small amounts of Lignite is commonly added along with the fluid loss additive to aid in fluid loss control. Normally Drispac/Staflo and Lignite is added in a 1:1 ratio respectively. 7. The Calcium content of the mud should be monitored and maintained less than 80 mg/L with additions of Soda Ash as required. Care should be taken not to add too much Soda Ash in order to minimize the Sodium Absorption Ratio (SAR) in the surrounding soil. An overtreatment of Soda Ash should also be cautioned, as a excess Carbonate ion build up may occur, thereby causing and increase in viscosity. If small amounts of Calcium are left in the mud system, this problem will not occur. 8. In some areas of Western Canada, Salt may be encountered. Generally if less than 5000 mg/L Salt is encountered, Bentonite can still be added directly into the active system without the yield or hydration being inhibited. If the Salt concentration exceeds ±5000 mg/L, a separate premix tank independent of the active mud system will be required to prehydrate the Bentonite in fresh water prior to adding to the active system. 9. Fresh additions of Bentonite should be made every tour, along with a good stream of water so that the mud does not become dehydrated. The Methylene Blue Test (MBT) should be checked regularly to determine the amount of Bentonite in the active system. 10. For an unweighted (no Barite) Gel Chemical system, the volume fraction of solids is calculated as follows: Volume Fraction of Solids (% Solids) = [(Mud Weight, kg/m 3 / 1000) – 1] X 0.625 or Volume Fraction of Solids (% Solids) = (Mud Weight, kg/m 3 – 1000) X 0.00064 For a weighted mud system containing Barite, the volume fraction of solids is calculated from the retort. 11. All available solids control equipment should be utilized to maximum capacity. Any further decrease in density should be done by dilution. Return to Table of Contents

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2.4

DISPERSED GEL CHEMICAL SYSTEMS Return to Table of Contents

Dispersed Gel Chemical mud systems are utilized in Western Canada primarily when drilling contaminants such as massive Anhydrite or Salt sections are encountered. They are an excellent systems to use in the deeper foothill wells of Western Canada, where higher temperatures and pressures can occur. Lignosulfonate dispersants were first used in Calcium base muds to control the Yield Point and Gel Strengths. The Lignosulfonates are primarily used as a viscosity reducing agent. The Lignosulfonates may be treated with a range of metal ions to confer slightly different properties. Calcium Lignosulfonates were the earliest to be used. Chrome and Ferrochrome Lingnosulfonates were developed to be more powerful thinners (dispersants) with extended temperature stability. In more recent times, the environmental effects of Chrome has led to the use of Chrome Free Lignosulfonates, such as Peltex or Pelthinz, which lack some of the temperature stability of the Chrome materials. Other dispersants, such as Desco CF and Alcomer 74 have replaced Peltex as the primary thinner(s) in dispersed muds. On the deeper hotter holes, Lignite is also often used in conjunction with the primary dispersants to aid in dispersion, fluid loss control, and temperature stability. It is believed that dispersants attach onto clay particles by valence attraction of the broken edge, thereby reducing the attractive forces between the particles. This phenomenon accounts for the dispersants ability to reduce and control the viscosity and Gel Strengths. Dispersed systems, depending upon the concentration of dispersants used, are often called dispersed or fully dispersed systems. The term “dispersed” in this sense has grown up through common usage, but is strictly incorrect as it is used to cover the deflocculating properties of dispersants. Dispersants actually have an inhibiting effect on true dispersion, which is the separation of the individual clay plates from the aggregated state. Treatments with Peltex, Pelthinz, Desco CF, Alcomer 74 and/or Lignite provide excellent rheology control, as well as borehole stability. They also aid in fluid loss control, and are generally stable at temperatures to 150+ Celsius.

Conversion: 1. Dispersed Gel Chemical mud systems are very flexible. Normally treatments of dispersants are made to existing Gel Chemical muds prior to entering an expected contaminant such as massive Anhydrite or Salt. They may also be added on the deeper wells where temperatures and pressures are increasing. The thinners are added to a concentration where the mud becomes fully dispersed. 2. Treatments may be altered to meet a variable mud property requirements. The required level of dispersion will depend upon many factors, such as the amount of contaminant expected, the type of contaminant encountered, the amount of solids in the mud system, the bottom hole temperature, pH of the fluid, etc. The mud program will normally have an indication of the amount and type of dispersant(s) required. 3. Treatment levels may be as follows: a. 2.0-6.0 kg/m3 for initial deflocculation b. 10.0-20.0 kg/m3 for inhibition and increased fluid loss control c. 20.0-30.0 kg/m3 for inhibition at higher temperature when the increased temperature has a dispersing effect on the clay particles. These concentrations are also needed for HTHP fluid loss control.

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These concentrations will vary depending upon the products used. It will take less Desco CF and Alcomer 74 than it would for Peltex or Pelthinz for the same level of dispersion. It is common to use a combination of these products when dispersing a mud system. For example: a. Desco CF and Lignite is used in a 1:2 ratio respectively. b. Desco CF and Alcomer 74 are used in a 2:1 ratio respectively. c. Peltex/Pelthinz and Lignite used in a 1:2 ratio respectively. 4. Peltex Lignosulfonate and Lignite are acidic in nature with a pH of approximately 4.0. They work more effectively in a pH range of 9.5-10.5. If these products are being used to disperse a mud system, the pH should be increased to these levels to ensure their effectiveness. If required, Peltex/Lignite and Caustic Soda can be mixed together through the chemical barrel. 5. Some foaming may be encountered when adding Lignosulfonate. A stockpile of a defoamer should be on location in the event it may be required. 6. While the dispersants are being added, additions of Bentonite will have to be made to ensure the viscosity and Yield Point are maintained high enough for effective hole cleaning, and to suspend Barite if applicable.

Maintenance: 1. The funnel viscosity should be maintained as required with daily additions of Bentonite. The Plastic Viscosity will tend to run somewhat higher than a conventional Gel Chemical mud system. The PV should be maintained as low as possible. 2. The Yield Point and Gel Strengths will run lower than a Gel Chemical mud, but should be maintained high enough to ensure effective hole cleaning, and to suspend the drilled cuttings and/or Barite when the pumps are shut off. 3. Daily additions of dispersant will be required, but will vary depending upon hole size, amount of contaminant encountered, mud density, solids content, and the desire properties. 4. Alkalinity greatly affects the performance of Peltex / Pelthinz and/or Lignite. An optimum pH of 9.5-10.5 should be maintained, and more importantly, the Pf alkalinity should be maintained between 0.3-0.7. Conversely, the pH can become greater than 10.5 with few immediate adverse effects. The foaming tendency is mud reduced when the pH is in the correct range. Lignosulfonates need free Hydroxide ions in order to work satisfactorily. Lignosulfonates and Lignite have a pH of 3-4 in an aqueous solution, so it is normal practice to add Caustic Soda along with any Lignosulfonate. A ratio of 4 sacks of Lignosulfonate to 1 sack of Caustic Soda is approximately correct to balance pH movement. 5. The fluid loss of a dispersed mud system will generally run lower than that of a conventional Gel Chemical system where massive anhydrite is being treated out with Soda Ash alone. This is one of the main advantages of dispersing a mud system through an anhydrite section. The fluid loss will remain much more stable, and therefore minimize any chance of differential sticking, tight hole, etc. Fluid loss is normally controlled with conventional fluid loss additives such as Drispac or Staflo. Additions of Lignite added in conjunction with Desco CF, Peltex or Pelthinz will also aid in fluid loss control. Return to Table of Contents

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6. If a Gel Chemical mud system is dispersed adequately, and the solids concentration is not too excessive, drilling through massive anhydrite sections will not appreciably affect the flow properties. While drilling through massive anhydrite sections, the pH of the system may be controlled with additions of Lime rather than Caustic Soda. This will minimize the amount of SAR (Sodium Absorption Ratio) from an excessive amount of Caustic Soda being added to the mud system. 7. Dispersed muds, if treated with sufficient concentrations, are able to tolerate Salt contamination up to ± 80 kg/m3, and still retain control over rheology and fluid loss.

2.5

POTASSIUM BASED MUD SYSTEMS


Potassium based fluids are usually employed for drilling clay/shale formations, both in exploration and production wells. These fluids are inhibitive systems that are used for controlling reactive formations. In shales containing clay mineral sequences, there is a powerful hydrational interaction with water. This hydration of the formation creates stresses internally in the rock being drilled, leading to borehole instability. The Potassium based mud systems have been designed to combat this effect. Clays are composed of layers of hydrated Silica, Magnesia, or Alumina, which are oriented in different ways to form the basic clay mineral of Montmorillonite, Kaolinite, Mica, and Chlorite. This alignment creates charged sites on the edges and faces of these minerals that have an affinity for water, thus a water layer will exist between the mineral sheets. The expansion or hydration potential of the different clay minerals is dependent upon salinity, and the type of ions present at the charged sites within the clay minerals. The primary shale inhibition is achieved by the substitution of cations in the clays (Sodium, Calcium, and Magnesium) with Potassium ions from the drilling fluid. The Potassium ion is small, and highly charged, and will readily cation exchange to form a clay with a minimum potential for expansion. Additions of PAC and PHPA Polymers provide secondary inhibition through encapsulation; forming a Polymeric barrier against migration of water into the matrix of the rock being drilled. The Potassium based mud systems will be more inhibitive than the Calcium or Ammonium based mud systems, and are normally run non-dispersed. The pH is also normally kept low (8.09.0) to minimize the clay hydration promoted by Hydroxyl ions. The following table shows the various Potassium salts that can be used for inhibition. Of these, only the Carbonate, Phosphate, Nitrate, Sulfate, and Acetate salts of Potassium can provide enough Potassium to be equivalent to 3% KCl by weight. The Carbonate and Sulfate salts are about twice the cost of KCl. The Nitrate, Phosphate, and Acetate salts are five to seven times the price of KCl. Of these salts, Potassium Sulfate appears to be the most cost effective substitute for KCl. A 3.5% solution of Potassium Sulfate (K2SO4) is equivalent in Potassium to a 3% KCl solution. Return to Table of Contents

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SUMMARY OF POTASSIUM ION SOURCES

Name

% K+ Ion in the Molecule

Potassium Chloride

KCl

52%

Maximum mg/L of K+ in Solution 135000

Potassium Hydroxide Potassium Lignite Potassium PHPA Potassium Carbonate

KOH

70%

4000

8-12

K-Lignite

±1%

10000

±11

K – PHPA

±1%

2500

±10

K2CO3

57%

280000

11.5

Potassium Phosphate (three) Potassium Nitrate

KH2PO4 K2HPO4 K3PO4 KNO3

30% 45% 55% 39%

53000 269000 282000 100000

4.6 8.5 12 7

Potassium Sulfate

K2SO4

45%

45000

7

Potassium Acetate

KCOOCH3

40%

260000

10

2.5.1

Formula

POTASSIUM CHLORIDE (KCl) MUDS

pH of Solution

Comments on Usage

7

Environmental Concern (Chlorides) Add only to control pH Supplemental K+ Source Supplemental K+ Source CO3 ions can thicken clay base muds and precipitation of Ca++ can restrict production Precipitation of Ca++ can restrict production Dry KNO3 forms an explosive with hydrocarbons Precipitation of Ca++ can restrict production Costly


Potassium Chloride (KCl) muds are a special class of Salt muds, in that the Potassium (K+) ion is utilized as the principal inhibiting ion. That is at a certain concentration, the Potassium ion will base exchange with the Sodium ion in Smectite clay, thereby minimizing the amount of swelling from the clay. Potassium ion concentrations generally range from 3.0-5.0% by weight for shale stabilization throughout Western Canada. With today’s environmental concerns regarding the use of salt base fluids, the use of KCl muds have been severely restricted in Canada. With the costs associated to clean up a sump that contains KCl, it has made these systems almost cost prohibitive to use.

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Return to Table of Contents Make Up: 1. For best results, the system should be free of all drilled solids. Dump and clean the mud tanks and rebuild volume with water.

2.

3.

4. 5.

6.

7.

If KCl was used for the upper flocculated water portion of the hole, then utilize as much clear sump water as possible to fill the tanks. Fill the tanks ± ¾ full with water. Add approximately 1.0-1.5 kg/m3 of Caustic Soda or Caustic Potash (KOH) through the chemical barrel to increase the pH of the water to ± 9.5-10.0. Caustic Potash (Potassium Hydroxide) has the advantage of providing an extra source of Potassium ions for added inhibition. Add the required amount of KCl (Potash) through the hopper to bring the Potassium concentration to the desired level. Generally a minimum concentration of 30 kg/m3 (3% by weight) will be required. On the initial premix, a concentration of 40 kg/m 3 (4% by weight) is recommended in the make up water. Once the fluid is displaced from the hole, and additional volume is build, the end concentration should be in the 3% by weight range. Some foaming may occur but should easily be controlled with small additions of a Defoamer as required. A stockpile of Defoamer should be on location in the event it may be required. Normally a PHPA Polymer such as Alcomer 110RD or Alcomer 60RD is added for shale encapsulation. A concentration of 1.5-2.0 kg/m3 is normally sufficient for added inhibition from these Polymers. Then add approximately 3.0-4.0 kg/m3 of a fluid loss reducing Polymer such as Drispac or Staflo through the hopper. All Polymers should be mixed slowly through the hopper at a minimum rate of ± 25-30 min.’s/sx. KCl muds being a Salt, can be corrosive in nature. Corrosion rings should be installed and monitored with these types of mud systems. Maintaining a pH of 9.5-10.0 will minimize corrosion levels, but will not eliminate it. An oxygen scavenger such as Corinox, KD-40 or Sodium Sulfite is normally added to control corrosion levels to an acceptable level with the KCl systems. Corinox and KD-40 are unique dual purpose corrosion prevention chemical mixtures in a liquid form. It has the ability to scavenge dissolved Oxygen effectively, as well the capability to absorb onto active corrosion sites (anodes) on drill pipe, casing, and tubing in water base muds. Under normal conditions for a corrosion level of about 25 mils per year (25 mpy), initially one (20L) pail of Corinox per 16 m3 of fluid is added.

If Sodium Sulfite is being used as on Oxygen scavenger, it is added continually until the residual Sulfite (SO3) concentration in the mud filtrate reaches or exceeds 300 mg/L. 8. If Bentonite is to be used for viscosity and supplemental fluid loss control, then prehydrate approximately 70-90 kg/m3 of Gel if fresh water in a separate premix tank independent of the rig’s active system. Let this system hydrate as long as possible to achieve full hydration of the Bentonite; i.e.: at least 30 minutes in warm water, and at least 60 minutes in cold water. 9. At mud up depth, displace the exiting fluid from the hole with the KCl Polymer water. While displacing, build volume and viscosity by slowly transferring over the prehydrated Bentonite to the active system over a circulation. Return to Table of Contents

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Return to Table of Contents Maintenance: 1. The mud density should be maintained as low as formation pressures will allow. If an increase in density is required, generally Barite is used. For an unweighted KCl Polymer system, all solids control removal equipment should be run continuously using the finest possible screens on the shale shakers. If a centrifuge is available, it should be big enough to process the circulating volume of the active system. 2. The viscosity should be maintained just high enough for effective hole cleaning. This is normally achieved with additions of prehydrated Bentonite. The MBT (Methylene Blue Test) should be monitored, and maintained at approximately 30-40 kg/m3 in the active system for viscosity control. Additions of prehydrated Bentonite will also aid in fluid loss control by building a filter cake. The viscosity in the KCl systems is also normally supplemented with additions of Kelzan XCD Polymer. XCD Polymer is an excellent product for increasing the Yield Point and “low end” rheology of these mud systems. Normal concentrations: 1.5-2.0 kg/m3. If the viscosity has to be reduced, dispersants such as Desco CF or Alcomer 74 may be added as required. Both products work very well in the KCl Polymer systems. 3. The Plastic Viscosity (PV) of the mud will correlate to the solids make up of the mud system, and should be kept as low as possible with dilution, and the effective solids control equipment on the rig. Because of the semi-flocculated nature of a KCl system, effective solids control equipment is vital. High speed linear motion shale shakers, and high volume centrifuge(s) are highly recommended with these types of muds. 4. Because of the semi-flocculated nature of the system, the Yield Point (YP) of a KCl mud will normally run higher than that of a conventional Gel Chemical system. The Gel Strengths will also be higher, but are generally flat and fragile. Kelzan XCD Polymer is an excellent product for increasing the YP or initial Gel Strength if added hole cleaning is required. 5. The pH of the mud system will be determined by the mud program. Maintaining a high pH will reduce the corrosion of the system, but will also enhance the hydration of swelling clays. If an increase if pH is programmed, then control in the desired range with additions of Caustic Soda (NaOH) or Caustic Potash (KOH) as required. 6. The natural fluid loss of a KCl system will be very high because of the semi-flocculated nature of the system; i.e.: 50-70+ cm3. However, the filtrate contains both KCl and PHPA Polymer, and thus protects against the hydration of water sensitive clays or shales. In order to minimize the possibility of differential sticking though, and to minimize the overall amount of water going into the potential productive zone(s), the fluid loss is generally lowered to the 8.0-12.0 cm3 range with additions of Drispac or Staflo as required. This will require more fluid loss Polymer than with conventional Gel Chemical mud systems. Generally a concentration of 3.0-4.0 kg/m3 of Drispac should be sufficient to lower the fluid loss to the desired range. Return to Table of Contents

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Generally Drispac SuperLo or Staflo ExLo is used to control the fluid loss. If an increase in viscosity is required with a reduction in fluid loss, then utilize Drispac Regular or Staflo Regular. 7. For maximum inhibition from the fluid, the concentration of PHPA Polymer should be monitored and maintained in a range of 1.5-2.0 kg/m3. Monitor the concentration closely to ensure there is always an excess in the filtrate. 8. As drilling progresses, daily additions of KCl will have to be made to ensure the Potassium ion does not fall below 3% by weight (30 kg/m 3), or as outlined in the mud program. The Potassium ion should be monitored closely. 9. Corrosion rings should be installed and monitored while drilling with a KCl system. The corrosion level should be controlled as outlined by the drilling program with an Oxygen scavenger such as Corinox, KD-40 or Sodium Sulfite as required.

PROPERTIES OF KCl SOLUTIONS (at 20 C)

% KCl

Density (kg/m3)

KCl (kg/m3)

KCl (mg/L)

K+ (mg/L)

Cl(mg/L)

1 2 4 6 8 10 12 14 16 18 20 22 24

1006 1013 1026 1039 1052 1065 1079 1093 1106 1120 1135 1149 1160

11.4 20.0 39.9 62.8 82.8 105.6 128.4 154.1 176.9 202.6 225.4 251.1 279.6

10050 20220 40960 62210 84000 106300 129200 152700 176700 201300 226600 252400 279000

5271 10605 21482 32627 44056 55752 67762 80087 92674 105576 118845 132376 146327

4779 9615 19478 29583 39945 50548 61439 72613 84026 95724 107755 120024 132673

Note: 

KCl: 1.984 SG



KCl Required (kg/m3) = 1.91 X Potassium Ion (mg/L) 1000



1 kilogram of KCl occupies 0.411 of volume in water Return to Table of Contents

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Final Volume Factor 1.004 1.008 1.016 1.024 1.033 1.043 1.053 1.064 1.076 1.088 1.102 1.115 1.028

Freezing Point ( C) 0 -1 -2 -3 -4 -5 -6 -7 -8 -9 -10 0 13

2.5.2

POTASSIUM SULFATE (K2SO4) MUDS


Potassium Sulfate (K2SO4) muds are similar to the KCl muds in that the Potassium (K+) ion is still utilized as the principal inhibiting ion, but does not contain any Chloride ions which make the system much more environmentally friendly. The Potassium ion will base exchange with the Sodium ion in Smectite clay, thereby minimizing the amount of swelling from the clay. Potassium ion concentrations generally range from 3.55.0% by weight for shale stabilization throughout Western Canada with these systems.

Make Up: 1. For best results, the system should be free of all drilled solids. Dump and clean the mud tanks and rebuild volume with water. 2. If Potassium Sulfate was used for the upper flocculated water portion of the hole, then utilize as much clear sump water as possible to fill the tanks. Fill the tanks ± ¾ full with water. 3. Add approximately 1.0-1.5 kg/m3 of Caustic Soda or Lime through the chemical barrel to increase the pH of the water to ± 9.5-10.0. Lime is much cheaper than Caustic Soda and will not affect the rheology of the mud system. 4. Add the required amount of K2SO4 (Potassium Sulfate) through the hopper to bring the Potassium concentration to the desired level. Generally a minimum concentration of 35-40 kg/m3 (3.5-4.0% by weight) will be required. On the initial premix, a concentration of 45-50 kg/m3 (4½-5% by weight) is recommended in the make up water. Once the fluid is displaced from the hole, and additional volume is build, the end concentration should be in the 3.54.0% by weight range. The Potassium ion concentration should be no lower than 16000 mg/L. 5. Some foaming may occur but should easily be controlled with small additions of a Defoamer. A stockpile of Defoamer should be on location in the event it may be required. 7. Then add approximately 1.5-2.0 kg/m3 of Kelzan XCD for primary viscosity control. The Potassium Sulfate systems are normally run clay free; i.e.: no Bentonite in the mud system. 8. After the Kelzan XCD has been mixed, fluid loss reducing Polymers should then be added. For these systems, Drispac and Starpak DP are normally mixed together in a 1:3 ratio respectively. Concentrations of ±3.0 kg/m 3 of Drispac Regular and ±9.0-10.0 kg/m3 of Starpak DP are normally mixed for an initial concentration. All Polymers should be mixed slowly through the hopper at a rate of ± 25-30 min.’s/sx. 9. Potassium Sulfate muds also being a Salt, can be corrosive in nature. Corrosion rings should be installed and monitored with these types of mud systems. Maintaining a pH of 9.5-10.0+ will minimize corrosion levels, but will not eliminate it. An oxygen scavenger such as Corinox, KD-40 or Sodium Sulfite is normally added to control corrosion levels to an acceptable level with the K2SO4 systems. Corinox is an unique dual purpose corrosion prevention chemical mixture in a liquid form. It has the ability to scavenge dissolved Oxygen effectively, as well the capability to absorb onto active corrosion sites (anodes) on drill pipe, casing, and tubing in water base muds. Under normal conditions for a corrosion level of about 25 mils per year (25 mpy), initially one (20L) pail of Corinox per 16 m3 of fluid is added. If Sodium Sulfite is being used as on Oxygen scavenger, it is added continually until the residual Sulfite (SO3) concentration in the mud filtrate reaches or exceeds 300 mg/L. Return to Table of Contents

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Return to Table of Contents Maintenance: 1. The mud density should be maintained as low as formation pressures will allow. If an increase in density is required, generally Barite or Calcium Carbonate is used. Calcium Carbonate is recommended for use when drilling into a potential pay zone, as it is acid soluble. For an unweighted Potassium Sulfate system, all solids control removal equipment should be run continuously using the finest possible screens on the shale shakers. If a centrifuge is available, it should be big enough to process the circulating volume of the active system. 2. The viscosity should be maintained just high enough for effective hole cleaning. This is normally achieved with additions Kelzan XCD Polymer only. Normal concentrations: 1.5-2.0 kg/m3. 3. If the viscosity has to be reduced, dispersants such as Desco CF or Alcomer 74 may be added as required. In a clay free environment, dilution with water is required to reduce the viscosity. Both products work very well in the K2SO4 Polymer systems. 4. The Plastic Viscosity (PV) of the mud will correlate to the solids make up of the mud system, and should be kept as low as possible with dilution, and the effective solids control equipment on the rig. As with the KCl systems, effective solids control equipment is vital. High speed linear motion shale shakers, and high volume centrifuge(s) are highly recommended with these types of muds. 5. Because of the Polymer nature of the system, the Yield Point (YP) of a Potassium Sulfate mud will normally run higher than that of a conventional Gel Chemical system. The Gel Strengths will also be higher, but are generally flat and fragile. Kelzan XCD Polymer is an excellent product for increasing the YP or initial Gel Strength if added hole cleaning is required. 6. The pH of the mud system will be determined by the mud program. Maintaining a high pH will reduce the corrosion of the system, but will also enhance the hydration of swelling clays. If an increase if pH is programmed, then control in the desired range with additions of Caustic Soda or Lime. 7. In order to minimize the possibility of differential sticking, and to minimize the overall amount of water going into the potential productive zone(s), the fluid loss is generally lowered to the 6.0-8.0 cm3 range with additions of Drispac and Starpak DP as required. Drispac and Starpak DP is normally added in a 1:3 ratio respectively. Drispac Regular is also normally added in these systems to supplement the viscosity. If a decrease in fluid loss is required, without any additional viscosity increase, then utilize Drispac SuperLo. 8. Note: If a neutral pH has been a programmed, or if the fluid is sitting static for an extended period of time; i.e.: testing, logging, etc., the Polymers in this system may begin to ferment. If the fluid begins to smell, a bactericide will be required. A common bactericide that can be “de-activated” at the end of the well without environmental repercussions is T352 Glutaraldehyde. Return to Table of Contents

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The recommended treatment is dependent on the severity of the bacterial contamination. As a pretreatment, add 0.1-0.5 litres/m3 to the mud system and monitor with microbial dipslildes. For combating contaminated fluids, add 0.5-2.0 litres/m3 per treatment until bacterial control is achieved 9. As drilling progresses, daily additions of Potassium Sulfate will have to be made to ensure the Potassium ion does not fall below 16000 mg/L (35-40 kg/m3), or as outlined in the mud program. The Potassium ion should be monitored closely. 10. Corrosion rings should be installed and monitored while drilling with a K2SO4 system. The corrosion level should be controlled as outlined by the drilling program with an Oxygen scavenger such as Corinox, KD-40 or Sodium Sulfite as required. PROPERTIES OF POTASSIUM SULFATE (K 2SO4) SOLUTIONS % K2SO4

Density (kg/m3)

K2SO4 (kg/m3)

K+ (mg/L)

SO4-2 (mg/L)

1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0 5.5 6.0 6.5 7.0 7.5 8.0 8.5 9.0 9.5 10.0

1008 1012 1016 1020 1024 1028 1032 1037 1041 1045 1049 1053 1057 1061 1066 1070 1074 1078 1083

10.0 15.1 20.2 25.4 30.5 36.0 41.5 46.5 52.0 57.3 62.7 68.1 73.8 79.2 84.9 90.6 96.3 102.0 107.8

4532 6821 9110 11443 13776 16110 18488 20911 23920 25758 28181 30649 33162 35675 381888 40746 43304 45907 48509

5568 8379 11190 14057 16924 19790 22712 25689 28610 31642 34619 37651 40738 43825 46912 50054 53196 56393 59591

Final Volume Factor 1.004 1.005 1.006 1.007 1.008 1.009 1.011 1.012 1.013 1.014 1.016 1.017 1.019 1.020 1.021 1.023 1.024 1.026 1.027

Freezing Point ( C) -0.28 -0.06 -0.05 -0.06 -0.06 -0.11 -0.11 -1.06 -1.17 -


2.5.3

Potassium Formate (KCOOH) Muds

Potassium Formate (KCOOH) is an organic Salt, which is biodegradable. It is a high density brine delivered as a 70.7% by weight (SG 1.53) solution for winter use, and as a 75% by weight (SG 1.57) solution for summer use. It is clear to slightly amber in appearance. The concentrated solution of Potassium Formate when diluted back with water to ±5%, will provide an inhibitive fluid with a Potassium ion of ±25000 mg/L. Potassium Formate readily exchanges its Potassium ions with clays and shales to inhibit their reactivity and contribute to improved hole stability. One m3 carboy or tote to 20 m3 of water will give a ±5% solution. This percentage of Potassium ion is generally enough to inhibit most troublesome shale formations in Western Canada. At higher concentrations, Potassium Formate will provide both temperature and bio-stability to Starches, PAC’s and Polymers.

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It is necessary to ensure that a forklift is on location for handling the tote or carboy containers that Potassium Formate is transported in. A Polymer tank or small premix tank is required for the pre-hydration of all Polymers prior to adding to the active system. Solids control is a key component to run the Potassium Formate system and 1-2 high volume centrifuges is recommended on location. Return to Table of Contents Make Up: 1. For best results, the system should be free of all drilled solids. Dump and clean the mud tanks and rebuild volume with water. 2. If Potassium Formate was used for the upper flocculated water portion of the hole, then utilize as much of the clear fluid as possible to fill the tanks. Fill the tanks ± ¾ full with water. 3. For floc water drilling, a 1.5% solution is sufficient to flocculate the solids. Increasing the concentration to 5% will inhibit the more highly active troublesome upper formations if required. There is no flocculating Polymer, or other Salt additions required for flocculation to occur at acceptable rates of penetration

4.

5.

6. 7. 8.

Caution is advised while floc water drilling as depletion rates of KCOOH can be quite high, and close monitoring of the K+ ion is advised. Prior to mud up, prehydrate Kelzan XCD or Xanvis Polymer and Aquastar “D” or Starpak DP, or a low molecular weight PAC fluid loss additive in fresh water for a minimum of 6-8 hours. Prehydrate enough Polymer to achieve concentrations in the active system of 2.0-3.0 kg/m3 of Kelzan XCD and 9.0-12.0 kg/m3 of Aquastar “D”. At mud up depth, close in the system and raise the KCOOH concentration to 5% by volume. Add enough Potassium Formate totes to raise the K+ ion concentration to 25000 mg/L and a solution of 5% Then add in the pre-hydrated Polymer solution. Once the Polymers are in, raise the pH to 10.0 with Caustic Potash (KOH) or Lime. Once these additions are in, it is recommended to add 15 kg/m3 of Magma Fiber (acid soluble) fine cellulose.

This fluid will exhibit the following properties: Mud Density: Yield Point: Gels: Fluid Loss: pH:

±1030 kg/m3 ± 9 Pa 3/5 Pa < 6.0 cm3 10.0

Maintenance: Potassium Formate is extremely lubristic in nature, and exhibits excellent low-end rheology. Once the Potassium Formate has coated the well bore face, drilled cuttings, additions of prehydrated Polymers, they then tend to lose the ability to take on free water. Potassium Formate is very hydrophilic in nature. 1. The mud density should be maintained as low as formation pressures will allow. If an increase in density is required, generally Barite or Calcium Carbonate is used. Calcium Carbonate is recommended for use when drilling into a potential pay zone, as it is acid soluble. Return to Table of Contents

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Note: Barite (Barium Sulfate) will become soluble if the Potassium Formate concentration is 40% or greater. In these circumstances, CaCO 3 should be used to increase the density. 3. The viscosity should be maintained just high enough for effective hole cleaning. This is normally achieved with additions Kelzan XCD or Xanvis Polymer only. Normal concentrations: 2.0-3.0 kg/m3. 3. The Plastic Viscosity (PV) of the mud will correlate to the solids make up of the mud system, and should be kept as low as possible with dilution, and the effective solids control equipment on the rig. As with the inhibitive systems, effective solids control equipment is vital. High speed linear motion shale shakers, and high volume centrifuge(s) are highly recommended with these types of muds. 4. Because of the nature of the system, the Yield Point (YP) of a Potassium Formate mud will normally run higher than that of a conventional Gel Chemical system. The Gel Strengths will also be higher, but are generally flat and fragile. 5. The pH of the mud system should be maintained at 10.0 with additions of Caustic Potash as required. 6. In order to minimize the possibility of differential sticking, and to minimize the overall amount of water going into the potential productive zone(s), the fluid loss is generally lowered to the 6.0 or less with additions of Aquastar “D” or and Starpak DP as required. 7. As drilling progresses, daily additions of Potassium Formate will have to be made to ensure the Potassium ion does not fall below 25000 mg/L (5% solution), or as outlined in the mud program. The Potassium ion should be monitored closely. 8. Corrosion rings should be installed and monitored while drilling with a KCOOH system. The corrosion level should be controlled as outlined by the drilling program with an Oxygen scavenger such as Corinox, KD-40 or Sodium Sulfite as required.

Completion: When the well is complete, the pH can be lowered to 4.0 with Sulfamic Acid, and then raised back to 10.0 with Caustic Potash or Lime. This action will cause a Polymerization of the Polymers, and any solids will drop out of the fluid. Therefore, the fluid will then be just a Potassium Formate water which can be transferred to the next hole. This fluid is re-usable in both floc water and mud forms.

2.6

AMMONIUM SULFATE MUD SYSTEMS


Ammonium based mud systems are similar to the KCl base muds, except that the Ammonium ion (NH4) is utilized as the principal inhibiting ion. The most common Ammonium base mud system run in Western Canada today is the Ammonium Sulfate system. The Ammonium Sulfate mud is more environmentally friendly than the KCl systems because it does not contain any Chlorides. Ammonium Sulfate based mud systems are a little more difficult to control than a Potassium based mud. The NH4 ion is slightly larger that the K+ ion, therefore it is harder to base exchange with the Sodium ion in the Smectite clay. This will result in a little more flocculation than the Potassium base systems, until the Sodium ions have all based exchanged with the NH4 ions. Once the Sodium ion has been replaced by the Ammonium ion, it fits into the lattice structure very snuggly, and is very difficult to remove.

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Return to Table of Contents Make Up: 1. For best results, the system should initially be free of all drilled solids. Dump and clean the mud tanks. Rebuild ± ¾ full with fresh water.

2. 3.

4. 5.

6.

7.

If Ammonium Sulfate has been used for the clear water (flocculated) drilling section of the hole, then fill the mud tanks with clear sump water. Ensure the fluid is taken from the suction side of the sump, and is free of any drilled solids. Add the required amount of Ammonium Sulfate through the hopper to bring the Ammonium content up to the desired level. Generally a minimum concentration of 3% by weight, or 30 kg/m 3 of Ammonium Sulfate is sufficient to inhibit most Bentonitic shales in Western Canada. On the initial make up, it is sometimes recommended to increase the concentration to 4% by weight (40 kg/m 3). When the fluid is displaced to the hole at mud up depth and volume is built, the final concentration will end up at the desired 30 kg/m3 with dilution. Then add approximately 3.0-4.0 kg/m3 of Drispac SL or Staflo Exlo for fluid loss control. Mix the fluid loss additives slowly through the hopper; i.e.: 25-30 min’s/sack. In a separate premix tank independent of the rig tank(s), prehydrate approximately 70-90 kg/m3 of Bentonite in fresh water, free of any Calcium. Let this slurry hydrate as long as possible. At mud up depth, displace the Ammonium Sulfate Polymer slurry to the hole. While displacing, slowly add over the prehydrated Bentonite slurry to build volume, and increase the viscosity. Discard the previous fluid from the hole to the sump, or a buried tank, etc. A neutral pH must be maintained with the Ammonium Sulfate mud system. Increasing the pH above 8.0 will liberate Ammonia gas and make it very unpleasant and unsafe to work around the mud tanks.

Any cement that has to be drilled out, should be done with fresh water prior to displacing the hole to an Ammonium Sulfate mud system. 8. Ammonium Sulfate muds in nature are not as corrosive as the KCl or Salt base mud systems. Being a fertilizer though, Ammonium Sulfate can be somewhat corrosive. Corrosion rings should be installed and monitored with these types of mud systems. If required, an oxygen scavenger such as Corinox, KD-40 or Sodium Sulfite may be added to control corrosion levels to an acceptable level with the Ammonium Sulfate systems. Corinox is a unique dual-purpose corrosion prevention chemical mixture in a liquid form. It has the ability to scavenge dissolved Oxygen effectively, as well the capability to absorb onto active corrosion sites (anodes) on drill pipe, casing, and tubing in water base muds. Under normal conditions for a corrosion level of about 25 mils per year (25 mpy), initially one (20L) pail of Corinox per 16 m3 of fluid is added. If Sodium Sulfite is being used as on Oxygen scavenger, it is added continually until the residual Sulfite (SO3) concentration in the mud filtrate reaches or exceeds 300 mg/L. Return to Table of Contents

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Maintenance: 1. The mud density should be maintained as low as formation pressures will allow. If an increase in density is required, generally Barite or Calcium Carbonate is used. Calcium Carbonate is recommended for use when drilling into a potential pay zone, as it is acid soluble. For an unweighted Ammonium Sulfate system, all solids control removal equipment should be run continuously using the finest possible screens on the shale shakers. If a centrifuge is available, the centrifuge should be big enough to process the circulating volume of the active system. 2. The viscosity should be maintained just high enough for effective hole cleaning. This is normally achieved with additions of prehydrated Bentonite. The MBT (Methylene Blue Test) should be monitored, and maintained at approximately 30-40 kg/m3 in the active system for viscosity control. Additions of prehydrated Bentonite will also aid in fluid loss control by building a filter cake. 3. The viscosity in the Ammonium Sulfate systems can also be supplemented with additions of Kelzan XCD Polymer. XCD Polymer is an excellent product for increasing the Yield Point and “low end” rheology of these mud systems. Normal concentrations: 1.5-2.0 kg/m3. If the viscosity has to be reduced, dispersants such as Desco CF or Alcomer 74 may be added as required. Both products work very well in the Ammonium Sulfate systems. 4. The Plastic Viscosity (PV) of the mud will correlate to the solids make up of the mud system, and should be kept as low as possible with dilution, and the effective solids control equipment on the rig. Because of the semi-flocculated nature of an Ammonium based system, effective solids control equipment is vital. High speed linear motion shale shakers, and high volume centrifuge(s) are highly recommended with these types of muds. 5. Because of the semi-flocculated nature of the system, the Yield Point (YP) of an Ammonium Sulfate mud will normally run higher than that of a conventional Gel Chemical system. The Gel Strengths will also be higher, but are generally flat and fragile. Kelzan XCD Polymer is an excellent product for increasing the YP or initial Gel Strength if added hole cleaning is required. 6. The pH of the mud system should remain neutral. Maintaining a high pH will liberate Ammonia gas. 7. The natural fluid loss of an Ammonium Sulfate will be very high because of the semiflocculated nature of the system; i.e.: 50-70+ cm3. In order to minimize the possibility of differential sticking, and to minimize the overall amount of water going into the potential productive zone(s), the fluid loss is generally lowered to the 8.0-12.0 cm3 range with additions of Drispac or Staflo. This will require more fluid loss Polymer than with conventional Gel Chemical mud systems. Generally a concentration of 3.0-4.0 kg/m3 of Drispac should be sufficient to lower the fluid loss to the desired range. Generally Drispac SuperLo or Staflo ExLo is used to control the fluid loss. If an increase in viscosity is required with a reduction in fluid loss, then utilize Drispac Regular or Staflo Regular. 8. As drilling progresses, daily additions of Ammonium Sulfate will have to be made to ensure the concentration does not fall below 3% by weight (30 kg/m 3), or as outlined in the mud program.

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9. Corrosion rings should be installed and monitored while drilling with an Ammonium Sulfate system. The corrosion level should be controlled as outlined by the drilling program with an Oxygen scavenger such as Corinox, KD-40 or Sodium Sulfite.

2.7

GYP MUD SYSTEMS


GYP muds are used primarily to drill massive and soluble sections of anhydrite. Gypsum is an environmentally friendly product that does not cause any major problems with today’s environmental regulations. GYP muds are also inhibitive in nature, in that the Calcium ion will base exchange with the Sodium ion in Smectite (Bentonitic) clays, and thereby cause dehydration or inhibition of the Bentonitic clay particle. It is not a very good inhibiting ion though, because the Calcium ion is quite large, and is hard to get it to replace the Sodium ion in the available lattice space of the Smectite clay. It takes quite a long time for the base exchange to take place, and being a divalent ion, the degree of flocculation can be quite severe. Make Up: Two situations normally occur when making up a GYP mud system. 1. The first situation occurs when anhydrite is not predicted but encountered, or if only stringers of anhydrite are encountered while drilling with a conventional Gel Chemical system. 2. When this situation occurs, the Gel mud becomes flocculated because of the Calcium contamination from the anhydrite. Anhydrite or soluble Calcium is not treated out with Soda Ash, but rather allowed to climb in the Gel Chemical system. This process is normally called “Gypping” the mud over.

3.

4.

5.

6.

Adjustments will have to be made to the Gel base mud. The degree of contamination or flocculation will depend upon the amount of anhydrite drilled, and the amount and type of solids in the mud system. When anhydrite is encountered with a Gel base mud system, a marked increase in funnel viscosity, Yield Point, Gel Strengths, fluid loss, and Calcium content occur. A decrease in pH should also be noted. Additions of Desco CF and/or Alcomer 74 will be required to control the flocculation. Normally Desco and Alcomer 74 are added in a 2:1 ratio respectively. The amount of dispersion required will depend upon the amount of anhydrite drilled, and the solids content of the mud. As anhydrite is drilled, more soluble Calcium will be introduced in the mud system. Do not treat out any Calcium with Soda Ash. Let as much soluble Calcium enter the mud system naturally. Generally about 400 mg/L of soluble Calcium will be required to “GYP” over the mud system. The lower the pH, the Calcium will go into solution and vice-versa. Calcium is insoluble above a pH of 10.6. Return to Table of Contents

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1. The second solution occurs when the anhydrite section is predicted or known about. The system is ‘Gypped” over by physically added Gypsum prior to penetrating the anhydrite formation. This will ensure that enough Calcium is in the mud system prior to penetrating the zone, and therefore no contamination should occur while drilling the anhydrite. 2. Prior to penetrating the anhydrite formation, slowly add approximately 15.0-17.0 kg/m3 of Gypsum to an existing Gel Chem. system. 3. Additions of Desco CF and/or Alcomer 74 will be required to control the flocculation. Normally Desco and Alcomer 74 are added in a 2:1 ratio respectively. The amount of dispersion required will depend upon the amount of soluble Calcium desired, and the solids content of the mud. 4. Because Gypsum (CaSO4.2H20) has a water molecule attached to it, it will require a good stream of water to be added to the active system while adding the Gypsum. 5. After the system has been “Gypped” over, maintain the pH in the desired range with additions of Lime, rather than Caustic Soda. Lime Ca(OH)2 will have the added advantage of an additional Calcium source rather than Caustic Soda (NaOH). 6. Add Drispac/Staflo and Starpak DP for fluid loss control. The Polyanionic Cellulose fluid loss Polymers such as Drispac or Staflo are affected by the amount of soluble Calcium in the mud system. The higher the Calcium content of the mud, the more of these additives will be required. Starpak DP is a much more effective fluid loss additive in Calcium base muds. Therefore normally Drispac or Staflo, and Starkpak DP is added in a 1:3 ratio respectively. 7. Adding Bentonite direct to the active system with a high amount of Calcium will severely limit the hydration of the Bentonite. Therefore a separate premix tank, independent of the active mud tank(s) will be required to prehydrate the Bentonite in fresh water, prior to adding to the active system. In a separate premix tank, prehydrate approximately 70-90 kg/m3 of Bentonite in fresh water. Let this slurry hydrate for as long as possible prior to adding to the active system. Return to Table of Contents Maintenance: 1. The mud density should be maintained as low as formation pressures will allow. If an increase in density is required, generally Barite is used. For an unweighted GYP system, all solids control removal equipment should be run continuously using the finest possible screens on the shale shakers. If a centrifuge is available, the centrifuge should be big enough to process the circulating volume of the active system. 2. The viscosity should be maintained just high enough for effective hole cleaning. This is normally achieved with additions of prehydrated Bentonite. The MBT (Methylene Blue Test) should be monitored, and maintained at approximately 40-60 kg/m3 in the active system for viscosity control. Additions of prehydrated Bentonite will also aid in fluid loss control by building a filter cake. 4. The viscosity in the GYP systems can also be supplemented with additions of Kelzan XCD Polymer, but generally is not recommended as the primary viscosifier. If the viscosity has to be reduced, dispersants such as Desco CF or Alcomer 74 may be added as required. Both products work well in the GYP systems.

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4. The Plastic Viscosity (PV) of the mud will correlate to the solids make up of the mud system, and should be kept as low as possible with dilution, and the effective solids control equipment on the rig. Because of the semi-flocculated nature of a GYP based system, effective solids control equipment is vital. High speed linear motion shale shakers, and high volume centrifuge(s) are highly recommended with these types of muds. 5. Because of the semi-flocculated nature of the system, the Yield Point (YP) of a GYP mud will normally run higher than that of a conventional Gel Chemical system. The Gel Strengths will also be higher, but are generally flat and fragile. 7. Generally the pH of the system is maintained in the 8.5-9.5 range with Lime only. The higher the pH, the less soluble Calcium becomes. Generally the Calcium content of the mud should run between 400-600 mg/L. 8. The fluid loss is normally run in the 6.0-10.0 cm3 range with Drispac/Staflo and Starpak DP in a 1:3 ratio respectively. Normal concentrations: Drispac SL or Staflo Exlo: Starpak DP:

3.0-4.0 kg/m3 9.0-12.0 kg/m3

9. Daily additions of Gypsum will be required while drilling through the anhydrite section to maintain the excess Calcium in the 400-600 mg/L range.

2.8

SALTWATER MUD SYSTEMS


Saltwater muds are used primarily in areas where Salt stringers, or massive Salt sections are drilled. Also if a Salt water flow is encountered, it may be necessary to convert an existing fresh water mud system to a Saltwater mud in order to minimize any contamination. Saltwater mud systems are not commonly utilized throughout Western Canada because of the environmental problems disposing of a high Chloride system. In some cases though, they have to be run because of drilling massive Salt sections. If a Salt mud is utilized today, the mud or sump fluids at the end of the well are generally hauled away and pumped down a disposal well. Salt can be encountered throughout Western Canada in the Middle to Lower Devonian formations in S.E. Saskatchewan, Central Alberta, and the Northern area of Alberta. For example, the Prairie Evaporite contains massive Salt in the Estevan, Sask. area. Also the Wabamun Formation around the Drumheller, Clive, or Bashaw areas of Central Alberta may contain Salt throughout the anhydrite/evaporite sections. The Muskeg Formation in the Trout, Kidney or Senex areas of Northern Alberta is usually massive Salt. Make Up: Two situations may occur when making up a Saltwater mud system. 1. The first situation occurs when Salt is not predicted but encountered, or if only stringers of Salt are encountered while drilling with a conventional Gel Chemical system. If Salt is encountered, adjustments will have to be made in chemical control, but will depend upon the severity of the contamination.

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2. Bentonite added to a mud containing over ±10000 mg/L of Salt exhibits a marked decrease in hydration and dispersion. As the Salt content increases, clay hydration and dispersion decreases to a further extent. As the Salt concentration reaches approximately 50,000 mg/L and above, viscosity and fluid loss control from Bentonite and natural Bentonitic clays become negligible. 3. When Salt is encountered with a Gel base mud system, a marked increase in funnel viscosity, Yield Point, Gel Strengths, fluid loss, and Chloride content occur. A decrease in pH should also be noted. 5. Additions of Desco CF and/or Alcomer 74 will be required to control the flocculation. Normally Desco and Alcomer 74 are added in a 2:1 ratio respectively. The amount of dispersion required will depend upon the amount of Salt drilled, and the solids content of the mud. 6. If the Salt contamination is less than 10000 mg/L, Bentonite may still be utilized for viscosity and fluid loss control, although more of it will be required than with a conventional fresh water mud system. 7. If the Salt contamination is above 10000 mg/L, higher concentrations of thinners; i.e.: Desco CF and/or Alcomer 74 will have to be made to control the viscosity and fluid loss control. If Bentonite is being used as the primary viscosifier, a separate premix tank independent of the rig tank must be used to prehydrate the Bentonite in fresh water prior to adding to the active system. If the fluid has to be saturated with Salt, adding prehydrated Bentonite in fresh water will dilute the Chloride content of the mud. Alternative viscosifiers such as Salt Gel or Kelzan XCD Polymer should be considered. 8. The second solution occurs where a massive Salt section is expected, and the hole is displaced to a saturated Saltwater system prior to penetrating the Salt section. The will avoid extensive hole washout, and contamination problems with a Gel base mud. In areas such as the Prairie Evaporite in S.E. Saskatchewan, or the Trout/Senex area of northern Alberta, this can be done easily with produced Brine water that is available in the area. The Brine water is displaced to the hole just prior to penetrating the Salt section. If the Brine water is not completely saturated, then ensure the fluid is brought to saturation with sacked Salt prior to penetrating the Salt Formation. 9. If Brine water is not available, then fresh water will have to be brought to saturation with sacked Salt as required. This will require approximately 311 kg/m3 (26% by weight) of sacked Salt.

Maintenance: 1. As the salinity increases in the fluid, so does the density. Saturated Saltwater with no drill solids will weigh approximately 1200 kg/m3. Refer to the Sodium Chloride salinity chart at the end of this section. In areas where a high density may be required without any solids incorporated into the fluid such as a workover or completion fluid, then the fluid can be formulated to a specific density with sacked Salt as required. 2. As with any other mud system, the funnel viscosity should be maintained just high enough for effective hole cleaning. The viscosity may be maintained with additions of prehydrated Bentonite, Salt Gel, or Kelzan XCD Polymer. Return to Table of Contents

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If Bentonite is used as the primary viscosifier, it must be prehydrated in fresh water first prior to adding to the active system. A MBT value of approximately 40-60 kg/m3 is normally maintained. Note: Adding prehydrated Bentonite with freshwater over to the active system with dilute the Chloride content of the Saltwater mud system. If a Salt saturated system is being run, further additions of sacked Salt will have to be added to the active system to ensure the system remains saturated with salt. Salt Gel may also be used in a Saltwater mud system as the primary viscosifier. Salt Gel is a Hydrous Magnesium Silicate (Sepiolite Clay). In comparison to Bentonite, Salt Gel is slightly less effective in its viscosifying power, and it does not have the ability to reduce the fluid loss of the mud system. It is more temperature stable, more inert to thinning in the presence of conventional thinners, and it more tolerant to mud contaminants. Salt Gel can be added directly to the Saltwater mud system, and will not dilute the chloride content of the mud. Kelzan XCD Polymer is not affected by the salinity of the mud system, and may be added as a primary or secondary viscosifier along with the prehydrated Bentonite or Salt Gel. 3. The PV (Plastic Viscosity) should be maintained as low as possible with effective used of the solids control equipment on the rig, and dilution. Also the Yield Point and Gel Strengths will run higher than conventional Gel Chem. Mud because the fluid is normally in a semiflocculated state. Desco CF and/or Alcomer 74 both work well in Saltwater mud systems as thinners or dispersants. 4. Saltwater muds can be very corrosive in nature, unless the fluid is saturated. A pH of approximately 9.5-10.0+ will aid in reducing the corrosion level in a Saltwater mud. This may be achieved with additions of Caustic Soda or Lime. Note: It should be noted though, that it takes approximately twice as much Caustic Soda to maintain the pH in the desired range as compared to a conventional fresh water mud system. This is due to the mass action of the Sodium ion (from the Salt) on clays, thereby releasing free Hydrogen ions, which in return will lower the pH of the fluid. A supplementary corrosion inhibitor is recommended when utilizing Saltwater mud system. Corrosion rings should be installed and monitored for the degrees of corrosion. 5. Fluid loss additives such as Drispac, Staflo, or Starpak DP are commonly used in Saltwater mud systems. If Drispac/Staflo and Starpak are used in conjunction, they are normally added in a 1:3 ratio respectively. Starch is another commonly used fluid loss additive for use in Saltwater mud systems. It should be noted though, that if Starch is being used, that a Bactericide should be used to prevent the Starch from bacterial fermentation. 6. Chloride titration’s should be made to determine if additions of sacked or bulk Salt will be required to maintain the Salt content in the range that was programmed. Refer to the Salinity chart at the end of this section to determine the amount of Salt required for a specific salinity. 7. Saltwater muds have a tendency to foam more than fresh water mud systems. The degree of foaming sometimes may be decreased by increasing the pH and Pf alkalinity of the mud.

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Return to Table of Contents A defoamer should always be stockpiled on location when utilizing a Saltwater mud system, in the event it may be required.

PROPERTIES OF SALT (NaCl) SOLUTIONS % Salt

Density (kg/m3)

1 3 4 6 7 9 11 12 14 15 17 18 20 21 23 24 26

1006 1018 1030 1042 1054 1066 1078 1090 1102 1114 1126 1138 1150 1162 1174 1186 1198

Salt Content (kg/m3) 8.56 25.68 45.65 62.77 79.89 99.86 116.98 134.10 154.07 174.04 194.02 211.14 231.11 251.08 271.05 291.03 311.00

Salt NaCl (mg/L) 10050 30660 41070 62480 73500 95760 118700 130300 153100 165800 190600 202700 229600 242800 269700 283300 311300

Chlorides Cl(mg/L) 6100 18600 24920 37910 44600 57500 71950 79070 92900 100500 115500 123000 139320 147200 163500 171900 188900


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Water Volume (m3) 0.998 0.996 0.993 0.981 0.976 0.969 0.952 0.952 0.948 0.940 0.933 0.926 0.919 0.909 0.902 0.895 0.888

Freezing Point (C) -0.6 -1.8 -2.4 -3.7 -4.4 -5.8 -7.4 -8.2 -9.9 -10.9 -12.9 -14.0 -16.5 -18.6 -20.7 -15.0 -3.9

2.9

CLAY FREE POLYMER MUDS (“CLEAR FLUID”)

Return to Table of Contents Clay free Polymer mud systems have become more popular over the past few years, particularly with the increase in directional or horizontal drilling. With the extended reach of the directional and horizontal wells today, there is a lot of “virgin” reservoir that is penetrated and produced. These horizontal reservoirs generally are “barefoot” completions, or produced through “slotted” liners. These reservoirs can therefore be more susceptible to formation damage than conventional vertical wells. The Clay Free Polymer or “Clear Fluids” as they are sometimes called, are used to a large extent for this purpose. Solids are kept to a minimum to minimize any damage to the potential productive reservoir. The fluid loss of the fluid is kept low to reduce the amount of filtrate to the productive zone. The Polymers used in these fluids have proven to be ideal for sufficient hole cleaning throughout horizontal sections. Two Polymers are generally utilized for viscosity control in these mud systems. Kelzan XCD Polymer or Xanvis Polymer are generally for primary viscosity control. Both work very well for viscosity control in these applications. Xanvis Polymer is a “cleaner or more refined” form of the Kelzan XCD Polymer. Kelzan XCD when acidized will leave a 3-5% residue that cannot be removed. Although minor, this residue can theoretically cause some damage to the potential productive zone. In the production process of manufacturing Xanvis Polymer, this residue is completely removed and when acidized, this Polymer allows for a complete “non-damaging” Polymer. This is advantageous for minimizing any potential formation damage. There is a premium to pay to achieve this though, as Xanvis Polymer is substantially higher in price than the conventional Kelzan XCD Polymer. Both products are very expensive as it is, and are both utilized in the horizontal drilling applications.

Make Up: 1. Generally in the horizontal well applications, the intermediate hole is drilled building angle to horizontal (90) with a Gel Chemical or Gel Polymer mud system. Intermediate casing is then generally run prior to drilling the potential productive zone horizontally. 2. While WOC, the Clay Free Polymer mud should be premixed as follows and allowed to prehydrate for as long as possible. 3. Dump and clean all the mud tanks thoroughly. Premix the following; Kelzan XCD Polymer: Drispac / Staflo: Starpak: Ultraseal XP:

1.5-2.0 kg/m3 2.0-3.0 kg/m3 6.0-9.0 kg/m3 3.0-4.0 kg/m3

4. Let this slurry hydrate and shear for as long as possible prior to displacing to the hole at mud up depth. Return to Table of Contents

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Return to Table of Contents Maintenance: 1. Displace the Polymer slurry to the hole at mud up depth. Build additional volume with fresh water. 2. When displacing, watch the shakers closely for Polymer “blinding”. Coarser screens may initially have to put on the shale shaker until the Polymer fluid passes through the bit a few times. 3. Drill ahead through the productive zone(s) with the Clear Polymer Fluid. 4. Additions of Kelzan XCD Polymer will be required to viscosify the slurry to the 35-50 sec/L range. Funnel viscosities in this range have generally been sufficient to drill the horizontal section of hole. 5. The Yield Point will generally run in the 5-10 Pa range with these types of systems. Hole cleaning in a horizontal section is generally not a problem as long as the annular velocity is maintained high enough. 6. A neutral pH is run with this system, unless H2S is anticipated. 7. It is imperative that the density remain as low as possible throughout the horizontal section of hole to minimize any formation damage to the potential productive zone. Generally a high speed linear motion shale shaker, and a high volume centrifuge is required to successfully run these systems. 8. A low fluid loss is required to minimize any formation damage. The fluid loss is generally run less than 7.0 cm3 with additions of Staflo/Drispac and Starpak DP as required. Staflo/Drispac and Starpak DP is normally added in a 1:3 ratio respectively. 9. Additions of 3.0-4.0 kg/m3 of Ultraseal XP is also commonly run to aid in fluid loss control with ideal particle size distribution. Ultraseal XP will also minimize any seepage losses throughout the horizontal interval, without plugging up the mud motor. 10. This fluid is normally not subject to bacterial fermentation when circulating. If the fluid is left static for an extended period of time though, such as logging, DST, etc., the fluid may begin to ferment. If the fluid starts to smell, a Biocide will be required. A Glutaraldehyde Biocide such as T-352 Biocide is the most environmentally friendly Biocide on the market, and when treated, can pass the Microtox. Recommended treatment: 0.1-0.5 litres/m3.

2.10

STABLE-K MUD SYSTEM


Stable-K is a specialized liquid product designed specifically for use as a replacement for Potassium Chloride (KCl) or Potassium Sulfate (K2SO4). Stable-K provides excellent shale and clay control, without the logistics, handling and mixing problems associated with large volumes of sacked KCl or K2SO4. Stable-K is compatible with all gels, crosslinkers, and breaker systems typically utilized in well stimulation and workover operations. It will not greatly affect fluid pH and, being non surface active, does not adversely affect formation wettability. Stable-K may be used in fresh water, acid or brine systems, and will not hinder the performance of acid corrosion inhibitors.

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Return to Table of Contents While Stable-K does not contain any Potassium, it is composed of a sophisticated, mildly cationic complex that function as KCl to control shale and clay activity. Unlike KCl or K2SO4, Stable-K may be easily mudded up “on the fly” therefore eliminating premixing. If Stable-K is mixed in fresh water without any Salts, the fluid can be easily disposed of without adverse effects on the environment. A 2% KCl solution contains 9700 mg/L of Chloride ion, while a functionally equivalent fluid containing Stable-K is Chloride free. This significantly reduce Chloride ion concentration greatly lessens the environmental risks associated with the use of KCl fluids. Stable-K Physical Properties: Product Form @ 70F Density Flash Point, F, (TCC) Pour Point, F pH

Clear Liquid 1055 kg/m3 <200 -40 9.0-10.0

Solubility Fresh Water High TDS Brine Hydrocarbon Ionic Charge

Soluble Soluble Insoluble Mildly Cationic

Application: Stable-K is typically applied at a concentration of 0.5 to 10 litres per cubic metre of fluid, depending on the percent of equivalent KCl being replaced, and the shale and clay quantities present in the wellbore and operation being performed. Where a 3% Potassium Chloride (KCl) is required to inhibit the shales, Stable-K is added to fresh water at a concentration of 3 litres per cubic metre. A mixing chart outlining the recommended use concentration of Stable-K for a specific KCl replacement is a given quantity of water is presented below.

Total Fluid Quantity of Stable-K Required for KCl Functional Equivalent

1 m3 4 m3 6 m3 8 m3 12 m3 16 m3 20 m3 24 m3 32 m3 80 m3

1% KCl 1 litre 4 litres 6 litres 8 litres 12 litres 16 litres 20 litres 24 litres 32 litres 80 litres

2% KCl 2 litres 8 litres 12 litres 16 litres 24 litres 32 litres 40 litres 48 litres 64 litres 160 litres

3%KCl 3 litres 12 litres 18 litres 24 litres 36 litres 48 litres 60 litres 72 litres 96 litres 240 liters


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4%KCl 4 litres 16 litres 24 litres 32 litres 48 litres 64 litres 80 litres 96 litres 128 litres 320 litres

5%KCl 5 litres 20 litres 30 litres 40 litres 60 litres 80 litres 100 litres 120 litres 160 litres 400 litres

2.11

POLYGLYCOL MUD SYSTEMS


These are anionic water based Polymer fluids, which use specialized Polyglycols to provide improvements in wellbore stability, lubricity, filtration control and formation damage. The Polyglycols are a range of liquid products, which effect improvements in wellbore stability by Hydrogen bonding within clay mineral layers, inhibiting the formation of a water hydrational layer, and thus preventing expansion of clay layers. To fully exploit this Hydrogen bonding effect, the Polyglycols are used in saline fluids, preferably with the presence of a inhibiting Cation such as Potassium Sulfate or Potassium Chloride. Polyglycols also exhibit a cloud point behavior. When above a critical temperature (the cloud point) the Polyglycol becomes insoluble in the saline base fluid, and forms dispersed Polyglycol droplets, which can inhibit shale by a secondary function of preventing water migration. The “clouded” Polyglycol fluid will effectively reduce filtration by forming a water repellent filter cake, and also acts as a lubricant. The use of Polyglycol and PHPA Polymers in these systems, further enhance inhibition by providing an encapsulation of shales. A correctly formulated and controlled Glycol system can exhibit inhibitive properties similar to those of an oil base drilling fluid. The high levels of wellbore stability, good lubricity, and low formation damage have seen these systems used in a number of extended reach, and horizontal wells through reactive shale/clay formations. These systems are normally run Gel free and non-dispersed. The pH is also normally kept low (7.5-8.0) to minimize clay hydrational effects due to Hydroxyl ions. A well controlled Polyglycol fluid, particularly if combined with a Potassium Salt such as Potassium Sulfate, will maintain a high degree of cuttings integrity, allowing good solids control to be achieved. In addition, the use of the Polyglycol will increase the solids tolerance of the fluid. These in combination allow maintenance of mud properties, and hole conditions at low dilution rates. These fluids, because of their limited dilution requirements, and optimum property maintenance, are often utilized in a manner similar to oil based drilling fluids. They are recycled between sections, and wells, further reducing the economics of using such fluids, and greatly reducing the environmental impact of these low toxicity fluids. Make Up: 1. For best results, the system should be free of all drilled solids. Dump and clean the mud tanks and rebuild volume with water. 2. If Potassium Sulfate was used for the upper flocculated water portion of the hole, then utilize as much clear sump water as possible to fill the tanks. Fill the tanks ± ¾ full with water. Note: Quite often the Polyglycol is used while clear water drilling for shale inhibition throughout the water drilling portion of the hole. Use this fluid for make up at mud up depth. 3. Add the required amount of K2SO4 (Potassium Sulfate) through the hopper to bring the Potassium concentration up to the desired level. Generally a minimum concentration of 3540 kg/m3 (3.5-4.0% by weight) will be required. The Potassium ion concentration should be no lower than 16000 mg/L. 4. Return to Table of Contents

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5. 6. 6.

7.

8. 9.

Add or increase the concentration of the Polyglycol to 3% by volume (30 litres/m 3). This is generally the accepted level of Polyglycol that will be required for shale inhibition in Western Canada. Some foaming may occur but should easily be controlled with small additions of a Defoamer. A stockpile of Defoamer should be on location in the event it may be required. If a PHPA Polymer has been programmed for added shale inhibition, it should be added now normally in a concentration of 1.5-2.0 kg/m3. Then add approximately 1.5-2.0 kg/m3 of Kelzan XCD for primary viscosity control. The Potassium Sulfate / Polyglycol systems are normally run clay free; i.e.: no Bentonite in the mud system. After the Kelzan XCD has been mixed, fluid loss reducing Polymers should then be added. For these systems, Drispac and Starpak DP are normally mixed together in a 1:3 ratio respectively. Concentrations of ±3.0 kg/m 3 of Drispac Regular and ±9.0-10.0 kg/m3 of Starpak DP are normally mixed for an initial concentration. All Polymers should be mixed slowly through the hopper at a rate of ± 25-30 min.’s/sx. Potassium Sulfate / Polyglycol systems can be corrosive in nature. Corrosion rings should be installed and monitored with these types of mud systems. An Oxygen Scavenger such as Corinox or Sodium Sulfite is normally added to control corrosion levels to an acceptable level with the Polyglycol systems. Corinox is an unique dual purpose corrosion prevention chemical mixture in a liquid form. It has the ability to scavenge dissolved Oxygen effectively, as well the capability to absorb onto active corrosion sites (anodes) on drill pipe, casing, and tubing in water base muds. Under normal conditions for a corrosion level of about 25 mils per year (25 mpy), initially one (20L) pail of Corinox per 16 m3 of fluid is added. If Sodium Sulfite is being used as on Oxygen scavenger, it is added continually until the residual Sulfite (SO3) concentration in the mud filtrate reaches or exceeds 300 mg/L. Return to Table of Contents

Maintenance: 1. The mud density should be maintained as low as formation pressures will allow. If an increase in density is required, generally Barite or Calcium Carbonate is used. For an unweighted Polyglycol system, all solids control removal equipment should be run continuously using the finest possible screens on the shale shakers. If a centrifuge is available, it should be big enough to process the circulating volume of the active system. 2. The viscosity should be maintained just high enough for effective hole cleaning. This is normally achieved with additions Kelzan XCD Polymer only. Normal concentrations: 1.5-2.0 kg/m3. 3. The Plastic Viscosity (PV) of the mud will correlate to the solids make up of the mud system, and should be kept as low as possible with dilution, and the effective solids control equipment on the rig. As with the Potassium based mud systems, effective solids control equipment is vital. High speed linear motion shale shakers, and high volume centrifuge(s) are highly recommended with these types of muds. 4. Because of the Polymer nature of the system, the Yield Point (YP) of a Polyglycol mud will normally run higher than that of a conventional Gel Chemical system. The Gel Strengths will also be higher, but are generally flat and fragile. Kelzan XCD Polymer is an excellent product for increasing the YP or initial Gel Strength if added hole cleaning is required.

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5. The pH of the mud system should remain neutral unless H2S is anticipated. If an increase if pH is programmed, then control in the desired range with additions of Caustic Soda or Lime as required. 6. In order to minimize the possibility of differential sticking, and to minimize the overall amount of water going into the potential productive zone(s), the fluid loss is generally lowered to the 6.0-8.0 cm3 range with additions of Drispac and Starpak DP as required. Drispac and Starpak DP are normally added in a 1:3 ratio respectively. Drispac Regular is also normally added in these systems to supplement the viscosity. If a decrease in fluid loss is required, without any additional viscosity increase, then utilize Drispac SuperLo. 7. Note: If a neutral pH has been a programmed, or if the fluid is sitting static for an extended period of time; i.e.: testing, logging, etc., the Polymers in this system may begin to ferment. If the fluid begins to smell, a bactericide will be required. A common bactericide that can be “de-activated” at the end of the well without environmental repercussions is T352 Glutaraldehyde.

8.

9. 10. 11.

The recommended treatment is dependent on the severity of the bacterial contamination. As a pretreatment, add 0.1-0.5 litres/m3 to the mud system and monitor with microbial dipslides. For combating contaminated fluids, add 0.5-2.0 litres/m3 per treatment until bacterial control is achieved As drilling progresses, daily additions of Potassium Sulfate will have to be made to ensure the Potassium ion does not fall below 16000 mg/L (35-40 kg/m3), or as outlined in the mud program. The Potassium ion should be monitored closely. The Polyglycol concentration should also be monitored and maintained at 3% by volume (30 litres/m3). Continue to add and maintain 1.5-2.0 kg/m3 of PHPA Polymer throughout the interval for added shale encapsulation. Corrosion rings should be installed and monitored while drilling with the K2SO4 / Polyglycol system. The corrosion level should be controlled as outlined by the drilling program with an Oxygen scavenger such as Corinox or Sodium Sulfite as required.

2.12

SILICATE MUD SYSTEMS


The majority of Silicate mud systems run have been on offshore operations around the world, where highly active or “gumbo” type of clay formations are drilled. They are quite expensive, run in conjunction with KCl (Potassium Chloride) and therefore have been somewhat limited for use on onshore operations such as Western Canada, where less active hydratable clays are drilled. For the sake of this manual through, the system will be documented. Silicate mud systems is a solution of Sodium Silicate in water (30.3% by weight). Sodium Silicate is normally added to conventional Salt / Polymer mud systems to enhance shale inhibition. Silicate muds with 3-10% by weight KCl or K2SO4 give exceptional shale recovery, approaching that achieved with the Invert mud systems. They are therefore suitable for drilling highly reactive clay and dispersible chalk formations.

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Return to Table of Contents The primary shale inhibitor in the system is the Sodium Silicate which precipitates or Gels on contact with divalent ions and lower pH in the formation, providing an effective water barrier which prevents hydration and dispersion Secondary shale inhibition is achieved by the cation exchange of the Potassium with the formation clays, thereby reducing the swelling tendency of the clays by direct interference with the swelling mechanism. Additions of PAC fluid loss Polymers also provide inhibition by encapsulation, and preventing dispersion of clay particles into the fluid. Standard anionic Polymers for fluid loss or viscosity control are fully compatible with Sodium Silicate. Conventional ionic thinners are not effective in Silicate systems. Additions of water, whole mud or non-viscosified premix is recommended to reduce the viscosity. Conventional water soluble lubricants are also not compatible with Silicate fluids. Sodium Silicate is highly inhibitive and is run as a non dispersed system, therefore higher than usual Yield Points and low shear end rheology values will be required to ensure hole cleaning. The pH of the system is higher than conventional muds, being in the 11.0 - 12.0 range. (This pH is due to the Oxide in the Silicate itself). The Silicate will precipitate out divalent ions present in the hardness from seawater (if used, for offshore operations), thus reducing the concentration of Silicate in the system. For this reason freshwater is recommended for fluid preparation. However seawater may be used if pretreated with Caustic Soda and Soda Ash. The concentration of Silicate in the mud can be measured, using oilfield recommended tests as outlined in Chapter 1, Section 1.31. From this concentration, Sodium Silicate in the system is calculated. Sodium Silicate may be added directly to the mud or through premixes to maintain the desired concentration. (  4.0 – 6.0 % by weight Sodium Silicate by volume). Make Up: Generally for offshore operations, the initial delivery of KCI brine and Sodium Silicate solution will be as a concentrate, ready to be cut back with fresh water. The brine concentrate normally contains up to  200 kg/m3 of KCI, and  I5% by volume Sodium Silicate, and a base concentration of Polymers (final Polymer concentrations to be advised). The mixing order of Polymers under normal conditions is not critical, but depends more on the mixing and shear facilities on the rig. 1. Take required volume of KCI / Sodium Silicate brine into the mud tanks and cut back with an equal volume of fresh water to give approximately a  100 kg/m3 KCI and 7.5% Sodium Silicate solution. This high of concentration of Potassium Chloride is normal for the highly active hydratable clays for offshore operations. This high of concentration would not be required for Western Canada. 2. If the use of fresh water is not possible, seawater can be used, however, this must be treated with Caustic Soda and Soda Ash to remove any hardness before adding to the KCI / Sodium Silicate brine. 3. Return to Table of Contents

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If this is not done, the Silicate will be precipitated out by the divalent ions in the seawater, thereby reducing the concentration of Sodium Silicate in the fluid. This can, if necessary, be rectified by further additions of Sodium Silicate. 4. Add the Polymers to achieve the final concentration as indicated in the mud program. These Polymers should be added slow enough to avoid the formation of “fish eyes”. The addition of Polymers can result in a small reduction of measured Sodium Silicate in the filtrate, due to the Silicate complexing with the Polymers. Additional Sodium Silicate may be required to maintain the desired concentration in the mud. 4. Add Barite if required, to the correct density, and then adjust the properties if required with Polymers.

If the mud is being prepared without the use of KCl / Sodium Silicate concentrate, the preferred order of mixing would as follows: 1. Prepare KCI brine cut back to the required concentration with fresh water or seawater (treated with Caustic Soda and Soda Ash to treat out hardness). 2. Add the Polymers to the specified formulation, and shear for as long as possible. 3. Add the Sodium Silicate as required. Note: Specific personal safety precautions should be taken when handling undiluted Sodium Silicate. 4. Add Barite as required.

Formulation: The Sodium Silicate / KCI system uses conventional Polymers for fluid loss and viscosity control. A typical formulation for the Sodium Silicate fluid to drill out a 444.5 mm hole section is as follows: KCl: Sodium Silicate: Fresh Water: Caustic Soda: Soda Ash: Drispac/Staflo Reg: Drispac/Staflo SL: Kelzan XCD Polymer:

70-115 kg/m3 (depending upon activity of the shale and mud program) 5% by weight As required As required to treat out the hardness As required to treat out the hardness 4.0-4.5 kg/m3 4.0-4.5 kg/m3 4.0 kg/m3 (or as required to achieve a 6 rpm value)

Note: No prehydrated Gel is used generally in field formulations, since after displacement, better control of rheology & fluid loss is obtained once drill solids are built in the system. This then avoids having flocculation of the system when mixing, and no depletion of Silicate is due to being taken up by any mixed Gel. A typical laboratory formulation of unweighted Sodium Silicate system, prepared from concentrated KCI brine, cut back with fresh water, gives the approximate results listed below.

600 rpm 300 rpm 200 rpm 100 rpm 6 rpm 3 rpm

101 79 68 53 20 16

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PV YP pH Total Hardness API Fluid Loss

22 Pa 28.5 Pa 11.7 0 12.0 cm3 Return to Table of Contents

Maintenance: 1. The desired Yield Point and low shear values (6 rpm) are readily obtained by treatment as required with XCD Polymer. Any reduction of undesirable high rheological values should be effected by dilution as required with Brine concentrate or fresh whole mud dilution. It is important to note that, due to the highly inhibitive nature of the Sodium Silicate mud, it is likely that incorporated drill solids will have little effect on rheology. Fluid viscosity will be derived almost entirely from Polymer concentrations used, and higher than usual Yield Point and low shear values will be required to ensure adequate hole cleaning. 2. Maintain fluid loss control by treatment as required with Drispac / Staflo (Reg) or LV depending on the viscosity requirements of the mud. Note that the freshly prepared solids free fluid will exhibit relatively high fluid loss values, until drill solids have been incorporated into the mud system. 3. Maintain Sodium Silicate concentration in the recommended range by addition of Sodium Silicate brine concentrate or by direct addition of the undiluted product. It is imperative that 'in and out" Sodium Silicate concentrations are monitored and recorded on a regular basis while drilling, to gauge the rate of depletion and treatment requirements. Note that laboratory work has established that there is some Sodium Silicate depletion with increasing Polymer concentrations This effect appears to be are marked with Starches and Xanthum Gum products (Kelzan XCD), than with anionic Polymers such as PAC. It is anticipated that a properly treated Sodium Silicate fluid should result in excellent cuttings integrity and gauge hole conditions. 4. Maintain KCl, concentration within the recommended range by addition of brine concentrate or direct addition of powdered KCI to the active system. Monitor and record “in and out" KCI concentrations an a regular basis while drilling, to determine the depletion rate and treatment requirements. 5. It is important to note that the highly inhibitive nature of the Sodium Silicate fluid will result in a higher quantity of cuttings being produced when drilling the highly active shales and consequently higher than usual loadings at the shale shakers may be experienced during this interval. Use all available solids control equipment as efficiently as possible to minimize undesirable mud density increases from drilled solids accumulation and reduce dilution requirements.

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Return to Table of Contents 6. As previously stated, it is anticipated that drilled solids incorporation should have minimal effect on fluid rheology.

7.

8. 9.

10.

As a general guideline it is recommended that a “dump and dilute" conditioning treatment may be required when MBT values greater than 60 kg/m 3 (Bentonite equivalent) are measured. The pH of the Sodium Silicate system is buffered in the range 11.0-12.0. As the pH is not derived from Hydroxyl ions, this is not in itself hazardous. However, the recommended safe handling procedures must be adhered to particularly when handling undiluted Sodium Silicate. As Sodium Silicate precipitates in contact with Calcium and Magnesium, the system will contain zero hardness. Silicates have an industrial application as a corrosion inhibitor of metals, and additional corrosion reducers will not be required in the drilling fluid. There will be no free oxygen in the system, and any Silicate reaction with ferrous material forms a Silicate coating which prevents any further reaction. The Silicate system will have a naturally high pH. However this is from SiO 2 and not from the Hydroxyl (OH-) radical, and therefore will not suppress bacterial growth. If the Silicate system is to be stored for any length of time, conventional treatment of Biocide should be added as for conventional water based Polymer muds.

2.13

Mixed Metal Hydroxide (MMH) Mud Systems Return to Table of Contents

The MMH system is based upon a Mixed Metal Hydroxide (MMH) which imparts truly unique rheological properties to the fluid. Mixed Metal Hydroxide based fluids exhibit low viscosity at the bit, yet Gel instantaneously as flow ceases, to carry and suspend cuttings and keep the hole clean. The system provided superior hole cleaning to that of conventional fluids, making it an ideal choice for directional or horizontally drilled wells. General: 1. The surface system should be built with fresh water and MMH prior to displacing to the hole. A spacer should be run ahead of the MMH system to avoid any contamination. After the system has been displaced to the hole, seawater or freshwater may be used for dilution to the active system. 2. Natural (unpeptized) Bentonite must only be used for this system. The Natural Bentonite should be prehydrated in fresh water prior to being added to the active system. Natural Gel and Polyvis II (Mixed Metal Hydroxide) will be added in a 10:1 ratio respectively for viscosity control. The MBT of the active system should be maintained no higher than 30 kg/m3. This should be controlled by dumping and diluting as required. 3. The system is run in a non-dispersed manner. Any anionic products such as thinners, (Alcomer 74L, Lignosulfonates, Lignite) should be avoided as it could destroy the viscosity complex of the MMH. Any cellulose LCM material such as Sawdust or Prima Seal should also be avoided as they may contain Lignins that would also reduce the viscosity. “Small” amounts of Drispac SL or Staflo ExLo (Polyanionic Cellulose Polymers) may be initiated to reduce excessive rheological properties should they occur. Pilot testing should be done prior to making any of these additions. 4. A low fluid loss and thin filter is recommended for this system.

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Lowering the hardness (Calcium content) of the make up water to 40-80 mg/L will increase the effectiveness of the fluid loss Polymers. Fluid loss control must be maintained with a non-ionic filtration control Polymer such as Starpak II or Polytrol.

Engineering Guidelines: 1. The Mixed Metal Hydroxide (MMH) system is extremely sensitive and responsive to treatment with anionic fluid loss reducers such as Drispac SL or Staflo ExLo for reducing rheology.

2. 3.

4.

5. 6.

Normal treatments above 0.3 kg/m3 are not required. Great care should be taken if using these additives, and pilot testing before use is recommended. The use of Drispac SL or Staflo ExLo in the MMH system is intended solely for a reduction of theology, and not as a supplementary filtration control additive. Prehydrated Natural Bentonite and Polyvis II (Mixed Metal Hydroxide) should be used in a ratio of 10:1 by weight respectively. Gels will be elevated with some progression. A high 10 minute Gel is no however, detrimental as the Gel Strengths in the system are extremely fragile. The 6 and 3 RPM readings should be flat. Cuttings should be hard and coherent. If they are not, add more Polyvis II MMH and/or prehydrated Natural Gel. Bentonite and Polyvis II should be kept in the ranges of 25-30 kg/m3 and 2.2-2.8 kg/m3 respectively. Polyvis II MMH should be added through the chemical barrel (pre-dispersed in fresh water). Additional Polyvis II MMH is required if the following events are observed: The Yield Point and PV stay the same, while the 6 and 3 rpm reading drop. The 6 and 3 RPM readings should remain elevated and flat.

Make up / Maintenance: 1. Initially clean all the mud tanks while WOC. Fill with fresh water, and add 0.75-1.0 kg/m3 of Soda Ash as required to treat out the Calcium to 40-80 mg/L. 2. Adjust the pH of the water to 10.0 with Caustic Soda. 3. Mix 30 kg/m3 of Natural Gel. Let the slurry hydrate for as long as possible – minimum of 6 hours. 4. The add 2.0-3.0 kg/m3 of Polyvis II MMH, mixed with fresh water through a chemical barrel. 50 lbs. of Polyvis II MMH will easily disperse into a chemical bbl. full of water. Adjust the pH to 10.0-10.2. 5. Add 12.0 kg/m3 of Starpak II for fluid loss control. 6. Displace the hole to the premixed Mixed Metal Hydroxide system. A spacer must be run ahead of the MMH system to avoid any contamination from the previous system. A 5-6 m3 water spacer, immediately followed by 5-6 m3 of a high viscosity (75-80 kg/m3) Bentonite slurry is recommended. 7. Drill ahead maintaining the mud density as low as pressures will permit with dilution and the solids control equipment on the rig. Dilution may be done with the premixed Natural Bentonite and Polyvis II additions, and/or adding water to the active system only.


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8. The funnel viscosity is mostly erroneous in this system, but can be controlled in the range of 45-80 sec/L with prehydrated Natural Gel and Polyvis II MMH in a 10:1 ratio respectively. Maintain a MBT no higher than 30 kg/m3. Decreases in viscosity can be made with slight additions of Drispac SL or Staflo ExLo. Always pilot test prior to making and Drispac or Staflo additions. 9. The PV should be controlled at the minimum level realistically possible by making use of all solids control equipment. An increase in the PV is indicative of a solids control increase, and appropriate measure for reduction should be implemented with whole mud dilution and the solids control equipment. 10. A YP of 10-25 Pa should be sufficient for proper hole cleaning. Excessive values can be can be controlled with whole mud dilution, water dilution, or additions of Drispac SL or Staflo ExLo (after pilot testing). 11. Excessive Gel Strengths can be circumvented by efficient solids removal, and maintaining the correct ratio of Prehyrated Bentonite and Polyvis II MMH at a 10:1 ratio. The 3 and 6 RPM dial reading should be controlled at 20-50 Pa, while remaining flat. Use small amounts of Barite or Calcium Carbonate (Limestone) to slug the drill pipe prior to trips. 12. Continue to maintain a pH of 10.0-10.5 throughout the interval with additions of Caustic Soda. Lower and maintain the Calcium content of the mud to 40-80 mg/L with additions of Soda Ash. Completion: At the completion of drilling, all possible MMH fluid should be recovered from both the active system and the hole. This fluid should be saved in a totally isolated tank, and saved for use on the next horizontal well. Once the liner or production casing is landed, displace all possible Mixed Metal Hydroxide mud from the hole with water. When the casing is displaced and all the MMH fluid is removed, run into the bottom of the liner or casing, and displace the balance of the hole with water while working the pipe. When the fluid in the hole is well watered back, add 2.0 litres/m3 of T-2001 De-Emulsifier to the circulating system. Work the drill pipe out of the liner in stages, while circulating and rotating, to remove as much Mixed Metal Hydroxide as possible from behind the liner.


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TABLE OF CONTENTS – CHAPTER 3 Return to Glossary Chapter 3 TOPICS 3.1 3.2 3.3 3.4

3.5

3.6

3.7

3.8

3.9 3.10

3.11

Oil Base Mud Systems Return to Table of Contents PAGE

OIL MUD APPLICATIONS RIG MODIFICATIONS FORMULATION DISPLACEMENT 3.4.1 Recommendations Prior to Displacement 3.4.2 DISPLACEMENT OIL MUD TESTING PROCEDURES 3.5.1 DENSITY and MARSH FUNNEL VISCOSITY 3.5.2 RHEOLOGY AND GEL STRENGTH MEASUREMENT 3.5.3 FLUID LOSS 3.5.4 ELECTRICAL STABILITY 3.5.5 OIL MUD ALKALINITY 3.5.6 OIL MUD CHLORIDE CONTENT 3.5.7 OIL MUD CALCIUM CONTENT 3.5.8 OIL MUD RETORT 3.5.9 OIL MUD HYDROGEN SULFIDE DETERMINATION 3.5.10 “HOT or QUICK” LIME TEST 3.5.11 ANILINE POINT DETERMINATION OIL MUD CALCULATIONS ( Envirofloc Internal Water Phase Only ) 3.6.1 CALCULATION OF WATER PHASE SALINITY 3.6.2 WATER ACTIVITY 3.6.3 CORRECTED SOLIDS 3.6.4 OIL / WATER RATIO 3.6.5 CHANGING THE OIL / WATER RATIO 3.6.6 HIGH AND LOW GRAVITY SOLIDS ( Weighted Invert ) OIL MUD CALCULATIONS ( Mixed Salts - Internal Water Phase Only ) 3.7.1 CALCIUM SOURCE 3.7.2 LIME CONTENT 3.7.3 WHOLE MUD CALCULATIONS ( Mixed Salt Content 3.7.4 LIQUID PHASE CALCULATIONS 3.7.5 CORRECTED OIL / WATER (OWR) RATIO 3.7.6 INERT SOLIDS CALCULATIONS 3.7.7 EXAMPLE CALCULATIONS INVERT PROPERTIES AND MAINTENANCE 3.8.1 MUD DENSITY 3.8.2 FUNNEL VISCOSITY 3.8.3 PLASTIC VISCOSITY 3.8.4 YIELD POINT and GEL STRENGTHS 3.8.5 ELECTRICAL STABILITY 3.8.6 FILTRATION 3.8.7 ACTIVITY / SALINITY 3.8.8 RETORT 3.8.9 EXCESS LIME CONTENT OIL MUD ENGINEERING GUIDELINES OIL MUD FORMATION LOSSES 3.10.1 SEEPAGE LOSSES 3.10.2 CONVENTIONAL OIL MUD “LCM” PILL (Whole Mud Loss) 3.10.3 DIASEAL “M” SQUEEZE (Oil Muds) OIL MUD PRODUCT CROSS REFERENCES

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1 1 2 3 3 4 4 4 5 5 6 7 8 8 9 10 11 12 12 12 13 13 18 19 20 23 23 24 24 25 26 26 27 38 38 38 39 39 40 40 40 41 41 42 44 44 45 46 47

CHAPTER 3 OIL BASE MUD SYSTEMS An oil base mud is defined as a mud, which contains oil as the continuous, or “outer” phase. Usually diesel oil is used as the continuous phase. These muds usually contain water emulsified into the oil as the non-continuous or “internal” phase. The amount of water emulsified into the oil determines the type of oil mud. Oil mud containing greater than 5% water by volume, are called Invert Emulsion muds. In addition to oil and water, oil muds contain emulsifiers, Hot Lime, preferential oil wetting agents, sometimes filtration control additives, oil wetting gellants, and possible weight material if required. Oil muds are normally used to solve specific problems which either cannot be solved by water base muds, or because oil muds offer a more economical solution.

3.1 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14. 15.

3.2

OIL MUD APPLICATIONS


To drill water sensitive swelling or sloughing shales. To protect production zones while coring or drilling. To decrease torque or drag while drilling directional wells. To prevent loss of circulation in subnormally pressured formations. To obtain native state cores. As a spotting fluid to free differentially stuck pipe. To leave between tubing or casing as a packer fluid for corrosion protection. To leave between casing and open hole as a casing packer fluid. To drill through Hydrogen Sulfide bearing formations. To drill deep, hot holes. To minimize areas where excessive hole washout is a problem. To drill formations that contain contaminants, such as Salt, Anhydrite, etc. To reduce melting when drilling through permafrost. As a workover fluid. As a perforating and completion fluid.

RIG MODIFICATIONS


Before drilling out the surface casing, the following rig modifications should be made to help control costly mud losses on the surface, reduce maintenance, and minimize potential pollution problems. 1. A kelly cock or mud saver should be installed. 2. A mud can with a return line to the mud tanks should always be used on trips, especially to pull a wet string. 3. A catch pan should be installed on the top of the bell nipple. This should be large enough to extend beyond the edges of the table. This device will catch mud, which falls through the table and will divert it into the drilling nipple. 4. If possible a racking pan should be provided for the drill pipe. A return line from this pan must be run to the flowline or into the catch pan beneath the table. 5. A pipe wiper should always be used on trips.

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6. Due to the high cost of diesel, and water being a contaminant, all water lines that might allow water entry into the active system, should be plugged. Rig crews should be educated in the importance of keeping water from draining into the mud tanks. Washing off the shaker screens should be done with diesel. 7. A pill tank or slugging pit should be available on the rig to eliminate pulling wet pipe on trips. 8. The mud tanks should be checked thoroughly prior to drilling out, to ensure that all mud guns are wedged down properly, the gates between compartments or to the sump do not leak, and the centrifugal pumps are in good working order. 9. The mud gates should be packed thoroughly with a Diesel-Gel sludge to ensure no leakage. 10. The lease should be properly ditched around the rig to ensure no spilling. A separate pit, buried or surface tank should be positioned to collect the cuttings from the shaker and the underflow from the centrifuge(s). 11. An adequate supply of upright storage tanks for transferring liquid Invert or Brine water should be spotted on location in a convenient location. A small pump should be rigged up to the storage tanks, in order that they may be circulated prior to adding to the premix and active tanks. 12. Check that all rubber parts are oil proof (hydril, pump parts, etc.) Change centrifugal pump packing lubricant from water to grease. 13. If possible, install a pneumatic or hand bung pump to provide accurate metering of liquid emulsifiers or conditioners into the active system. 14. Any welding should be done on the rig prior to filling the mud tanks with premixed Invert. 15. The rig crews should be supplied with slicker suits, and proper oil resistant footwear, and gloves. Oil absorbent material such as "Floor Dry” or Alfob “W" Absorbent should be available for the stairs, walkways and rig floor. 16. A safety meeting should be arranged at the location so that all personnel concerned know and understand the use and cost of an Invert mud system.

3.3

FORMULATION


1. Open all of the mud guns and the suctions on the mixing tank to thoroughly drain any water that may be present. Clean the tank(s) and seal the gates shut with a mixture of Bentonite and water to a “sludge” consistency. 2. Add the desired volume of diesel fuel in the mixing tank using proper precautions. (See recommended specifications for diesel fuel). Add the diesel oil through the hopper if possible. 3. Run all the subsurface guns, mixing hopper, and agitators to obtain the maximum amount of shear possible. 4. Add the required amount of emulsifiers through the hopper. Mix thoroughly until the solution is homogeneous. 5. Add “Hot Lime” or “Quick Lime” as it is sometimes called (Calcium Oxide; CaO) through the hopper using proper precautions. Mix thoroughly. 6. In a separate tank or compartment, premix the Brine water for the internal phase to the proper concentration. The Brine water may be made up of Calcium Chloride 97%, Calcium Nitrate (Envirofloc), or a combination of both Salts. 7. Transfer the required amount of Brine water in the Diesel mixture, preferably through the hopper. Let this mixture shear through all shearing devices for a minimum of ¾-1 hour. The longer the fluid is sheared, the tighter the emulsion will be. 8. Add the required amount of gelling agent (organophyillic clay) through the hopper. 9. Continue vigorous mixing for 1-2 hours in order to make a homogenous and stable emulsion. Check the sample for separation, etc.

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10. If weight material is required, add through the hopper at this time. Do not add any weight material while adding Brine water. Barite may become water wet, and could settle to the bottom of the tanks if mixed at the same time as the brine water. Shear the mud for as long as possible. 11. Check for settling of Barite at the bottom of the mixing tank. If the mud is too thin or Barite is settling, add additional Organophyllic Clay slowly through the hopper to thicken the fluid. 12. If the fluid is too thick, more diesel fuel or an oil wetting agent may be added to thin the fluid. Note: If Envirofloc (Ammonium Calcium Nitrate Decahydrate) is used as the make up for the Brine water phase, it must be mixed in a well-ventilated area. Ammonia gas may be released when Hot Lime and Envirofloc (Calcium Nitrate) are mixed together.

RECOMMEDED DIESEL OIL SPECIFICATIONS FOR AN OIL BASE DRILLING FLUID

Properties Gravity, API Color, Robinson Flash Point, PM C Pour Point, C Viscosity @ 38 C, SSU Carbon (10% Bottoms) Ash, % Bomb Sulphur, % Corrosion 3Hr @ 100 C Cetane Number Suspended Sediment Dissolved Sediment Bromine Number Diesel Index Aniline Point, C % Aromatics (+Olefins) *

**

Typical Specifications Preferred 36.0 25 67 -21 35.5 0.01 Nil 0.16 J3 50.8 0.1 0.9 1.43 54.5 65 21.8

33.0-39.0 20-30 54 minimum -12 to –9* ** ** ** 0.15-0.32 ** ** ** ** ** ** 57 minimum 18-30

A lower pour point material may be suitable for use, but should be checked by a lab prior to use. Diesel with pour points lower the -9 C usually indicates that a pour-point depressant has been added. These depressants could cause a weakening of the emulsion with increased viscosity and Gel Strength. Not Critical

3.4

DISPLACEMENT

3.4.1

RECOMMENDATIONS PRIOR TO DISPLACEMENT

1. 2. 3. 4. 5.

Acceptable Range


Clean the mud tanks and check that the gates do not leak. Secure all the water lines. Check that all rubber parts are oil proof (hydril, pump parts, etc.) Install a diesel wash gun or diesel bucket at the shaker. Install saver sub on kelly, mud bucket, and wiper rubber for the pipe when tripping.

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6. Change centrifugal pump packing lubricant from water to grease. 7. In areas where excessive rain or snow is to be expected, pits should be covered. 8. If possible, install a pneumatic or hank bung pump to provide accurate metering of the liquid emulsifiers into the mud system. 9. Provide absorbent materials for stairs walkways and rig floor. 10. If the mud tanks are covered, provide fans for proper ventilation.

3.4.2

DISPLACEMENT


1. Preferably, the displacement should be made inside the surface or intermediate casing. Pull up 10 metres into the casing. 2. Initially, put on relatively coarse screens on the shale shaker in the event some blinding does occur until all the solids become oil wet. After a circulation or two, replace with fine mesh screens if required. 3. Ensure that the return line is rigged up properly, so that the fresh water fluid in the casing can be dumped to the sump. 4. Fill the slugging or pill tank with diesel. There should be enough volume to place a - 200 metre spacer between the Invert and water base fluid.

150

5. Prime the main pump with Invert and line it up on the hole. The standby pump should also be primed, and ready in case the main pump breaks down. 6. Start to displace with the Invert, making sure the fluid in the casing is being dumped to the sump or a buried tank. Have enough premixed Invert on location to fill the hole and fill the active mud tanks approximately 2/3 full. 7. Displace the Invert in either plug or turbulent flow, as laminar flow promotes channeling. Excellent results have been obtained where plug flow has been utilized in open hole displacements. 8. Slowly reciprocate and rotate the drill string. Try and maintain a constant pump pressure. 9. Watch the diesel spacer closely as it comes out of the flowline to the sump. It could be relatively thick at the interface between the two fluids. Let the Invert cleanup somewhat before putting it over the shaker. 10. Put the Invert over the shaker and circulate the hole. If plugging of the shaker screens occur, wash with a brush or diesel gun (not water). Small amounts of an oil-wetting agent should also be added into the shaker box. 11. As the mud gets warmer, and is sheared through the bit, the mud properties will improve.

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3.5

OIL MUD TESTING PROCEDURES


There are a few unique tests that are required for an oil base drilling fluid. Collect about 2 litres of mud coming out at the flowline after passing through the shale shaker. Note the date, depth, and time of sampling. Record the temperature of the mud sample at the time each measurement is made.

3.5.1

DENSITY and MARSH FUNNEL VISCOSITY

1. The mud density and funnel viscosity are done in the same manner as on a water base mud system. 2. To accurately monitor the density, it is recommended that a Tru-Weight Pressurized Mud Balance be used periodically. 3. Clean the funnel and mud balance with diesel or solvent.

3.5.2

RHEOLOGY AND GEL STRENGTH MEASUREMENT

Equipment:


1. 6 Speed VG Meter 2. Thermal Heating Cup Procedure: 1. Due to the profound effect temperature has on an oil base mud, it is imperative for accurate results that all rheology tests are done at a consistent temperature. 2. Pour a sample of Invert into a thermal heating cup. 3. Run the VG meter at 600 rpm to stir the sample of mud while it is heating to 65 C (150 F). By heating the sample in this manner, it will ensure that both the mud and the “bob” of the VG meter are at the same temperature for an accurate rheology. 4. Take the rheology and Gel Strengths when the temperatures constant at 65 C. The PV, YP and Gel Strengths are taken in the same manner as a water base mud system outlined in Chapter 1. 5. Clean the VG meter and thermal cup with diesel or solvent.

3.5.3

FLUID LOSS


1. An Invert mud system normally has an API fluid loss of zero. Therefore, a HT-HP (High Temperature – High Pressure) fluid loss should be run. 2. Run the HT-HP fluid loss the same as a water base mud system outlined in Chapter 1. The temperature should be run at 5-10 C above the bottom hole temperature, and at a differential pressure of 3500 kPa (500 psi), unless otherwise specified by the oil company. 3. Clean the HT-HP fluid loss cell with diesel or solvent.

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3.5.4

ELECTRICAL STABILITY


The Fann Model 23C has been upgraded to a Digital Fann Model 23D, or an OFI Model E30A. The tests are performed in the same manner, but a lower voltage reading is displayed when taken with the digital meters. The performance of the digital ES meters is superior to that of the older Model 23C, because the automatic ramp of voltage is accurate and constant. The Fann Model 23C makes it measurements with a spiky, non-symmetric wave form, while the digital meters make their measurements with true sinusoidal wave forms, with symmetry about the ground reference. Because of the potential for confusion when comparing the measurements made with the different types of ES meters, it is advisable to always note the type and model number of the instrument used when reporting the ES measurement. FANN MODEL 23C OPERATION: Equipment: 1. A glass or plastic container 2. Fann Model 23C ES meter 3. Mallory No. TR136R (8.1 volts) battery or equivalent Duracell EL-4423 battery Procedure: 1. Heat the sample to be tested to 65 C (150 F). 2. Pout a sample of mud into the container and immerse the probe to a depth of 25 mm (1 inch). 3. Turn the dial to zero. Depress the red button and hole down for 5-10 seconds before starting to turn the dial. Continue to hole down the button, and slowly turn the dial to the right to increase the voltage applied to the electrodes. When the red light glows, emulsion breakdown has occurred. 4. Release the button and read the dial. 5. Multiply the voltage reading by 2 to obtain the emulsion stability. 6. Once the emulsified material in the “slit” between the electrodes is broken down, it must be replaced with fresh fluid before repeat tests are made. For routine accuracy, this may be accomplished by vigorously stirring the sample with the probe. Clean the probes and reset the dial to zero prior to taking a second test. 7. Solvents such as kerosene or naphtha are excellent for cleaning the probe. More volatile solvents may be harmful to the molded plastic. Use a soft cloth to clean the test material from the “slit” between the probes, and dry thoroughly. NEVER use a metal object to clean the probe. A severe electrical shock could result. 8. Do not subject the probe to temperatures above 150 C. 9. Battery life is estimated at 1 year of average service. Replace with Mallory No. TR136R or equivalent Duracell EL-4423 battery.

FANN MODEL 23D OR OFI MODEL E30A OPERATION: Equipment: 1. A glass or plastic container 2. Fann Model 23D or OFI Model E30A ES meter

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Procedure: 1. Heat the sample to be tested to 65 C (150 F). 2. Immerse the probe in the sample, making certain that the fluid covers the electrode surfaces, and briefly stir briskly with the probe. 3. Make sure the probe does not touch the sides or bottom of the container and push “ON” to turn the instrument electronics on. There is no “OFF” since the instrument shuts itself off approximately one minute after the last operation. 4. Push and release “TEST” to start the automatic ramp. Do not move the electrode during the measurement. The ramp will stop at the breakdown voltage. Read and record the voltage from the digital display. If the “LOW BATTERY” light flashes, the measurement should be ignored. Replace the four 9-Volt alkaline batteries before proceeding. 5. Clean the probe thoroughly by passing a paper towel or rag between the electrode gap. Rinse in kerosene or naphtha and wipe the probe again with a paper towel or rag.

3.5.5

OIL MUD ALKALINITY


Equipment: 1. 50/50 mixture of Xylene / Isoproponal solution, or a 75/25 mixture of camping fuel / rubbing alcohol, or normal Propoxy Propanol solution. 2. 250 ml Erlenmeyer flask or beaker 3. Magnetic Stirrer 4. 2 cm3 syringe 5. Phenolphthalein Indicator Solution 6. N/10 Sulfuric Acid Solution 7. Distilled Water Procedure: Pour 50-70 cm3 of the xylene / isoproponal mixture in the Erlenmeyer flask. Disperse 1.0 cm3 of Invert mud into the solvent. Stir vigorously with the magnetic stirrer for 1-2 minutes to break the emulsion. Add 100-125 cm3 of distilled water, and 15-20 drops of Phenolphthalein indicator solution. While stirring rapidly with the magnetic stirrer, slowly titrate with N/10 Sulfuric Acid until the pink color just disappears. Continue stirring for another 5 minutes. If the pink color reappears, titrate a second time with N/10 H2SO4 acid. Continue stirring for another 5 minutes. If the pink reappears again, titrate a third time with N/10 H2SO4 acid. The end point is reached when the pink color does not reappear after stirring 5 minutes. After the third titration, call this the end point. 6. Record the total amount of cm3 of N/10 Sulfuric Acid required as the POM. 1. 2. 3. 4. 5.

Calculations: Excess Lime Content (kg/m3) = POM X 3.7

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3.5.6

OIL MUD CHLORIDE CONTENT


Equipment: 1. Potassium Chromate Indicator Solution 2. Silver Nitrate Solution: 1.0 cm 3 = 1000 mg/L Chlorides (Use this solution only if ENVIROFLOC (Calcium Nitrate) or a mixture of ENVIROFLOC and Calcium Chloride is used for the internal Brine phase). 3. Silver Nitrate Solution: 1.0 cm 3 = 10000 mg/L Chlorides (Use this solution only if Calcium Chloride is used for the internal Brine phase). Procedure: 1. The Chloride titration is a continuation of the oil mud alkalinity measurement. 2. To the sample that has just checked for alkalinity, add 20 drops of Potassium Chromate Indicator solution. 3. Titrate the solution with the weak Silver Nitrate solution (if Envirofloc is used as the internal brine phase), or the stronger Silver Nitrate solution (if CaCl2 is used as the internal brine phase). Calculations: Chlorides of the Whole Mud (mg/L) = cm3 of AgNO3 x 1000 (for the weaker solution) Chlorides of the Whole Mud (mg/L) = cm3 of AgNO3 x 10000 (for the stronger solution)

3.5.7

OIL MUD CALCIUM CONTENT


Equipment: 1. 2. 3. 4. 5. 6. 7. 8.

Normal Propoxy Propanol solution or a 50/50 mixture of Xylene / Isoproponal solution 250 ml Erlenmeyer Flask or Beaker Magnetic Stirrer 3 ml syringe Calver II Indicator Powder (Calcium Indicator) Calcium Buffer Solution (1.0 N Sodium Hydroxide) Calcium Titrating Solution; EDTA, 1.0 cm 3 = 4000 mg/L Calcium Distilled Water

Procedure: 1. Pour 50 cm3 of Normal Propoxy Propanol or Xylene/ Isopropanol solution into the Erlenmeyer flask. 2. Disperse 1.0 cm3 of Invert mud into the solvent. 3. Stir vigorously with the magnetic stirrer for 1-2 minutes to break the emulsion. 4. Add 100-125 cm3 of distilled water, 30 drops of Calcium Buffer Solution, and 0.1—0.2 grams of Calver II Indicator Powder. 5. While stirring rapidly with the magnetic stirrer, slowly titrate with Calcium Titrating Solution until the color changes from a light purple to a deep blue.

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Calculations: Calcium Whole Mud (mg/L) = cm3 Calcium Titrating EDTA Solution X 4000

3.5.8

OIL MUD RETORT


Equipment: 1. OFI or Baroid 50 ml Retort Procedure: 1. Lift the retort assembly out of the insulator block. remove the mud chamber from the retort. A crescent wrench may be necessary. 2. Pack the upper chamber with a very fine steel wool. 3. Fill the chamber with mud, gently replace the lid allowing for excess mud to escape. This is the point where error is often introduced. Be sure that no air is entrapped in the chamber. An accurate volume of mud is essential. 4. Wipe off any excess mud. 5. Coat the threads and matting surface below the threads of the mud chamber thoroughly with Never-Seez to seal the connection and prevent loss of vapor. This will also facilitate an easier opening of the retort after the test is completed. 6. Screw the condenser into the upper chamber of the retort. 7. Screw the condenser into the retort stem. Do not invert the retort. 8. Place the retort into the insulator block and put the insulating cover in place. 9. Add a drop of wetting agent to the 50 ml graduated cylinder and place it under the drain of the condenser. Connect the retort to the power outlet, and turn on the power. 10. Heat the sample until liquid no longer drips form the condenser, or until the pilot light goes out. 11. Unplug the retort and allow it to cool prior to running additional tests. 12. To quickly cool the retort, run cool water over the mud chamber and condenser. The mud chamber can be cleaned with water. The graduated cylinder requires soap and water. Remove and replace any mud caked steel wool. Clean the retort drain tube and condenser with a pipe cleaner. Be sure to dry the inside of the retort and condenser before running the next test. 13. If the unit is to be cleaned later, break the sample cup lose from the expansion chamber ½ turn, for easier removal once the unit has cooled down. 14. Do not transport the retort with the assembly inserted in the heating jacket. Calculation (% expressed as a volume fraction): 1. 2. 3.

% oil by volume = ml’s of oil X 2 % water by volume = ml’s of water X 2 % solids by volume = [50 – (ml’s of oil + ml’s of water)] X 2 or % solids by volume = 100- (% oil by volume - % water by volume)

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3.5.9

OIL MUD HYDROGEN SULFIDE DETERMINATION

Equipment: 1. 2. 3. 4. 5. 6. 7.


Garrett Gas Train Drager H2S Analysis Tubes Citric Acid Solution containing a De-emulsifier Octanol in a Dropper Bottle 10 ml and 20 ml Syringe Magnetic Stirrer with a (¼ x 1 inch) Plastic Coated Stirring Rod Teflon Sample Injection Tube

Procedure: 1. 2. 3. 4. 5.

6. 7. 8. 9. 10.

11. 12.

13.

14.

Place the Garrett Gas Train on the magnetic stirrer so that the stir bar will freely rotate to vigorously agitate the contents in Chamber 1. Install and puncture a CO2 cartridge in the carrier gas assembly. Arrange the plastic injection tube through the rubber septum on the top of Chamber 1, to allow the mud sample to be injected into the chamber. Add 20 ml of Citric Acid solution, and 10 drops of Octanol into Chamber 1. Select a Drager tube (low or high range) based on the table at the end of this section to match the expected levels of Sulfides. Also select an appropriate mud sample volume from the table at the end of this section. Break the tips of the Drager tube, and install it with the arrow pointed downward into the bored receptacle. Install the flowmeter tube with the word “TOP” upward. Install the top of the Garrett Gas Train, and hand tighten all screws evenly to seal. Attach the flexible tubing to the dispersion tube, and to the Drager tube. Adjust the dispersion tube in Chamber 1 to approximately 3.0 cm 3 above the bottom of the stir rod. Put the mud sample in the syringe and place it into the injection tube. Hold the syringe plunger in place with your hand. Gently flow the gas for a 10 second period to purge air from the system. Check for any leaks and then shut off the gas. Start rapid stirring the fluid in Chamber 1. Slowly inject the Invert sample into Chamber 1. Stir for at least 5 minutes or until the sample is well dispersed. Start the carrier gas flow. Adjust the rate between 200 and 400 ml. per minute, or keep the flowmeter ball between the red lines. One CO2 cartridge should provide about 15-20 minutes of flow at this rate. Observe changes in the appearance of the Drager tube. Note and record the maximum darkened length before the front starts to smear. Continue the gas flow for a total of at least 15 minutes. With prolonged flow, the stain front may attain a diffuse or feathery coloration. In the high-range tube, an orange color may appear ahead of the black front in sulfides are present in the sample. The orange region should be ignored. Clean the chambers with warm water and a mild detergent. Clean the dispersion and injection tubes with Varsol. Rinse the unit with distilled water, and allow it to drain dry.

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Calculations: Using the measure sample volume, the Drager tube’s maximum darkened length, and the tube factor from the following table, calculate the active sulfides as H2S in the sample as follows: H2S (mg/L) = (Darkened Length *) (Tube Factor) Sample Volume, ml * In units marked on the Drager Tube

Drager Tube Identification, Sample Volumes, and Tube Factors Sulfide Range (mg/L) 1.5-3.0 3-6 6-120 60-1020 120-2040 240-4080

Sample Volume (ml) 10.0 5.0 2.5 10.0 10.0 10.0

Drager Tube I.D. (see Tube body) H2S 100/a H2S 100/a H2S 100/a H2S 0.2%/A H2S 0.2%/A H2S 0.2%/A

Tube Factor 12 12 12 600* 600* 600*

* The Tube Factor 600 is based on a batch factor (stenciled on the box) of 0.40. For another batch factor, a corrected factor should be calculated as follows: Corrected Tube Factor: 600 (Batch Factor 0.40)

3.5.10 “HOT or QUICK” LIME TEST


Hot Lime or Quick Lime (Calcium Oxide; CaO) is used in an Invert mud rather than hydrated Lime [Calcium Hydroxide; Ca(OH)2]. Hot Lime acts as a catalyst to change the fatty acid concentrates over to Calcium base soaps. Below is a simple check to determine whether the Lime is “Hot”, meaning that it has not hydrated. Equipment: 1. 100 ml Graduated Cylinder 2. 250 ml Graduated Beaker 3. Metal Thermometer Procedure: 1. Weigh 40 grams of Hot Lime into the beaker. 2. Set the thermometer in the beaker. 3. Add 30 ml of water and gently stir for 30 seconds and let the beaker set for the reaction to take place. 4. 54 C or higher indicates that the Lime is “Hot”.

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3.5.11 ANILINE POINT DETERMINATION


The aniline point should be determined, especially if utilizing crude oil, to minimize excessive wear and deterioration of rubber components on the rig. An aniline point of 57 C is considered the minimum accepted range for the oil make up in an Invert mud system. Equipment: 1. 25 ml Pyrex Test Tube 2. Pyrex jacket; 37-42 mm in diameter, and 175 mm in length 3. Manually operated metal stirrer with a concentric ring on the bottom. The diameter should be approximately 19 mm, and the length about 200 mm with a right angle bend at the top. 4. Aniline point thermometers with ranges from -35 C to +40 C, and from 25 C to 105 C. 5. Numbers 12 and 24 cork stoppers 6. Two 10 ml pipettes and two 5 ml pipettes 7. Rubber suction bulb for measuring aniline 8. Heat – an open flame, or an infrared lamp (250-375 watts) 9. Non-aqueous cooling bath to be used when aniline or mixed aniline point is below room temperature 10. N – keptone reagent Procedure: 1. Using a pipette, add 10 ml of aniline and 10 ml of sample into the air-jacket tube filled with stirrer and thermometer. Center the thermometer in the test tube so that the immersion mark is at the liquid level. The bulb should not touch the sides of the tube. 2. Stir the sample rapidly and heat until the sample is completely miscible. The cooling bath must be substituted for the heat if the aniline sample mixture is completely miscible at room temperature. 3. When the mixture becomes cloudy throughout and complete separation of aniline and sample occurs, record the temperature. This will be the minimum equilibrium aniline solution temperature. 4. Record the temperature in degrees C.

3.6

OIL MUD CALCULATIONS ( Envirofloc Internal Water Phase Only )

3.6.1

CALCULATION OF WATER PHASE SALINITY


Calculations: 1.

Envirofloc Concentration,(kg/m3) = Calcium Whole Mud (mg/L) X 0.0054

2.

Water Concentration, (kg/m3) = Water Fraction X 1000

3.

Water Phase Salinity (% by weight) =

(Envirofloc, kg/m3 X 100)____ (Envirofloc, kg/m3 + Water, kg/m3)

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Example: 1.

Volume of Calcium Titrating EDTA Sol’n = 3.9 cm 3

2.

Calcium Whole Mud, mg/L: = 3.9 X 4000 = 15,600 mg/L

3.

Volume Fraction of Water (from retort uncorrected) = 0.13

4.

Envirofloc Concentration, kg/m3 = 15600 X 0.0054 = 84.24 kg/m3

5.

Water Concentration, kg/m3 = 0.13 X 1000 = 130 kg/m3

6.

Water Phase Salinity (% by weight) = (84.24 X 100) (84.24 + 130) = 39.3 % by weight

3.6.2

WATER ACTIVITY


The Water Activity of the Envirofloc water phase Invert can be determined from the graph showing the % by weight Envirofloc versus Water Activity. For the above example, the Water Activity (% by weight) of the mud is 0.79.

3.6.3

CORRECTED SOLIDS

Due to the volume expansion associated with Envirofloc (Calcium Nitrate) in solution, it is necessary to correct the water and solids fraction as follows. Fomula Abbreviations: Rw Ro Rs D Wt Sg Ef E Cs Cw

= Volume Fraction of Water = Volume Fraction of Oil = Volume Fraction of Solids = kg of Water in Envirofloc = % Weight as a Decimal = Specific Gravity of the Brine = Expansion Factor = kg/m3 Envirofloc = Corrected Solids = Corrected Water

Calculations: 1.

kg/m3 of Envirofloc, (E): E = Calcium Whole Mud (mg/L) X 0.0054

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2.

kilogram of Water, (D): D = E X 0.16674

3.

Determine % Weight as a Decimal, (Wt): Wt =

4.

E_________ {E + (Rw X 1000)} – D

Specific Gravity of the Brine, (Sg): Sg = (Wt X 100) + 116.98 120.48

6.

Expansion Factor, (Ef): Ef =

7.

Corrected Solids, (Cs): Cs =

8.

1______ Sg X (1 – Wt)

Rs______ Ef – (D / 1000)

Corrected Water, (Cw): Cw = (Rs – Cs) + Rw

Example: From the Retort:

Volume Fraction of Water, Rw = 0.16 Volume Fraction of Oil, Ro = 0.74 Volume Fraction of Solids,Rs = 0.10

From Titration, Calcium Whole Mud = 14080 mg/L

1.

kg/m3 of Envirofloc, (E): E = Calcium Whole Mud (mg/L) X 0.0054 = 14080 X 0.0054 = 76.03 kg/m3

2.

kilogram of Water, (D): D = E X 0.16674 = 76.03 X 0.16674 = 12.68 kg

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3.

Determine % Weight as a Decimal, (Wt): Wt =

E_________ {E + (Rw X 1000)} – D = 76.03 _____ {76.03 + (0.16 X1000)} – 12.68 = 76.03_______ (76.03 + 160) – 12.68 = 76.03 223.35 = 0.34 % by Weight

4.

Specific Gravity of the Brine, (Sg): Sg = (Wt X 100) + 116.98 120.48 = (0.34 X 100) + 116.98 120.48 = 34 + 116.98 120.48 = 1.2531 Sg

5.

Expansion Factor, (Ef): Ef =

1______ Sg X (1 – Wt) = 1________ 1.2531 X (1 – 0.34) = 1______ 1.2531 X 0.66 = 1__ 0.8270 = 1.2091 Ef

6.

Corrected Solids, (Cs): Cs =

Rs______ Ef – (D / 1000) = 0.10_________ 1.2091 – (12.68 / 1000) = 0.10_____ 1.2091 – 0.01268 = 0.10 1.196 = .0836 ( % volume fraction)

7.

Corrected Water, (Cw): Cw = (Rs – Cs) + Rw = (0.10 – 0.0836) + 0.16 = 0.0164 + 0.16 = 0.1764 (% volume fraction)

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The corrected readings should then be as follows: Volume Fraction of Water, Rw = 0.18 (rounded off) Volume Fraction of Oil, Ro = 0.74 Volume Fraction of Solids,Rs = 0.08 (rounded off)

3.6.4

OIL / WATER RATIO


The oil / water ratio is the amount of each liquid which makes up the fluid phase of the Invert. A corrected solids analysis must be performed prior to calculating the correct oil / water (OWR) ratio. Fomula Abbreviations: Rw = Volume Fraction of Water (corrected) Ro = Volume Fraction of Oil (corrected) Calculations: Oil Ratio

= ____Ro_____ X 100 Rw + Ro

Water Ratio

= ____Rw_____ X 100 Ro + Rw

Example: Corrected Retort Readings: Volume Fraction of Water, Rw = 0.18 (rounded off) Volume Fraction of Oil, Ro = 0.74 Volume Fraction of Solids,Rs = 0.08 (rounded off) Oil Ratio

= ____Ro_____ X 100 Rw + Ro = _____0.74____ X 100 0.18 + 0.74 = _____0.74____ 0.92 = 0.80

Water Ratio

= ____Rw_____ X 100 Ro + Rw = _____0.18____ X 100 0.74 + 0.18 = _____0.18____ 0.92 = 0.20

The OWR (oil / water) ratio is expressed with the oil before the water as follows: OWR = 80/20

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3.6.5

CHANGING THE OIL / WATER RATIO


To change the oil/water ratio, the following calculations may be used. The corrected retort readings and the total circulating volume must be known. First determine the present OWR, and then decide whether oil or water should be added to change the OWR. The volume of oil and water in the mud system must be calculated as follows. Calculations: Total volume of oil in system, m3 = Volume Fraction of Oil X Total Circulating Volume Total volume of water in system, m3 = Volume Fraction of Water X Total Circulating Volume If oil is to be added to increase the OWR: Volume of Oil, m3 + x Volume of Water, m3

=

Desired Oil Ratio Desired Water Ratio

If water is to be added to decrease the OWR: Volume of Oil, m3 Volume of Water, m3 + x

=


Example: An OWR of 80/20 was determined. The mud program requires an 85/15 OWR. Therefore additional diesel oil will be required to bring the OWR up to 85/15. The total circulating volume of the system is 120 m3. Corrected Retort Readings: Volume Fraction of Water, Rw = 0.18 Volume Fraction of Oil, Ro = 0.74 Volume Fraction of Solids,Rs = 0.08 Total volume of oil in system, m3

= Volume Fraction of Oil X Total Circulating Volume = 0.74 X 120 = 89 m3

Total volume of water in system, m3

= Volume Fraction of Water X Total Circulating Volume = 0.18 X 120 = 22 m3

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Calculate the amount of oil to be added to increase the OWR: Volume of Oil, m3 + x Volume of Water, m3 89 + x 22

=


= 85 15

(15) (89 + x) = (85) (22) 1335 + 15x = 1870 15x = 535 x = 535/15 x = 36 m3 It will then require an additional 36 m3 of diesel oil to change the OWR from 80/20 to 85/15. While adding the oil, additional emulsifiers, Hot Lime, etc. will have to be added to ensure a stable emulsion exists.

3.6.6

HIGH AND LOW GRAVITY SOLIDS ( Weighted Invert )

Calculations:


The following information is needed in order to determine the amount of each component in weighted Invert mud. Volume fraction of oil (corrected) Volume fraction of water (corrected) Volume fraction of solids (corrected) Mud density, kg/m3 Calcium Whole Mud, mg/L From the Calcium Whole mud, calculate the amount of Envirofloc as follows: Envirofloc, kg/m3 = Calcium Whole Mud X 0.0054 The Water Phase Salinity can be calculated from the retort water fraction (uncorrected), and the amount of Envirofloc in the mud as follows. Water Phase Salinity

=

Envirofloc X 100__ _________ (0.833 X Envirofloc) + (1000 X Water Fraction)

Example: 1.

Retort Results: Oil Fraction = 0.62 Water Fraction = 0.16 Solids Fraction = 0.22 Mud Density = 1420 kg/m3 Calcium Whole Mud = 27600 mg/L

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2.

Envirofloc, kg/m3

= Calcium Whole Mud X 0.0054 = 27600 X 0.0054 = 149 kg/m3

3.

Water Phase Salinity

=

4.

If we use 1.0 m 3 of mud as a basis for the calculation, the mass and volume of the liquids can be accounted for directly from their known densities. The following chart shows the kilograms and cubic metres of oil and water in 1 m3 of mud.

Liquid Oil Water TOTAL

Envirofloc X 100__ _________ (0.833 X Envirofloc) + (1000 X Water Fraction) = 149 X 100________ (0.833 X 149) + (1000 X 0.16) = 14900___ 124.12 + 160 = 14900 284.12 = 52.4% by weight

1 Cubic metre, m3 0.620 0.160 0.780

Density 840 1000

Kilograms 520.8 160.0 680.8

The solids which remain in the retort cup include dehydrated Envirofloc salt, low gravity solids, and high gravity solids. The decahydrate salt; i.e. Envirofloc (Calcium Nitrate), contains 16.67% by weight of water. Therefore the amount of dehydrated Envirofloc in 1 m3 of mud can be calculated as follows: 5.

100% (Envirofloc) - 16.67%(water) = 83.33% Pure Envirofloc 83.33% as a decimal fraction = 0.8333 Dehydrated Envirofloc = 0.8333 X 149 kg/m3 = 124.2 kg/m3

6.

And the amount of dehydrated Envirofloc in an Envirofloc solution which is 52.4% by weight (water phase salinity) is: Dehydrated Envirofloc = 0.8333 X 52.4% = 43.7%

7.

The density of the dehydrated Envirofloc can be calculated from on of the following formulas. For Salinity > or = to 30% by Weight: kg/m3

= [ -11.4 (Dehydrated Envirofloc, %)] + 3435 = [ -11.4 (43.7%)] + 3435 = ( -498.48) + 3435 = 2937 kg/m3

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For Salinity < 30% by Weight: kg/m3 8.

= [ -20.3 (Dehydrated Envirofloc, %)] + 3731

From the mass and the density, we can calculate the volume occupied by the dehydrated Envirofloc as follows: Volume =

124.2 2937 = 0.042 m3

9.

Thus far, the liquids and the dissolved salt accounts for 805 kilograms, and 0.822 m 3. Oil Water Dehyd. Envirofloc Total

10.

0.620 m3 0.160 m3 0.042 m3 0.822 m3

520.8 kg 160.0 kg 124.2 kg 805 kg

The remainder of the mass and the volume is occupied by the undissolved solids. That is, the low gravity solids and high gravity solids. These amounts of undissolved solids are calculated as follows: Mass, kg

= 1420 (mud density) - 805 = 615 kg

Volume, m3 = 1.000 – 0.8222 = 0.178 m3 11.

Therefore, the total density of the mixture of low gravity solids and high gravity solids is: = 615 kg 0.178 m3 = 3455 kg/m3

12.

The fractional part of low gravity solids in the undissolved solids is: Fraction of low gravity solids

Note:

= 4200 – 3455 4200 – 2600 = 0.466 % by volume

Average relative density of high gravity solids = 4200 kg/m 3 Average relative density of low gravity solids = 2600 kg/m 3

13. Then, the volume of low gravity solids: = 0.466 X Total Volume of Undissolved Solids = 0.466 X 0.178 = 0.083 m3 14. And the mass of the low gravity solids is: = 0.083 X 2600 = 216.0 kg/m3

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15.

The remaining mass and volume is high gravity solids: The volume of high gravity solids is: = 0.178 – 0.083 = 0.095 m3 The mass of the high gravity solids is: = 615 – 216 = 399 kg/m3

Therefore on the mud check sheet the following would be reported: Low Gravity Solids = 216 kg/m3 High Gravity Solids = 399 kg/m3

3.7

OIL MUD CALCULATIONS ( Mixed Salts - Internal Water Phase Only )

3.7.1

CALCIUM SOURCE


If we are not familiar with the source of the Calcium Salt(s) used in the mud, a comparison of the Calcium Source Number (CSN), and the whole mud Chlorides can be helpful in establishing the Calcium source. Based on the information we have, the two possibilities are as follows. 1. Whole Mud Chlorides are less than the Calcium Source Number: With today’s environmental concerns, this is the most common case. The mixed Calcium Chloride/Envirofloc Inverts, straight Envirofloc Inverts, mixed Calcium Acetate/Envirofloc Inverts, and the straight Calcium Acetate Inverts fall into this category. Calcium Acetate based Inverts are very expensive, and generally only become cost effective in high OWR (oil/water) ratio fluids. Assuming that Acetates are not used as a Calcium source reduces the commonly referred to mixed Salt Invert (Calcium Chloride/Envirofloc) or a pure Envirofloc based Invert; the latter of which is typical with Whole Mud Chlorides less than 1000 mg/L. Whole mud Chlorides greater than 1000 mg/L: The Calcium salts are combined Calcium Chloride and Envirofloc. For this mixed Calcium Salt Invert, the Calcium Chloride and Envirofloc concentrations are: Calcium Chloride (kg/m3 whole mud) = 0.001565 X (mg/L Chlorides) Envirofloc (kg/m3 Whole Mud) = [0.005405 X (mg/L Activity Calcium)] – [0.003055 X (mg/L Whole Mud Chlorides)]

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3.7.2

LIME CONTENT


Same as section 3.5.5 Data Required: Pm = ml of N/10 H2SO4 required to reach the end point for the alkalinity check Calculations: Lm = kg/m3 Lime in Whole Mud Lm = 3.71 X Pm

3.7.3

WHOLE MUD CALCULATIONS ( Mixed Salt Content )

Mud Check Data Required:


Mca = number of ml Titraver (EDTA) required to reach the end point for the Calcium check. Mcl = number of ml of 0.282 Silver Nitrate ( 1 ml = 1000 mg/L Cl) required to reach the end point for the Chloride check. Calculations: 1. Chlorides: Clm = kg/m3 Whole Mud Chlorides Clm = 10 X Mca Note: If 0.0282N Silver Nitrate ( 1 ml = 10000 mg/L Cl) is used for the titration, the multiplier is 1.0 2. Calcium: Cam = kg/m3 Whole Mud Calcium Cam = 4 X Mca Note: If regular hardness titrating solution, or Titraver 400 is used, the multiplier if 0.40 3. Calcium Chloride: Smc = kg/m3 Calcium Chloride in Whole Mud Smc = 1.565 X Clm 4. Envirofloc: Sme = kg/m3 Envirofloc in Whole Mud Sme = (5.39 X Cam) – (3.05 X Clm) – (540 X Lm)

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5. Nitrates: Nm = kg/m3 Whole Mud Nitrates (NO3) Nm = 0.631 X Sme

3.7.4

LIQUID PHASE CALCULATIONS


Mud Check Required: Rw = % Retort Water Ro = % Retort Oil Calculations: 1. Calcium Chloride Swc = kg/m3 Calcium Chloride in Water Phase Swc = 100 X Smc Rw 2. Envirofloc Swe = kg/m3 Envirofloc in Water Phase Swe = 100 X Sme Rw 3. Nitrates Nw = kg/m3 Nitrates (NO3) in Water Phase Nw = 100 X Nm Rw 4. Total Equivalent Chlorides and Water Activity Clwt = Total Equivalent Water Phase Chlorides, kg/m 3 Clwe = Equivalent Envirofloc Chlorides, kg/m3 Read form Table 2 or Figure 1 using Nw Clwt = Clwe + 100 X Clm Rw Aw = Water Activity Read from Figure 2 using Total Equivalent Chlorides, Cl Note: If the mud is a 100% Envirofloc Invert, Aw may be read directly from Table 1, and if it is a 100% Calcium Chloride Invert, Aw may be read directly from Table 2.

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3.7.5

CORRECTED OIL / WATER (OWR) RATIO

Frc = Calcium Chloride Retort Water Factor Read from Table 2 or Figure 4 using Swc


Fre = Envirofloc Retort Water Factor Read from Table 1 or Figure 3 using Swe Rwc = Corrected % Retort Water Rwc = (Frc + Fre – 1) Rw OWR = Oil / Water Ratio O = 100 X Rwc (Ro + Rwc) W = 100 X Rwc (R0 + Rwc) Brine Water Density: Db = Salt Water Density, kg/m 3 Db =

998___ (Frc + Fre – 1)

+ 100 (Smc + Sme + Lm) Rw

Liquid Phase Density: Dl = Liquid Phase Density, kg/m 3 Dl = 8.50 + Db X W 100

3.7.6

INERT SOLIDS CALCULATIONS

Mud Check Data Required:


Rs = % Retort Solids Dm = Mud Density, kg/m3 Cs = Volume Fraction corrected Low Gravity Solids Cs = ( Dm – Dl) (2600 – Dl) Cs = Rs – (Frc + Fre – 2) Rw

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Note: If the alternative calculation for the volume fraction of low gravity solids is significantly different, it is possible that the retort data was not corrected for entrained air or vapor losses. LGS = Low Gravity Solids, kg/m 3 LGS = 2600 X Cs Weighted Invert Mud: Cs = Volume Fraction Corrected Low Gravity Solids Cs = Rs/100 – (Frc + Fre – 2) Rx /100 Ds = Average Solids Density Ds = Dm – Dl (1 – Cs) Cs HGS = High Gravity Solids, kg/m3 HGS = 2.625 (4200 – Ds) LGS – Low Gravity Solids, kg/m 3 LGS = 1.625 (Ds – 2600)

3.7.7

EXAMPLE CALCULATIONS


Unweighted Mixed Salt Invert Mud Check Data: Titraver 4000 or EDTA Sol’n = 4.43 ml 0.282 N Silver Nitrate = 0.96 ml Pm = 3.2 ml of N/10 Sulfuric Acid Retort Solids, Rs = 8.5% Retort Water, Rw = 15.5% Retort Oil, Ro = 76.0% Mud Density = 1037 kg/m3

Whole Mud Calculations:

1.

Lime Content: Lm = 3.71 X Pm = 3.71 X 3.2 = 11.87 kg/m3 Lime in Whole Mud

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Mixed Salt Content: 1.

Chlorides Clm Clm

2.

Calcium Cam

3.

= kg/m3 Calcium Chloride in Whole Mud = 1.565 X Clm = 1.565 X (9.60) = 15.02 kg/m3 Calcium Chloride in Whole Mud

Envirofloc Sme

5.

= kg/m3 Whole Mud Calcium = 4 X Mca = 4 X (4.43) = 17.72 kg/m3 Whole Mud Calcium

Calcium Chloride Smc

4.

= kg/m3 Whole Mud Chlorides = 10 X Mca = 10 X (0.96) = 9.60 kg/m3 Whole Mud Chlorides

= kg/m3 Envirofloc in Whole Mud = (5.39 X Cam) – (3.05 X Clm) – (540 X Lm) = (5.39 X 17.72) – (3.05 X 9.60) – (540 X 11.87) = 95.51 – 29.28 – 6.41 = 59.82 kg/m3 Envirofloc in Whole Mud

Nitrates Nm

= kg/m3 Whole Mud Nitrates (NO3) = 0.631 X Sme = 0.631 X 59.82 = 37.75 kg/m3 Whole Mud Nitrates (NO3)

Liquid Phase Calculations:

1.

Calcium Chloride Swc

= kg/m3 Calcium Chloride in Water Phase = 100 X Smc Rw = 100 X 15.02 15.5 = 96.90 kg/m3 Calcium Chloride in Water Phase

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2.

Envirofloc Swe

3.

Nitrates Nw

4.

= kg/m3 Envirofloc in Water Phase = 100 X Sme Rw = 100 X 59.82 15.5 = 385.9 kg/m3 Envirofloc in Water Phase

= kg/m3 Nitrates (NO3) in Water Phase = 100 X Nm Rw = 100 X 37.75 15.5 = 243.5 kg/m3 Nitrates (NO3) in Water Phase

Total Equivalent Chlorides and Water Activity Clwe

= Equivalent Envirofloc Chlorides, kg/m 3 or (mg/L)/1000 = Read form Table 2 or Figure 1 using Nw = From Figure 1, at Water Phase Nitrates = 243.5 kg/m 3, read = 138 kg/m3

Clwt

= Clwe + 100 X Clm Rw = 138 + 100 X 9.60 15.5 = 138 + 61.94 = 199.9 kg/m3 (round off to 200)

Aw

= Water Activity = Read from Figure 2 using Total Equivalent Chlorides, Clwt = From Figure 2 using Clwt = 200 = 0.75 Water Activity

Corrected Oil / Water Ratio: Frc

= Calcium Chloride Retort Water Factor = Read from Table 2 using Swc = Read from Table 2 using Swc = 96.90 Note: This example demonstrates interpolation for better accuracy. If the value (v), with which a table of values is entered lies between two values (v1) and (v2), then the desired resultant value (r), will be between (r1) and r2), which correspond to (v1) and (v2) respectively. The desired value (r) can be determined by the following equation. r = (v – v1) (r2 – r1) + r1 (v2 – v1)

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Note: In this instance, the values 96.90 and r1 = 96.72 are close enough to consider the values to be the same (i.e.: one could use v1 = 1.0225 to be the value for Frc). However, to demonstrate the interpolation procedure, the example can be carried out as follows. So, applying this procedure to determine Frc, we obtain: Frc

= (96.90 – 96.72) (1.0240 – 1.0255) + 1.0255 (102.51 – 96.72) = (0.18) (0.0015) + 1.0225 (5.79) = 0.000047 + 1.0225 = 1.0225 Calcium Chloride Retort Water Factor

Fre

= Envirofloc Retort Water Factor = Read from Table 1 using Swe = Read from Table 1 using Swe = 385.9 r = (v – v1) (r2 – r1) + r1 (v2 – v1)

Fre

= (385.9 – 362.4) (1.2015 – 1.1826) + 1.1826 (391.7 – 362.4) = (23.5) (0.0189) + 1.1826 (29.3) = 0.0152 + 1.1826 = 1.1978 Envirofloc Retort Water Factor

Then; Rwc Rwc

= Corrected % Retort Water = (Frc + Fre – 1) (Rw) = (1.0025 + 1.1978 – 1) (15.5) = (1.2203) (15.5) = 18.9%

The corrected oil / water ratio (OWR) can now be determined Oil (O) = 100 X Ro Ro + Rwc = 100 x 76 76 + 18.9 = 7600 94.9 = 80% Water (W) =

100 X Rwc Ro + Rwc = 100 X 18.9 76 + 18.9 = 1890 94.9 = 20%

OWR = 80 / 20

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Brine Water Density: Db

= Salt Water Density, kg/m 3

Db

=

Dl

= Liquid Phase Density, kg/m3

Dl

= (8.5 X Oil) + Db X W 100 = (8.5 X 80) + 1377 X 20 100 = 680 + 275.4 = 955 kg/m3 Liquid Phase Density

998_______ + 100 (Smc + Sme + Lm) (Frc + Fre – 1) Rw = 998_________ + 100 ( 15.02 + 59.82 + 11.87) (1.0225 + 1.1978 – 1) 15.5 = 998_ + 100 (86.71) 1.2203 15.5 = 817.8 + 559.4 = 1377 kg/m3 Salt Water Density

Inert Solids Calculations: Cs

= Volume Fraction Corrected Low Gravity Solids

Cs

=

Density Mud – Dl__ (2600 – Dl) = 1037 – 955 2600 - 955 = 82__ 1645 = 0.050

Alternative volume fraction corrected solids in unweighted muds: Cs

= 8.5/100 – (1.0225 + 1.1978 – 2) (15.5)/100 = 0.085 – (0.2203) (15.5)/100 = 0.085 – 0.034 = 0 051 Note: The two methods for determining the faction of low gravity solids agree indicating the validity of the equations. Sufficient accuracy of the calculation and accuracy of the mud check data is required to perform the calculations. However, using the mud density (Dm), and liquid density (Dl), is generally better, since vapor losses and entrained air usually results in a higher retort solids content than the actual.

LGS

= Low Gravity Solids, kg/m 3

LGS

= 2600 X Cs = 2600 X 0.050 = 130 kg/m3

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3.8

INVERT PROPERTIES AND MAINTENANCE

3.8.1

MUD DENSITY


The density of an Invert mud can range from 930 to 2600 kg/m 3 by the addition of weight material. Generally, the Invert muds utilized in Western Canada are unweighted (less than 1000 kg/m3), and perform very well with respected to penetration rates in the foothills. As with any drilling fluid, an Invert Emulsion must meet certain rheological requirements before weight material can be supported. The main cause of Barite settling in an oil mud is poor suspension or Gel Strength characteristics. Another cause of Barite settling is water wetting of the weight material. This can be caused by adding Barite without additions of the concentrate component chemicals to maintain a “chemical balance”, or adding Barite to an unstable emulsion. Never add Barite at the same time Brine water is being added. The Barite may become water wet, and settle to the bottom on the mud tanks. When Barite, or other weighting agents such as Calcium Carbonate, etc. are being added to the mud system, small additions of an oil wetting agent should be made to prevent water wetting of the solids. Also pilot testing on the Invert should be made prior to the Barite additions to ensure the YP and Gel Strengths are high enough to suspend the weight material. For every cubic metre of volume gained from the Barite additions, each emulsifier component and Hot Lime should be added in the correct proportions to ensure oil wetting of weight material, stable flow properties, and a strong emulsion is maintained. If the density of the fluid is to be dramatically altered, the OWR (oil / water ratio) may also need to be changed. When mixing Barite, a high pressure or high shear mixing system is advisable. Agitators and mud guns should be running in the active system, with periodic checks taken in the mud tanks to ensure no settling occurs.

3.8.2

FUNNEL VISCOSITY


In general, the Marsh Funnel viscosity of an unweighted oil base mud is a little lower than a water base mud. A weighted invert should be about the same as that of a good water base mud used for the same purpose. The funnel viscosity of an Oil Mud is affected more by temperature than that of a water base mud because oil is subject to greater viscosity variations with temperature changes than is water. A drastic drop of temperature, for example in the winter, can reduce the flowline temperature enough to cause a significant increase in the funnel viscosity of an oil mud, even though the viscosity of the mud down hole would not change. The mud temperature should be reported along with Funnel Viscosity. This reporting is more important for an oil mud than a water base mud. The viscosity is decreased when oil is added, and increased when water and/or solids are added to invert mud. That is, a higher OWR (oil/water ratio) will generally have a lower viscosity than a lower OWR ratio. If water or oil is being added to change the viscosity or the OWR ratio, the proportionate amount of concentrates must be added to maintain a tight emulsion. If an increase in funnel viscosity and Yield Point is required for better hole cleaning, Organophyllic Clay may be added. This material requires approximately two circulations to fully yield and should be pilot tested to determine the proper concentration desired. Adding a very small stream of water along with the Organophyllic Clay will aid in the yield of the product.

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3.8.3

PLASTIC VISCOSITY


The Plastic Viscosity (PV) of an oil mud is influenced primarily by the quantity and viscosity of oil used, amount of water present, the temperature of the mud, and the quantity and size of solids present in the mud system. Incorporated drilled solids not only increase the PV and mud density, but also effect the waterwet characteristics of the shale. These water-wet solids can agglomerate and occupy considerable volume in the mud, thereby magnifying the PV increase. An oil-wetting agent or secondary emulsifier will effectively disperse these clusters and lower the PV. Thus, when the PV has increased to an undesirable point. and the OWR ratio and density remains relatively unchanged, treatments of an oil wetting agent is recommended. The PV is best controlled though, as with any system, with proper and effective use of the solids control equipment.

3.8.4

YIELD POINT and GEL STRENGTHS


The Yield Point (YP) and Gel Strengths of an Invert are normally maintained lower to that of a comparable water base mud. For example, it is not uncommon to successfully drill 311 mm hole with an unweighted Invert with Yield Points ranging from 2-4 Pa. To obtain consistent and meaningful data from the PV, YP and Gel Strengths, the rheology should be checked at 65C (150F) with the VG meter. The temperature should be recorded on the mud check sheet. The YP is affected less than the PV by temperature changes. An increase in the Yield Point will be apparent should water wetting of solids occur. Again noticeable fluctuations will be evident if a tight emulsion is not present. Additions of water or Organophyllic Clay may be used to increase the Yield Point. The clay will affect the YP more than the Funnel Viscosity. Low Yield Points could promote the settling of Barite when accompanied by low Gel Strengths in a weighted invert mud. Chemical changes to the system will affect the Yield Point more than the Plastic Viscosity, therefore it is advisable to pilot test before any additions are made. The Get Strengths play a slightly more important role in an oil mud than they do in an average water base mud, i.e. they tend to be lower. High Gel Strengths or progressive Gel Strengths may indicate flocculation of water wet solids, or a possible weakened emulsion. The initial Gel Strength plays a significant role in Barite suspension. An increase in water and/or solids content will increase the Gel Strengths. If additions of water and/or Barite are authorized at the time, and there appears to be an increasing Gel Strength, then it may well be that the quality of the emulsion is degrading or solids are increasing. Note: Faster penetration rates, more stable hole conditions and a more economical fluid will result from consistent flow properties. Care should be taken when making chemical additions or altering the oil/water ratio to keep the rheological properties stable.

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3.8.5

ELECTRICAL STABILITY


This test determines the voltage potential required to initiate current flow in the mud. A stable oil mud is one in which the water is well emulsified and therefore will not conduct electricity. As the stability, or tightness of the emulsion increases, the greater will be the voltage potential required to initiate current flow. However, it must be kept in mind that this test does not indicate whether the system is in a good or poor condition. The reading obtained can be very unpredictable because so many factors are involved. Therefore, it is difficult to place a true meaningful value upon it. As a guide over the long term, a decreasing voltage stability can indicate a weakening emulsion. However an increase in water content or conductive solids can result in the same readings, although the actual emulsion stability has not changed. In short, every facet of the oil mud has an effect on the voltage stability reading. If they are not all considered, the number given by the Emulsion Stability meter is of little value. Generally an electrical stability of 400 volts or greater is acceptable. If the electrical stability climbs over 1000 volts, the daily maintenance of additives can be reduced. Note that the newer digital Emulsion Stability meters generally give a lower reading than the Fann Emulsion Stability meter. To tighten the emulsion or increase the electrical stability, additional emulsifiers and Hot Lime will be required. Note:

Free water in the HT-HP fluid loss test is the best indicator of emulsion instability.

3.8.6

FILTRATION


If a relaxed fluid loss invert has been programmed, both API and HT-HP fluid loss should be checked. On the relaxed filtrate systems, an API filtrate may be as high as 6-8 cm3, and the HTHP filtrate as high as 20-25 cm3. Remember, the filtrate should be all oil. For most Inverts used in Western Canada, the API fluid loss in normally zero, and the HT-HP fluid loss at 150 C will be 6-10 cm3 . The filtrate again should be free of any water. The HT-HP fluid loss is the best indicator of emulsion stability. This test should be conducted at bottom hole tem plus 5-IO C or as indicated by the drilling fluid program. Indications of an increase in the filtrate or water in the filtrate be attended to immediately. Additions of an asphalt will reduce the filtrate, and in higher temperature situations will contribute to emulsion stability. Additions of the concentrates and Hot Lime will remove water in the filtrate by increasing the a stability.

3.8.7

ACTIVITY / SALINITY


The salinity of the water phase is normally formulated with Calcium Nitrate ( Envirofloc CaNO3) or Calcium Chloride (CaCl2) to balance the activity of the shale. Activity is a measure of a shale’s affinity for water. Generally speaking the shale attempts to absorb water from a mud to balance its salinity by osmotic forces. To counteract these forces, the water phase of the invert contains sufficient salinity to balance the hydration and osmotic forces of the shale, thus eliminating the absorption of water to the shale. The Wapiabi and Blackstone shales commonly encountered in the Foothills of Western Canada have activities of approximately 0.7.

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Therefore the internal water phase activity should be adjusted to that of the shale with additions of Calcium Chloride or Envirofloc (Calcium Nitrate) as required. The deeper the well, the more compressed the shale becomes, therefore the activity of the Invert may have to be lowered to balance the activity of the mud and formation. The mud may have a lower activity than the shale, however, there are two schools of thought in regard to this practice: either the shale becomes more brittle when dried out and weakens the wellbore, or it hardens and becomes more stable. The "activity" of the mud can be maintained or adjusted with CaCI2 or Envirofloc, whichever is required. Only powdered CaCl2 can be added directly to the system to change the salinity. Envirofloc should has to be added in solution.

3.8.8

RETORT


The relationship between the oil/water ratio and weight is very important in the control of an oil mud's rheological properties. Each company has its own formulation for these ratios related to the required densities. A little more time is usually required to obtain complete distillation of an oil mud than a water base mud. High stability oil muds generally require slow initial heating to break the emulsion and prevent the mud from boiling over during the early distillation process. Allow distillation to continue for 10 minutes after the last distillate is observed. It is often difficult to read the oil/water interface accurately. Sometimes there appears a milky emulsion of the two phases at this point. Aerosol solution may help separate the phases. Mechanically breaking the emulsion up with a stirring rod or simply allowing the graduate to stand for an hour or so will help. Use a high temperature style retort for best results. NOTE: After the mud stabilizes the rheological properties desired should be allowed to dictate the oil/water ratio to be used. That is, the oil/water ratio should be adjusted until the appropriate Yield Point and Gel Strength is achieved. Having done this, check the retort and determine the oil/water ratio. Once this ratio is stabilized the flow properties will not change, as long as a proper chemical balance is maintained.

3.8.9

EXCESS LIME CONTENT


Generally, maintaining an excess Lime content of 10-15 kg/m3 in the oil mud is sufficient to provide a tight emulsion from the concentrates. If a H2S or CO2 bearing zone is anticipated, it is advisable to increase the excess Lime concentration to 20-30 kg/m3. Careful monitoring of the Lime content should be made throughout these intervals as both these gases, if allowed to influx into the wellbore, will lower the alkalinity.

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3.9

OIL MUD ENGINEERING GUIDELINES


1. Premix all products so that the products have a chance to yield before going down hole. Shearing the premix as much as possible for several hours will give a better initial rheology. Add premixed Invert when the active volume is low. 2. The Calcium Nitrate (Envirofloc) should be dissolved in water prior to adding to the oil base mud. Use the chemical barrel, pill or premix tank to prepare the brine for adding to the active mud system. It is recommended to saturate the water with Calcium Nitrate (Envirofloc). This will increase the salinity of the water phase without lowering the OWR significantly. 3. If adding Barite or CaCO3 to the mud, add slowly a small amount of oil wetting agent to help oil wet the solids. Discontinue adding all other products, especially water, while adding the CaCO3 or Barite. 4. Watch the Yield Point closely in an oil base mud to ensure that effective hole cleaning and weight material suspension is maintained. An organophyllic clay may be added to help suspend the weight material without substantially increasing the yield value. 5. Small amounts (4-20 litres/min.) of diesel can be added to the active system when the Yield Point or oil/water ratio gets high. This may be particularly useful in a high weighted oil mud. 6. Make no other additions while adding Barite or CaCO3. 7. Vigorous agitation is necessary when adding materials to give maximum stability. The more shear in an Invert, the better. 8. Always use a diesel spacer when displacing a fresh water mud from the hole or cementing. 9. If at any time the electrical stability falls below 400 volts, or if water is noticed in the filtrate, add the appropriate emulsifiers and Hot Lime. 10. If weight material is not suspended properly, or if tight hole or hole fill is experienced, add organophyllic clay. 11. Prior to working on the pumps, circulate at least "bottoms up" or as long as the pump is going to be shut down. 12. A daily record is essential to properly control losses and reduce daily maintenance costs. It is advisable to measure the tank volume several times per hour, to ensure that any losses are detected immediately. 13. Hydraulics play an important role and shares equal importance with the mud program. Excessive annular velocities should be avoided. The importance of circulating 5-10 minutes before making a connection, especially when making fast hole or in any coal sections, is imperative. The pipe should be pulled slowly when tripping. Also circulating bottoms-up prior to a trip will ensure minimum fill on bottom, and no tight spots coming out.

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14. Be sure to do concentration calculations on the correct volume. An 80/20 OWR does not mean the mud has 80% oil and 20% water, and thus these volumes should not be used to calculate material concentrations. Solids content must be taken into consideration if using "total volume" calculations. This is important to understand especially when calculating the amounts of Envirofloc or Calcium Chloride to use. 15. When testing oil muds, it is important to follow the procedures exactly. Be sure to use the exact volumes as indicated in the test procedures. A small error in volumes can produce a large error in results. 16. If CaCO3 or Barite becomes water wet: a. An effective treatment is to dilute the system with good uncontaminated premixed mud. b. Reduce the water wet Barite or CaCO3 content by discarding a portion of the mud, or by centrifuging and discarding weight material or high gravity solids. c. Treatments of emulsifier or an oil wetting agent will be beneficial. 17. Hot Lime must be added every time a emulsifier concentrate is added to the active system. If H2S is anticipated, increase the excess Lime content to 20-30 kg/m³. 18. As water will thicken the system, care should be taken in this respect. Shale shakers should not be washed with water. Water lines that leak or could contaminate the Invert mud should be plugged off. 19. The rheology, funnel viscosity and emulsion stability should be checked at a constant temperature as the viscosity of the fluid will vary greatly with temperature change. 20. The solids control equipment should be supervised and maintained in good working condition at all times. Clean this equipment with diesel only. 21. Each of the additives in the oil base mud is present for a specific purpose. The mud will not perform as intended if treated with more or one additive, or none of the other. Keep a good chemical balance. 22. An oil base mud should look good. The Invert should always look “shiny” with small dispersion rings. A grainy, dull, flat color indicates that something is wrong, and immediate action should be taken.

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3.10

OIL MUD FORMATION LOSSES


Because of the high cost of an Invert drilling fluid, loss of circulation or the "potential" of lost circulation zones is the single greatest drawback of an oil base mud. Constant monitoring of the mud tanks should be made while drill ahead. The tanks should be checked a minimum of 2 - 3 times every tour, with a record made of premix additions, surface losses, and hole losses. The cuttings from the shale shaker and the underflow discharges from the desilter and/or centrifuge(s) may be retorted to determine the approximate amount of Invert mud that is being lost through the solids control equipment. Various LCM materials have been added to prevent seepage loss in oil base muds, with somewhat limited success. Cellulose LCM material such as Cellophane, Prima Seal, Fiber, and to some extent Sawdust, tend to preferentially water wet in an Invert that could result in "balling up" of the material. Materials which have generally been added to minimize loss of circulation are: 1. 2. 3. 4. 5.

Mica Walnut Shell Ultra Seal Liquid Casing Calcium Carbonate

Generally oil muds are treated with various concentrations of the above products on a tourly basis. They are normally screened out with the shale shakers to prevent a solids buildup, and minimize problems with the pumps. If the rig has the capability, a highly concentrated 8-10 m³ pill can be made up in the pill tank with the various LCM products, and the hole "swept" 2-3 times a tour, depending upon the severity of the loss. The pill should be pumped back to the pill tank, where it can be reconditioned with LCM material, and used again.

3.10.1 SEEPAGE LOSSES


A close watch on daily or tourly seepage loss must be maintained to accurately know how much is being lost to the formation. It must not be confused that seepage loss does not mean losses occurred through the solids control equipment, retention of Invert on the cuttings, losses around the lease, etc. Once an accurate amount of seepage loss to the formation is determined, a procedure can be set up as to the amount and type of LCM material that should be added to the Invert mud, in order to minimize these losses. The amount and concentration of LCM material to be added is strictly an economic choice. The cost of the LCM material being added to the Invert mud must reduce the seepage loss to less than the cost of the LCM material, or the treatment would be more expensive than the loss of the Invert to the formation.

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Below is a combination of materials that have been successfully used to reduce seepage loss. 1. 15-20 kg/m³ of fine grind "325 mesh" Calcium Carbonate, in combination with "0 Grind" Calcium Carbonate. 2. 5-15 kg/m³ of fine to medium grind Mica. 3. 15-75 kg/m³ Ultra Seal XP, depending on the severity of the seepage loss. These products can be mixed together or separately through the hopper. Normally they are screened out at the shale shaker or can be mixed as a pill prior to trips or surveys. Ultra-Seal XP, and other lost circulation material should be stockpiled on location prior to drilling ahead with Invert.

3.10.2 CONVENTIONAL OIL MUD “LCM” PILL (Whole Mud Loss) Return to Table of Contents The following is a recommended LCM pill when whole mud losses are encountered. LCM material should not be added indiscriminately to an oil base mud. Approval from the operator must be obtained prior to pumping any LCM pills. 1. Prior to spotting the pill, it is recommended that there should be no nozzles in the bit. 2. This pill should be isolated in a pill tank or separate premix tank. The LCM material can be added through the hopper, or "gunned in" with a surface gun if available, or added underneath the hopper discharge. Ensure all the LCM material is thoroughly mixed into the mud before spotting the pill. 3. Mix the following materials into 10-15 m3 of Invert: a. 30 kg/m³ Mica. Use a combination of 10 kg/m³ Mica Fine, 10 kg/m³ of Mica Medium, and 10 kg/m³ of Mica Coarse. b. 20-30 kg/m³ of fine #325 Grind to "0" Grind Calcium Carbonate. c. 10-30 kg/m³ of Ultra Seal XP, “C” and Plus Grinds. 4. Pull up to just above the thief zone, and spot the pill slowly in the zone. 5. If this procedure fails, repeat the pill as above, only doubling the concentration of LCM material. This pill should be pumped open ended. If not, ensure that there are no nozzles in the bit. 6. If this procedure fails, another alternative should be considered, such as spotting cement, etc.

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3.10.3 DIASEAL “M” SQUEEZE (Oil Muds)


Diaseal M may require some lead time for prompt delivery. If this pill is to be considered, enough lead time will have to be given to ensure that the material is available.

Diaseal “M” Formulation With Diesel Oil Material Required for a 10 m3 Slurry Density (kg/m3) 950 1080 1200 1320 1440

Diesel Oil (m3) 8.8 8.6 8.3 8.1 7.7

Diaseal “M” (kg) 1250 1170 1085 1000 925

Barite (kg) 0 1750 3490 5380 7430

Nut Plug / Mica (kg) 450 450 450 450 450

Due to the variations of oil and Barite, pilot tests should be made to determine exact formulations. If the slurry becomes too thick, add up to 3.0 kg/m³ of an oil wetting agent to thin the mud. Approximately 40-70 kg/m³ of Mica or Nut Plug can be used in the above formulation without change of properties. Absorbent LCM material such as Sawdust or Prima Seal should be avoided as the slurry viscosity will increase.

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3.11

OIL MUD PRODUCT CROSS REFERENCES

Reef Mud

Carbo-Drill

Dowell / IDF Interdrill D

Envirovert

Canamara United Chemoil

Enviromul

-

Interdrill N

-

-

Versamul

Invermul NT

Carbo-Mul

Interdrill Emul

Enviromul I

Chemul I

Versacoat

EZ Mul

Carbo-Mul HT

Interdrill Vistone

Enviromul II

Chemul II

Secondary emulsifier and wetting agent for invert muds

VG-69 VG-Plus VG-HT Versawet

Geltone II

Carbo-Vis

Interdrill Emul

Envirotone

Viscosifier and gelling agent

Invermul

Carbo-Tec L

Interdrill O.W.

Envirotreat

OMV-100 Oilgel 3000 Chemwet OM

Asphaltic Resin

Versatrol

AK-70

Carbo-Trol

Interdrill S

-

Amine Treated Lignite Oil Mud Thinner LSRV Rheology Modifier, Viscosifier Oil Mud System Viscosifier Surfactant Cleaner

Versalig

Durotone HT OMC

Carbo Trol A-9 -

Interdrill

-

Gilsonite HT Pulverized -

-

-

-

Versamod

Bara Resin Vis

^-Up

-

-

-

Versa HRP

X-Vis

-

Tru-Plex

-

Oilgel 3000

Clean-Up

Bara-Klean

Mil-Clean

Idwash

-

C-3001

Wetting Agent

Versa SWA

-

-

-

-

-

Surfactant to Reduce Oil on Cuttings

Versatrim

-

-

-

-

-

Description Oil Mud System Name Mineral Oil Mud Primary or Basic Emulsifier Secondary or Organic Surfactant Emulsifier Organophillic Clay Oil Wetting Agent

M-I

Baroid

BH Inteq

Versadrill

Invermul

Versaclean


Versathin


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Primary Application Diesel oil Invert mud system Mineral oil Invert mud system Primary emulsifier in the basic oil mud system

Improve oil wetting of solids and emulsion stability Controls HT-HT fluid loss

Filtration Control Reduces viscosity and gel strengths Increases Yield Point, Gel Strengths, and carrying capacity Increases Yield Point, Gel Strengths with minimal Plastic Viscosity Detergent and degreaser for oil mud cleanup and cuttings wash Preferentially oil-wets solids and reverse potential water wetting problems Reduces oil retained on cuttings

TABLE OF CONTENTS – CHAPTER 4

Return to Glossary

Chapter 4 Drilling Fluid Contaminants Return to Table of Contents TOPICS 4.1 4.2

4.3

4.4

4.5

4.6

4.7 4.8 4.9

PAGE

MAKE UP WATER ANHDYRITE CONTAMINATION 4.2.1 DETECTION 4.2.2 TREATMENT CEMENT CONTAMINATION 4.3.1 DETECTION 4.3.2 TREATMENT SALT CONTAMINATION 4.4.1 DETECTION 4.4.2 TREATMENT CARBONATE / BICARBONATE CONTAMINATION 4.5.1 DETECTION 4.5.2 TREATMENT HYDROGEN SULFIDE 4.6.1 DETECTION 4.6.2 TREATMENT 4.6.3 GENERAL PRECAUTIONS HIGH SOLIDS 4.7.1 TREATMENT CONTAMINANT SUMMARY QUICK REFERENCE - RECOGNIZING AND TREATING CONTAMINANTS 4.9.1 CEMENT CONTAMINATION 4.9.2 MAGNESIUM CONTAMINATION 4.9.3 ANHYDRITE CONTAMINATION 4.9.4 SALT CONTAMINATION 4.9.5 CARBONATE / BICARBONATE CONTAMINATION 4.9.6 HYDROGEN SULFIDE 4.9.7 SALT WATER FLOW OR GAS KICK CONTAMINATION 4.9.8 CHEMICAL TREATMENT AND MUD PROPERTY CHANGES

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1 2 2 3 4 4 4 5 5 5 6 6 7 7 8 8 11 11 11 12 13 13 13 14 14 14 15 15 16

5. CHAPTER 4 DRILLING MUD CONTAMINANTS The composition and treatment of drilling fluids depends on the formations encountered, or added intentionally during the drilling operations. Almost any of these materials under certain circumstances can be considered contaminants. This chapter summarizes the various contaminants and describes methods of chemical control and removal of water-soluble contaminants. If large quantities of contaminants are expected or accidentally encountered during drilling, certain factors must be taken into account depending on the contaminants. These factors are considered individually in the following discussions of each type of contaminant. In general, a contaminant is anything that causes undesirable changes in the mud properties. In this sense, each of the essential components of water base muds may become a contaminant in some situations. Solids are by far the most prevalent contaminant in drilling mud. Bentonite added in excess, drill cuttings, or Barite may lead to high rheological properties, and affect drilling rate. Water or excess chemical treatment can lead to drastic mud changes and cause unnecessary and unscheduled Bentonite additions. Some contaminants can be predicted and pretreated. The predicable contaminates are cement, make up water, massive salt or anhydrite, and gases such as Hydrogen Sulfide or Carbon Dioxide. These contaminants can be chemically removed in some cases before they have a chance to attack the clay or organic deflocculants. Pretreatment have advantages as long as it is not excessive, and does not adversely affect mud properties. Other contaminants are unpredictable and unexpected, such as those which result from a small feed in to the mud, or a gradual build up of a contaminant. Eventually the contaminant shows its effect by altering the mud properties of the mud system. This change most often occurs when a drilling fluid is most susceptible, i.e.: when deflocculants (thinners) are slightly depleted, or after a long trip, etc. when the fluid is allowed to remain static and subjected to elevated downhole temperatures, or after an additional contaminant enters the system. It is always necessary to keep complete accurate records of drilling fluid properties, to see the gradual onset on contamination and avoid deterioration of an otherwise good mud system

4.1

MAKE UP WATER


Water is the controlling ingredient in all water base mud systems because it dissolves, suspends, and surrounds all other ingredients making up the system. Make up water containing any contamination will adversely affect the clay particles in a mud system just as though the contaminants were picked up while drilling. For this reason the mud engineer prior to spudding the well should check all unknown sources of water. In many cases it will prove economical to use a more distant water source than to chemically treat out brackish or alkaline water.

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The common contaminants found in make up water include: 1. 2. 3. 4.

Calcium and Magnesium salts. Sulfates Carbonates and Bicarbonates Chlorides (Salt)

There are basically two ways of handling the problem of contaminated make up water. 1. Treat out the undesirable contaminant with Caustic Soda, Soda Ash or Barium Carbonate. For example, to determine the amount of Soda Ash required to treat out excessive total hardness (Calcium and Magnesium Salts) in the make up water, use the following formula: Soda Ash (kg/m3) = (Total Hardness, mg/L x .00014) 2. Leave the contaminants in and add sufficient amounts of dispersant such as SAPP, CF, Alcomer 74 or Lignite to control the flow properties.

Desco

If there are any doubts as to the purity of the make up water, a one litre sample should immediately be sent to a water analysis laboratory. The sample will be analyzed for impurities and a recommended treatment passed on to the parties involved.

4.2

ANHDYRITE CONTAMINATION


Anhydrite can be found in thick beds, in stringers, in the make up water, and sometimes as the cap rock of a salt dome. The chemical composition of Anhydrite is Calcium Sulfate (CaSO4). It is primarily the Calcium that causes the problem with the mud properties. The Calcium ion attracts onto the negatively charged clay platelets, and initially tends to flocculate or "clobber" Bentonite. As the anhydrite concentrations increase toward a maximum calcium solubility of approximately 600 mg/L, a "base exchange" or change in the Bentonite characteristic occurs.

4.2.1

DETECTION


If the mud is fresh water Gel Chemical system, anhydrite will affect the mud properties as follows: 1. Funnel viscosity increase 2. Yield Point increase 3. Gel Strength increase. Will tend to be flat and fragile, i.e.: a flash Gel Strength (high 10 second Gel Strength that is close to the 10 minute Gel Strength). 4. Water loss increase 5. Decrease in the pH 6. Calcium ion increase 7. Sulfate ion increase 8. Small white cuttings over shale shaker.

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4.2.2

TREATMENT


1. If possible, the mud engineer should be on location prior to and while drilling any anhydrite sections. If the contamination is not severe, usually the treatment involves adding Soda Ash (Na2CO3) to precipitate the Calcium ion as Calcium Carbonate. CaSO4 + Na2CO3  CaCO3  + Na2SO4 Prior to penetrating the anhydrite, the pH should be increased to approximately 10.0-10.5 with Caustic Soda. The higher the pH, the less soluble Calcium becomes. A pretreatment of approximately 2.0-3.0 kg/m3 Soda Ash is generally made. While drilling through the anhydrite, the mud engineer should check the properties closely at the flow line and suction tank, and treat accordingly with Soda Ash and Caustic Soda as required. 2.

If the anhydrite contamination is severe and the section to be drilled is quite thick, the mud system may be allowed to “GYP” over and dispersed to control any flocculation. Exact properties, the required level of dispersion and whether the Calcium ion will be treated out or not, will be determined in the drilling fluid program. With the new environmental regulations regarding the amount of Sodium allowed in the soil (Sodium Absorption Ratio), only small amounts of Soda Ash, if any should be used to treat out the soluble Calcium. Most often, no Soda Ash is mixed, and the Calcium level climbs depending upon the amount of anhydrite drilled. The mud properties are then controlled with additions of thinners, and Calcium tolerant fluid loss additives such as Drilstar HT and/or Starpak DP.

3.

Barium Carbonate (BaCO3) may been used for treating small amounts of Anhydrite contamination, but is not a common chemical used in Western Canada. The primary advantage of this product is that the Calcium ion and the (SO4)-2 radical are both precipitated. CaSO4 + BaCO3  CaCO3  + BaSO4  The disadvantage of the product is that it is quite expensive and can be quite toxic. It requires approximately 4.1 kg/m3 of BaCO3 to precipitate 2.85 kg of Anhydrite, which makes it economically impractical to treat appreciable quantities of Anhydrite.

4. Care must be taken not to add too much Soda Ash (Sodium Carbonate) while treating out anhydrite as a Carbonate problem may occur. It is always best to leave a little soluble Calcium in the mud system, i.e.: 60-80 mg/L Calcium to ensure this problem does not exist. Soluble Sodium Sulfate (Na2SO4) formed in the reaction from the Soda Ash treatment, could cause flocculation problems with prolonged treatments, which may require a higher level of dispersion.

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4.3

CEMENT CONTAMINATION


In most drilling operations cement contamination occurs one or more times when casing is cemented, and/or plugs are drilled out. One advantage to encountering cement over other contaminants, is the fact that it is always known when the cement is to be drilled. The extent of contamination and its effect on mud properties depend on several factors. These include solids content, type and concentration of dispersants, and quantity of cement incorporated. Cement contains compounds of Tricalcium Silicate, Calcium Silicate and Tricalcium Aluminate, all of which react with water to form large amounts of Calcium Hydroxide Ca(OH)2. It is the Calcium Hydroxide (Lime) released by cement reacting with water that causes most of the difficulty associated with cement contamination. Lime in drilling fluids causes chemical reactions, which are detrimental to rheological and fluid loss properties. As with the anhydrite contamination, the Ca+2 ion in the Lime will flocculate Bentonite, and the presence of the Hydroxyl ions (OH-) will increase the pH drastically.

4.3.1

DETECTION


Fresh water Gel Chemical systems will be flocculated by cement, resulting in the following changes of the mud properties: 1. 2. 3. 4. 5. 6. 7.

4.3.2

Funnel viscosity increase Yield Point increase Gel Strength increase - Flat and fragile Water loss increase Dramatic increase in pH Pf alkalinity increase Calcium ion increases.

TREATMENT


Chemical treatment must be used to remove the cement contamination. The aim of the treatment is to control the pH while removing Calcium and the excess Lime from the system as an inert, insoluble Calcium precipitate. This is done primarily with Sodium Bicarbonate (commonly referred to as Bicarb). Ca(OH)2 + NaHCO3  CaCO3  + NaOH + H2O 1. To chemically remove 100 mg/L of Calcium originating from Lime (Cement) would require approximately 0.21 kg/m3 of Bicarb. Quite often a pretreatment of 1.5-2.0 kg/m3 is made to the active system prior to drilling out the cement. After the initial circulation, the interface between the mud and cement may be badly flocculated; therefore the mud is normally dumped to the sump for a short period of time. Care must be taken not to over treat with Sodium Bicarbonate, as a Bicarbonate ion problem may occur, making viscosity control difficult.

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2. SAPP (Sodium Acid Pyrophosphate) is another very good product for controlling cement contamination. SAPP is a very powerful phosphate thinner having a pH of approximately 4.0. It will have a threefold effect combating cement contamination by dispersing (thinning) the mud, lowering the pH, and sequestering (removing) the Calcium at the same time. Treatments will vary, but normally a concentration of 0.25-0.75 kg/m3 SAPP is sufficient to thin the mud. A treatment of 0.28 kg/m 3 SAPP will chemically remove 100 mg/L of Calcium originating from the cement. SAPP has a temperature limitation of approximately 85 C. 3. Materials such as Alcomer 74 or 72L can also be used to deflocculate or disperse cement contaminated mud. Both have a low pH of approximately 4.0 but require a higher level of concentration than SAPP to effectively disperse the mud. When cement is completely set or hard, only about 10% is normally available for contamination. Whereas, when cement is soft (green), as high as 50% of the cement may be dispersed and available to react. Because pH values are high when drilling cement, the quantity of Calcium ion in solution rarely exceeds 300 to 400 mg/L. For this reason, much of the cement drilled remains as discrete particles and is available to replace the calcium that has been treated out of solution. High concentrations of excess Lime may require many days to remove, particularly if mechanical solids removal devices such as mud cleaners, fine screen shakers and centrifuges are not used.

4.4

SALT CONTAMINATION


Salt is not a common occurrence in Western Canada, but can be encountered in Rainbow Lake, Zama Lake, Senex or Kidney areas of northern Alberta; south central area of Alberta such as the Bashaw, Clive or Drumheller areas; to the south eastern Estevan area of Saskatchewan.

4.4.1

DETECTION 1. 2. 3. 4. 5. 6. 7.

4.4.2


Funnel viscosity increase Gel Strength increase Fluid loss increase Decrease in pH and Pf alkalinity Chloride ion increase Fluctuation in density - if a salt water flow is encountered "Grainy" appearance to mud.

TREATMENT


Salt cannot be precipitated by chemical means. If salt is encountered, treatments of a dispersant such as Desco CF or Alcomer 74 and Caustic Soda are usually required. It is generally not feasible or practical to dilute the Salt content with fresh water. The required amount of thinner or dispersant will depend upon the concentration of Salt encountered, but the pH should be maintained at 10.0-11.0 with Caustic Soda, as required. If supplementary fluid loss control is required, do not use CMC. A polyanionic cellulose polymer such as Drispac or Staflo, or the modified starches such as Drilstar HT or Starpak DP, work much more effectively in a Salt environment.

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In concentrations above 10,000 mg/L Salt, the hydration of Bentonite becomes severely limited. In a case as this, utilize a premix tank to prehydrate all the Bentonite in fresh water prior to adding to the active system. Generally, Attapulgite or Sepiolite Clay (Salt Gel) is not recommended because most rigs do not have adequate mixing facilities to shear the product sufficiently. The fluid loss characteristics also become very difficult to control. If the salt section to be drilled is thick, switching the mud system over to saturated salt water or an invert mud may be more beneficial and economical. Salt muds can be corrosive in nature, unless the fluid is saturated. Corrosion rings should be run and monitored when running a Salt mud system. Maintaining a high pH will reduce the corrosion of a Salt mud, but it takes approximately twice as much Caustic Soda to maintain a pH in the same range as compared to a water base mud system. An Oxygen corrosion inhibitor such as Corinox or KD-40 should be run when utilizing a Salt Water mud system.

4.5

CARBONATE / BICARBONATE CONTAMINATION Return to Table of Contents

Carbonate problems occur from a variety of sources. Every oil and gas bearing formation contains C02 gas as a result of either oxidation or anaerobic bacteria attack on the hydrocarbons. Limestone formations that have been subjected to heating effects from volcanic activity or acidizing will contain C0 2 gas. Lignosulfonates will give off C02 when subjected to high temperatures. Lignite is a prime source due to its humic acid content. Both dispersants are subject to bacteria attack, which can release C0 2 as part of the degradation process. Mechanical solids control and mixing equipment tend to aerate the mud, consequently injecting a certain amount of C0 2 into the system. Overtreatment with Soda Ash or Sodium Bicarbonate could also cause a Carbonate / Bicarbonate buildup. Carbon Dioxide enters a water base mud system and immediately changes its chemical composition depending upon pH. Below a pH of 6.3, C02 ions are predominant; from a pH of 6.3-10.3 Bicarbonate (HC03-) ions dominate; and a pH above10.3, Carbonates (C03=) are the major ion. Most of our Gel Chemical and dispersed systems have a pH of higher than 10.0, therefore in most cases; excess Carbonates cause the mud difficulties associated with this problem.

4.5.1

DETECTION


A Carbonate / Bicarbonate mud problem has been one of the most difficult contaminates to identify in the field. Characteristically, the problem will show that the Yield Point and Gel Strengths will steadily increase in a pattern similar to a fine solids buildup. Large amounts of water in the past have been added to thin the mud; and subsequent massive additions of chemicals were required to compensate for the dilution. As in the case with any problem, early identification is essential to proper remedial treatment. It is important to note that no one individual mud test will pin point a Carbonate problem. Several indicators will establish the possibility of the problem such as: 1. 2. 3. 4. 5.

Disparity between the Pf / Mf alkalinity Increase in the Yield Point Increase in the 10 minute Gel Strength Solids (retort) are normal Pm alkalinity is lower than the Mf

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The best method for detection is to utilize the Garret Gas Train as outlined in Chapter 1, section 1.13.3. Also outlined in the section are the Pf / Mf and Pl / P2 calculations to determine the amount of soluble Carbonates / Bicarbonates in the mud system.

4.5.2

TREATMENT


As a general rule, anything less than a 1000 mg/L of Bicarbonates or Carbonates will not cause any mud difficulties. Treatment of a Carbonate problem is accomplished with the incorporation of Lime into the mud system. CO3-2 + Ca(OH)2  CaCO3  + 2(OH)This treatment can be difficult, depending upon the solids concentration, etc. and pilot testing should be done before adding the Lime to the active system. The Lime should be mixed in water through the chemical barrel to ensure it is evenly distributed throughout the system. A concentration of 0.25-0.75 kg/m3 is normally a sufficient treatment.

4.6

HYDROGEN SULFIDE


Hydrogen Sulfide (H2S) occurs in various formations throughout Western Canada. Hydrogen Sulfide is particularly harmful because it not only can disrupt mud flow properties; it accelerates corrosion, and is toxic. Extreme safety is required when encountering H2S gas. Not only is it destructive to metal components, but it can kill people. Therefore, the importance of exercising all safety precautions when handling Hydrogen Sulfide cannot be overstressed.

TOXICITY OF HYDROGEN SULFIDE TO MAN

% H 2S 0.5 – 1.0% 50-100 mg/L 1.0 – 5.0% 100-150 mg/L 0.5-2.0% 150-200 mg/L 2.5-4.5% 350-450 mg/L 5.0-6.0% 500-600 mg/L 6% + 600-1500 mg/L

2-15 Min.

Irritation of eyes. Loss of smell Loss of smell Irritation of eyes. Loss of smell Respiratory disturbances; Collapse Collapse *, unconsciousness, death *

30 Min. – 1 Hour Respiratory tract irritation Throat irritation Throat and eye irritation Dull pain in head. Weariness Severe pain in eyes and head; dizziness; death *

4 – 8 hours

8 – 48 hours

Sharp pain in eyes; coughing Hemorrhage and death * Death *

Hemorrhage and death *

* Data secured from experiments on dogs, which have susceptibility similar to man

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4.6.1

DETECTION


1. Hach Sulfide Test (Chapter 1; Section 1.8.2) The Hach Test is a very simple test that can be conducted on both whole mud and filtrates. A sample of mud or filtrate is acidified and then bubbled by adding Sodium Bicarbonate to a small container fitted with a lid holding a lead-acetate treated paper. The expelled gas is passed through the lead-acetate paper. By comparing the shade of the darkened paper with a standard, a close approximation of the amount of Sulfides can be determined. Due to variations in the pH of muds, a fixed amount of acid added to the mud may vary the results of the test. 2. Garret Gas Train – Water Base Muds (Chapter 1; Section 1.8.2) This is a more sophisticated way of measuring the Sulfides in muds and filtrates than the Hach Test measures. It can be very beneficial when a small amount of Hydrogen Sulfide is being induced into the mud. Sulfides can be detected by this method at lower concentrations than by the Hach Test. 3.

Garret Gas Train - Invert Muds (Chapter 3; Section 3.5.9) The Garret Gas Train can also be utilized to detect soluble Sulfides in Invert muds. Invert Emulsion muds can be treated with various solvents and the water phase separated and titrated for alkalinity. By monitoring the alkalinity of Invert Emulsion muds, a high level of Lime can be maintained to combat Hydrogen Sulfide.

4.6.2

TREATMENT


Treatment of the drilling mud is very important when drilling in areas where Hydrogen Sulfide may be encountered. If the Hydrogen Sulfide can be reacted chemically in the annulus then it will not have to be dealt with on the surface. If the reaction is fast enough and pretreatment concentration is adequate, then pipe failure also can be avoided. 1. The only permanent solution to controlling H2S gas is to increase the mud density sufficiently to prevent further intrusion into the wellbore. If an influx is taken, the severity of a H2S problem is directly related to the pH of the mud system. That is, H2S gas will react with the Hydroxyl ions of the existing mud to dissociate into Bisulfide (HS-) or Sulfide (S-) ions, which are not detrimental to rig personnel or metal goods, Therefore, a high pH of 10.5-11.0 should be maintained at all times while drilling through any potential H2S bearing zone. While the S= species is harmless to life and metal goods, it should be emphasized that the potential for danger is present. If the pH was to drop to a low enough value; for example, from a water flow or C02 gas, the S= species would revert back to the H2S gas. 2. There are a number of specifically designed products to precipitate out Sulfides, and pick up Hydrogen to minimize stress cracking of high tensile strength metal. Some of the more popular products mud products that are used to treat H2S is Zinc Carbonate or Zinc Chelated compounds. The drilling fluid program will state recommended concentrations and handling procedures with the various products.

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Treatment of a Small Influx of H2S with Alkalinity (Water Base Muds): Drilling any formation containing H2S could release H2S into the drilling fluid. Small amounts of H2S can be controlled with mud alkalinity, which will neutralize the acid gas. The amount of H2S the mud system can tolerate may be calculated as follows: mg/LH2S = 682 X Pm SG Where: Pm is the ml of N50 Sulfuric Acid (H2SO4) to neutralize 1 ml of mud : SG is the specific gravity of the mud NB: Caution should be exercised when using this method to treat H 2S, as it is a reversible reaction. Pretreatment with Zinc Carbonate: In the case where pretreatment is required for larger volumes and/or higher concentrations of acid gases, the use of ZnCO3 (Zinc Carbonate) is recommended. An initial treatment of 3.0 kg/m3 ZnCO3 is sufficient to treat out 500 mg/L of soluble H2S. Rules of Thumb Treatment for Zinc Carbonate: a. For concentrations of H2S less than 100 mg/L: kg/m3 of ZnCO3 = H2S 166 Where H2S = mg/L of H2S in the filtrate b. For concentrations of H2S greater than 100 mg/L: kg/m3 of ZnCO3 = H2S 166 Where H2S = mg/L of H2S in the filtrate The same formula can be used to calculate the required amount of ZnCO3, but treatment requires the addition of 35 kg of Gypsum plus 15 kg of Lime for every 100 kg of ZnCO 3 added to the system. These 2 chemicals need to be mixed at the same time to prevent any rheological effects from a Carbonate build up. The additional Lime is required to maintain the hydroxyl level for effective H2S scavenging. The pH of the mud system should be maintained in the 10.5-11.0 range.

Page-157

Mixing Procedures for ZnCO3: Zinc Carbonate should be added directly to the system through the hopper. It should be added no faster than 10-15 min.’s/sack and slower if the solids content exceeds 6% by volume. Prior to encountering a possible H2S bearing zone, it is recommended that the mud system may be pretreated with ZnCO3. The Sulfide content of the mud should be determined with the Garret Gas Train. A concentration of 3.0 kg/m3 will remove approximately 500 mg/L H2S. An excess amount of ZnCO3 should be maintained in the system. The addition of ZnCO3 mixed faster than 10-15 min’s/sack can result in aeration of the system. Monitor the addition rate closely - the slower the product is added the better. Because of the slight solubility of Zinc Carbonate, some flocculation of the mud can be expected. The degree of viscosity and Gel Strength increase will be determined by the solids content of the mud. Additions of Desco CF or Alcomer 74 should be used to maintain the viscosity in the desired range. Environmental Consideration when Using Zinc Carbonate: Under the new sump guidelines, the addition of any heavy metal requires the sump to be sampled before any disposal can take place. The allowable amount of Zinc is 600 kilograms. To assist in calculating the amount of Zinc added to the system with the addition of Zinc Carbonate, it is reasonable to use the following formula: Zinc, kilograms = Zinc Carbonate X 0.57 Regulation ID #G50 also deals with the soil loading for heavy metals and set the land spreading maximum of 300 kg/hectare for Zinc. Treatment of a Influx of H2S with Alkalinity (Oil Base Muds): In some areas where Hydrogen Sulfide may be encountered it has become a practice to use oil base muds. This seems to provide protection for metal goods. However, the solubility of Hydrogen Sulfide in oil is greater than it is in water and more pressure dependent. Therefore, more Hydrogen Sulfide could be carried in an oil mud and released all at once when pressure is removed, causing a large volume of free hydrogen sulfide at the surface. By adding excess Lime to Invert muds (20-30 kg/m3), one can take advantage of having high alkalinity for reacting with Hydrogen Sulfide. This necessitates a complicated test for residual alkalinity in the oil-base muds and still leaves a potential problem of flashing dissolved hydrogen sulfide out of the mud as pressure is reduced.

Page-158

4.6.3 1.

2. 3. 4. 5. 6. 7. 8. 9. 10.

11.

GENERAL PRECAUTIONS


Each person whose work may put him where H2S may be present, should be well informed of the characteristics of H2S, its dangers, safety procedures, recommended first aid procedures, etc. Instructions in the use of protective equipment should be given to all employees. Protective equipment should be available when working where H2S may be present. Before entering air suspected of containing Hydrogen Sulfide, a test should be made to determine whether or not the gas is present and its concentrations. Do not try to determine the presence of the gas by its odor. The sense of smell is rapidly paralyzed by H2S. Personnel should use the buddy system and wear air masks in any area that is known or suspected to have in excess of 20 mg/L H2S. Poison gas signs should be widely used at well locations, on leases and on all buildings or other locations where H2S is or may be present. Prevent the escape of H2S fumes into the air of work areas by leaks, etc. Adequate ventilation systems should be used to keep the gas removed from the work area. Never enter a tank, cellar, building or other enclosed or low place where the gas has accumulated without wearing proper respiratory protection equipment and a safety belt secured by a life line held by a responsible person outside. Air masks should be used while working in high places whenever the slightest danger of H2S exists, as H2S can quickly render a worker unconscious and cause him to fall off a tank or other elevated area.

4.7

HIGH SOLIDS


Drilled solids are the number one contaminant of any mud system. It is the one problem the mud engineer has to contend with from spud to total depth. Adverse effects caused by drilled solids account for the major portion of drilling fluid maintenance expenditures. These detrimental effects include the following: 1. 2. 3. 4. 5. 6.

4.7.1

Increased drilling fluid maintenance costs. Difficulty in maintaining proper rheological properties. Reduce penetration rates. Increased frequency of differential sticking. Increased circulation pressure losses. Increase in the severity of contaminants such as anhydrite, salt, cement, etc.

TREATMENT


1. The following attached chart is a guideline of the recommended solids content of a fresh water mud for a given density. 2. The sand trap and shaker tank should be dumped and cleaned regularly to keep the solids content and mud density in an economical range. Keep the pit equalizers a high as possible and always add a good stream of water while drilling. 3. Refer to the chapter on Solids Control.

Page-159

RECOMMENDED SOLIDS CONTENT FOR WATER BASE MUDS

4.8

CONTAMINANT SUMMARY


Treating chemical contaminants is a difficult process. As was discussed under the various contaminant sections, the accurate detection of the contamination concentration is complicated by interfering ions. The test results may indicate a concentration, which is too high or too low, depending upon the contaminant and the mud composition. The same ions, which mask the test results also, interfere with the treatment process. Buffers and other unexpected compounds in solution can negate the treatment or produce unexpected results. To maximize the chances of successfully treating a contaminant, it is recommended to adhere to the following: 1. Proven test procedures with solutions and equipment of known quality and accuracy should be used. 2. Always undertreat a contaminant. An additional smaller treatment is preferable to the problems caused by overtreatment. 3. Addition of the additives slowly over one or two circulations insures an even distribution throughout the mud system. 4. Adequate time must be allowed to achieve expected results before concluding that the additive is ineffective. 5. Pilot test whenever possible and practical.

Page-160

6. It is necessary to keep a detailed record of all treatments and test results so that the unexpected mud rheology changes caused by delayed chemical reactions can be identified. 7. Precipitates frequently remove organic additives from the mud and should be replaced as required. 8. Chemical treatments should not be used as replacement for good solids control. 9. Observe the order of chemical additions in two stage treatments.

4.9

QUICK REFERENCE - RECOGNIZING AND TREATING CONTAMINANTS Return to Table of Contents

4.9.1

CEMENT CONTAMINATION

Detection: 1. 2. 3. 4.

Increase in funnel viscosity, Yield Point, and Gel Strengths. Increase in pH, Pm, and Pf (particularly Pm). Increase in fluid loss. Increase in excess Lime and soluble Calcium (later).

Treatment: 1. Depending on the type of mud system in use, SAPP or other thinners such as Desco CF or Alcomer 74, and Sodium Bicarbonate may be used to lower the pH and precipitate out the soluble Calcium. The clay particles are then free to react with the thinner or deflocculant in use. 2. Large treatments of water, Desco CF or Alcomer 74 to control flow properties. Additions of Bentonite and fluid loss additives are made to obtain the desired fluid loss after flow properties are under control.

4.9.2

MAGNESIUM CONTAMINATION


Detection: 1. Unstable Yield Point and fluid loss. 2. High levels of hardness after treating Calcium with Soda Ash. Treatment: Note: The following treatment is for minor levels of contamination, such as from seawater. Do not use Caustic Soda when treating massive Magnesium contamination such as from Carnalite 1. Raise the pH to 11.0 with Caustic Soda or Caustic Potash (KOH) to remove Magnesium. 2. Maintain the pH at this level to prevent Magnesium from resolubilizing from Mg(OH)2.

Page-161

4.9.3

ANHYDRITE CONTAMINATION



Increase in funnel viscosity, Yield Point, and Gel Strengths. Increase in fluid loss. Increase in soluble Calcium. Possible decrease in Pf and pH.

Treatment: 1. Precipitate or sequester soluble Calcium with Phosphates (SAPP) or Soda Ash. Reduce viscosity with treatments of a thinner such as Desco CF or Alcomer 74, and Caustic Soda. Lower the fluid loss with PAC materials such as Drispac or Staflo, and supplemented with the more Calcium tolerant fluid loss additives such as Drilstar HT or Starpak DP. 2. Allow the anhydrite to remain in the system to give a soluble Calcium level of 400-600 mg/L. Control the viscosity with dispersants, pH and Caustic Soda, and the fluid loss with Drispac, Staflo and/or Drilstar HT or Starpak DP.

4.9.4

SALT CONTAMINATION



Increase in funnel viscosity, Yield Point and Gel Strengths. Increase in fluid loss. Increase in soluble Chlorides and Calcium. Decrease in pH and Pf.

Treatment: 1. Dilute the Salt concentration with water if the Salt formation is to be cased off shortly after drilling. Treat the fluid with dispersants for viscosity control. Add Caustic Soda and Lime in a 1:2 ratio for pH and Pf control. Use the Starch base fluid loss additives such as Drilstar HT or Starpak DP and prehydrated Bentonite for fluid loss control. 2. If the Salt section is not to be cased off, and the formation is to be left exposed for a long period of time, saturate the system with Sodium Chloride (Salt) to prevent further hole enlargement. Control the viscosity with treatments of Desco CF, plus Caustic Soda and Lime. Control the fluid loss additions of Drispac and/or Drilstar HT and Starpak DP, and prehydrated Bentonite additions. If Starch is used for fluid loss control only, maintain the Chlorides at saturation (±190,000 mg/L) to prevent fermentation of the Starch. If not, then a Biocide will have to be utilized.

4.9.5

CARBONATE / BICARBONATE CONTAMINATION



High Gel Strengths. Increase in Pf with a constant pH. Increase in the difference between the Pf and Mf alkalinity. Increase in the Carbonate or Bicarbonate levels.

Page-162

Treatment: 1. Raise the pH to 10.3 to 11.3. 2. Add Lime and/or Gypsum – two soluble sources of Calcium to remove Carbonates.

4.9.6

HYDROGEN SULFIDE

Detection: 1. Decreasing alkalinities. 2. Slight foul odor (rotten eggs) at the flowline. 3. Mud or pipe turns black. Treatment: 1. Increase the pH to 10.5-11.0 with Caustic Soda. 2. Buffer with Lime. 3. Add a H2S scavenger such as Zinc Carbonate.

4.9.7

SALT WATER FLOW OR GAS KICK CONTAMINATION

Detection:


1. Increase in the mud pit level. 2. Increase in the rate of returns form the wellbore. 3. Increase in Chloride content of the mud. Treatment: 1. 2. 3. 4.

Shut down the pump. Pick up off bottom to clear the kelly bushing. Close in the well with the BOP. Measure the drill pipe pressure, and calculate the additional mud density that will be required to balance the kick. 5. Increase the mud density to the required density while circulating the kick out at a reduced pump rate. 6. If it is a gas kick, remove the gas form the system by use of the surface circulating equipment and degassers. 7. If it is a Saltwater flow, dump the salt water at the surface (if possible). Then condition the fluid with additional dispersants and Caustic Soda. Dilution of the NaCl ion concentration with freshwater may be required. Small treatments of Lime and Caustic Soda may also be required for pH and Pf control.

Page-163

Contaminant

Contamination Ion

Carbon Dioxide Anhydrite or Gypsum

Carbonate Bicarbonate Calcium

Lime or Cement

Calcium and Hydroxyl

Hard or Seawater Hydrogen Sulfide

Calcium or Magnesium Sulfide ( H2S, HS-, S2-)

Treatment

Gyp to maintain pH Lime to raise pH Soda Ash SAPP Sodium Bicarbonate Sodium Bicarbonate SAPP Citric Acid Caustic Soda Zinc Carbonate plus sufficient Caustic Soda to maintain a pH of 10.5-11.0

1. Fw is the fractional % of water from the retort. 2. Excess Lime (kg/m3) = 0.074178 {Pm – (Pf X Fw)}.

4.9.8

Treating Concentration (kg/m3) mg/L X Fw X 0.00285 mg/L X Fw X 0.00121 mg/L X Fw X 0.00265 mg/L X Fw X 0.00277 mg/L X Fw X 0.002097 kg/m3 Excess Lime X 3.23 kg/m3 Excess Lime X 3.281 kg/m3 Excess Lime X 5.4 mg/L X Fw X 0.00285 mg/L X Fw X 0.002596


CHEMICAL TREATMENT AND MUD PROPERTY CHANGES

PV 

YP 

Gels 

FL 

pH 

Pm 

Pf 

Mf 

Cl

Ca+2 pH 11.5

Solids 



















































Carbonate or Bicarbonate



























H2S



























Solids – Old



























Solids - New



























Contaminant Cement

WT 

Anhydrite



Salt

 Increase

FV 

 Decrease

 No Change

 Slight Increase

 Slight Decrease


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Treatment Bicarb, SAPP, Desco Citric Acid Caustic, Dilution and Thinner, or Soda Ash Caustic, Water Dilution, Thinners pH < 10.3: Lime pH 10.3-11.3: Lime and Gyp pH> 11.3: Gyp Caustic, Lime, ZnCO3 Dilution and Solids Control Equipment Dilution, Solids Removal Equipment, Thinners

TABLE OF CONTENTS – CHAPTER 5 Chapter 5 TOPICS 5.1

5.2

5.3

5.4 5.5 5.6 5.7

Return to Glossary

Mud Related Drilling Problems

Return to table of contents

STUCK PIPE 5.1.1 BRIDGING 5.1.2 DIFFERENTIAL STICKING LOSS OF CIRCULATION 5.2.1 CONVENTIONAL "LCM" PILL 5.2.2 GUNK SQUEEZES 5.2.3 CALCIUM CARBONATE (CaCO3) PILL - "CEMENTING UNIT REQUIRED" 5.2.4 CALCIUM CARBONATE (CaCO3) PILL - NO CEMENTING UNIT REQUIRED 5.2.5 DIASEAL "M" PILL 5.2.6 THIXOTROPIC CEMENT SQUEEZE 5.2.7 SEPIOLITE (Sea Mud / Salt Gel) LCM PILL 5.2.8 “ULTRA SEAL” LCM PILL 5.2.9 ULTRASEAL “POLY PLUG” GEL SEALANT SHALE PROBLEMS AND BOREHOLE STABILITY 5.3.1 RUBBLE ZONES 5.3.2 SHALE HYDRATION AND DISPERSION COAL FOAMING BARITE PLUG CORROSION

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PAGE 1 1 2 6 6 7 8 9 9 11 12 12 13 15 15 16 18 19 20 21

CHAPTER 5 MUD RELATED DRILLING PROBLEMS 5.1

STUCK PIPE


The drill string can be stuck for may reasons including poor hole cleaning due to inadequate mud carrying capacity, sloughing shale, key seating and/or differential pressure sticking.

5.1.1

BRIDGING

Bridges can be caused by poor cleaning or by sloughing of the walls into the wellbore. The key to a muds lifting capacity is indicated by the appearance of formation solids coming over the shale shaker. An unusually large amount of shale indicates that the hole is washing out. Rounded edges on large cuttings show that these pieces have been tumbling in the hole for a long time and are not being lifted out effectively. Long splinters or fissured shale may indicate that the shale is "popping" into the wellbore, indicative of overpressured shale. At times large amounts of material can remain in the hole without any surface indication that a hole cleaning problem exists. Large pieces of rock, which are not removed from the hole often, become lodged between stabilizers or reamers and the hole. If this occurs while drilling, the torque required to rotate the drill string will increase rapidly. If pieces of rock become lodged while making a connection or during a trip, the additional pull of the hook will appear as a drag. A sudden increase in pump pressure can sometimes be observed, as bridges form and restrict mud flow up the annulus.

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Methods of preventing stuck pipe due to sloughing shale or inadequate hole cleaning may include the following: a) Increase the viscosity and particularly the Yield Point of the mud. There is no exact yield value that can be specified, as every situation is unique, but generally an upper Yield Point of ±15 Pa should clean most cuttings or cavings from the wellbore. Again watch the shale shaker closely to determine the characteristics of cuttings. b) If possible annular hydraulics should be improved, to provide faster cuttings transport. Pump liners may have to be changed or larger bit nozzles utilized so that more fluid may be circulated without excessive pump pressure buildup. Critical velocities should be calculated to avoid turbulent flow that could increase shale problems by tearing up or eroding the hole. c) Use viscous pills to sweep the hole when drilling. This is a common and effective practice when drilling with flocculated water. d) Increasing the mud density may be beneficial in some cases to balance the pore pressure of the shale, and to help hold formations in place to stabilize the wellbore. e) Reducing the water loss may help to minimize the hydration of shales and wetting along bedding planes with could disperse and slough into the wellbore. f) The drill string itself should be evaluated to minimize flexure of the string against the sides of the wellbore, which might tend to physically knock shale from the walls of the borehole. g) Keep the hole full at all times. Avoid excessive surge or swab pressures by tripping slowly, especially if a float is utilized in the string. h) Use invert mud or inhibitive water base mud.

5.1.2

DIFFERENTIAL STICKING


Differential pressure sticking of the drill pipe can be defined as the force that holds the pipe against the wall of the borehole due to the differential pressure between the hydrostatic pressure of the mud column and the formation pressure. The pressure differential acts in the direction of the lower pressure in the formation. This pressure pushes the pipe toward the permeable formation. As the pressure differential gets larger, the force exerted on the pipe gets larger. Differential stuck pipe occurs most often at a point next to the drill collars. This is due to the drill collars being larger; hence more surface area is in contact with the side of the wellbore. The following are major factors in differential pressure sticking: a) The pipe becomes stuck opposite a permeable formation. b) The sticking occurs after an interruption of pipe movement. c) The pipe comes in contact with a soft, mushy or non-resilient type wall cake. If the pipe is differentially stuck, as opposed to other types of sticking, the following will occur: a) Circulation, if interrupted, will be restored and maintained after sticking is noticed. b) The pipe cannot be raised or lowered. c) No large amounts of cuttings are circulated out.

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The force required to move differentially stuck pipe could exceed the strength of the drill pipe. Several preventative steps can be taken to minimize the chances of becoming stuck: a) The mud density should be maintained as low as practical, taking into consideration wellbore stability and potential well control problems. b) Keep the pipe moving or rotating. Avoid undue shutdowns and/or slow connections. Use spiral drill collars to reduce the contact area against the wellbore. c) Maintain a low fluid loss and pay particular attention to the filter cake; i.e.: it should be thin, tough and resilient. In areas where differential sticking is prevalent, the high temperature / high pressure fluid loss should be maintained below 20 cm3. d) Adding 2-8% oil to the mud system gives preferential oil wetting to the drill string, thereby allowing better lubricity and minimizing the possibility of stuck pipe. New environmental regulations may make adding oil to the mud prohibitive. When the drill string become stuck, it is imperative to act quickly as the sticking coefficient increases with time. To avoid costly and time consuming washover operations, a couple of methods are generally used to free the pipe.

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a) Spotting crude oil or diesel oil with a surfactant around the drill collars has gained wide acceptance. There are many surfactants available; i.e.: Canfree, Pipelax, Kum Free, BFree, EZ Spot, Freepipe, etc. If a surfactant is not available on location, a straight diesel oil pill should be spotted across the collars as quick as possible. If differential sticking is suspected in an area, always keep 1 or 2 drums of a differential sticking surfactant on location in the event it may be required. Generally enough pill is mixed up to cover the entire length of the drill collars, plus an excess of 1.5 m3 (10 bbls) to be left on top of the collars, and another 3.0 m 3 (20 bbls) to be left inside the drill collars. Normally 20-25 litres of surfactant is recommended per cubic metre of diesel oil (12 gal/bbl). The pill should be spotted leaving 3 m3 (20 bbls) inside the drill string. The pipe should then be worked by pulling up to a predetermined over pull weight, applying torque and releasing the weight at regular intervals. The pill across the collars has a tendency to migrate up the hole; therefore approximately 0.1 m3 (1/2 - 1 bbl) of excess fluid in the pipe should be pumped every half hour. An average waiting period is generally 10-12 hours. If the pipe does not come free in a reasonable period of time (maximum of 2 pills), mechanical methods may be required to free the pipe. If the spotting pill has to be weighted due to an abnormally pressure zone, or to increase the pill density to that of the mud weight to minimize migration, the spotting procedure would be the same although some of the products may be different. The mixing procedure of the various products will be outlined in the drilling mud program. b) Reducing the hydrostatic pressure and therefore the differential pressure with the use of a packer has been tried as another alternative. Considerations regarding wellbore stability and potential well control problems must be evaluated prior to implementing this method. After the free point is determined, the pipe is backed off and hoisted. A fishing string is made up and run in consisting of the following: -

screw in sub perforated joint packer jars

-

safety joint a hydraulic or disc valve crossover sub drill collars

After the packer is set, the hydrostatic pressure is relieved from the fish and the drill collars should come free.

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DIFFERENTIALLY STUCK PIPE

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5.2

LOSS OF CIRCULATION


Loss of circulation can be a frustrating and expensive problem. There are no “cure all” products and/or procedures when combating loss of circulation. Every situation tends to be unique in nature. A few things should be considered though when analyzing the problem. When loss of circulation is first noted, the conditions at the time the loss occurred should be studied. The time of the occurrence (while drilling, circulating or tripping), the type of loss (seepage, partial or complete), and the severity of the loss with respect to the exposed formations should be considered to determine when the loss occurred, where (in the hole) the loss occurred, and the best remedy for the situation. Please review the following techniques for a few possible remedies to cure loss of circulation.

5.2.1

CONVENTIONAL "LCM" PILL


Consider using a combination of LCM material with varying sizes to provide for an optimum bridging agent with this type of pill. Small amounts of Lime may be used to slightly flocculate the Bentonite, to increase the viscosity preventing the LCM material from settling out and plugging the bit. It is cheaper to obtain the viscosity using small amounts of Lime. The Lime addition will also provide a higher fluid loss than the Gel slurry thereby increasing the sealing rate. The actual concentration of LCM in the pill may vary; the formulation listed below assumes no jet or very large nozzles in the bit. Once the approximate point of loss is established, a 15 -30 m3 (100-300) barrel pill should be mixed as follows:

1. 2.

Fresh Water Soda Ash

15-50 m3 0.50-0.75 kg/m3

3. 4.

Caustic Soda Bentonite

0.50-0.75 kg/m3 70-75 kg/m3

5. 6.

Sawdust Kwik Seal/ Prima Seal Cellophane/Walnut Shells/Mica Lime

15 kg/m3 15 kg/m3

Actual concentration will depend upon the hardness of the water. Increase pH to 9.0-9.5 Allow enough time to hydrate fully. Initial viscosity should be ± 50-60 sec/L. "Gun " in thoroughly. Coarse to medium.

15 kg/m3

Medium to fine.

1.0-1.5 kg/m3

Raise viscosity to a approximately ±80-100 sec/L.

7. 8.

Once the pill has been mixed, spot just above the loss zone by pumping slowly; 160-320 litres/min. (1-2 bbl./min.) until the hole is full and circulation is regained. If the hole remains full, close the hydril and squeeze the annulus with 300-500 kPa (50-75 psi) for 30 minutes. If this procedure fails, repeat once. A second failure may indicate that another technique may be in order.

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CONTROL OF LOSS OF CIRCULATION

EFFECTIVE CONTROL OF MUD LOSSES INTO A PERMEABLE ZONE REQUIRED A WIDE RANGE OF PARTICLE SIZES

5.2.2

GUNK SQUEEZES


A Diesel Oil / Bentonite (DOB) or a Diesel Oil Bentonite / Cement (DOBC) squeeze may be considered in cases of more severe losses. These pills are recommended to be pumped open ended, but can be pumped through a bit with no nozzles, or large diameter nozzles. If possible, drilling should continue without returns, through the entire thief zone. The amount to mix will vary, but generally twice the open hole volume, or a maximum of 15 m 3 should be sufficient. The Gel Cement mixture should be pre-blended in bulk form if possible. Sacked material may be used, but it makes the pill more difficult to mix, and the slurry is not as homogenous. A cementing unit should always be used to pump these pills. The pill should be spotted just above the loss zone. A concentration of 900 kg/m 3 of Gel (300 lbs./bbl.) should be mixed per m3 of Diesel for the DOB squeeze. The same concentration applies for the DOBC squeeze, but the Gel and the Cement should be pre-blended or mixed in a 1:1 ratio.

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1. 2. 3. 4. 5.

Pumping and mixing equipment should be free of any water to prevent contamination. Pump a 2m3 spacer of Diesel fuel. Mix and pump the DOB or DOBC squeeze. Follow the squeeze with a 1m3 diesel spacer. Displace the slurry down the drill pipe with water or mud at approximately 0.2-0.3 m3/min. (12 bbl's/min.). 6. When the pill reaches the bit, or if the annulus fills, close the hydril and slowly displace the gunk squeeze into the thief zone. 7. Try and squeeze with up to 700-2100 kPa (100-300 psi) pressure. Do not exceed 3500 kPa. 8. When this is complete pull up and wait approximately 1 hour for the DOB squeeze, and up to 8 hours for the DOBC squeeze before drilling ahead.

5.2.3

CALCIUM CARBONATE (CaCO3) PILL - "CEMENTING UNIT REQUIRED" Return to table of contents

This type of pill utilizes different sizes of grinds of CaCO3 with Kelzan XCD Polymer for viscosity control. It is a very competent type of pill as the bridging agents are actually limestone or dolomite rock. The advantage of this type of pill is that all the ingredients are acid soluble. Therefore, if the loss of circulation is in or close to the carbonate productive zone; i.e.: the Keg River Formation in Rainbow Lake, Zama, or Shekilie areas, formation damage is kept to a minimum. This pill must be spotted open ended. A cementing or acidizing unit with pressurized suctions, and batch mixing augers must be utilized. The largest size nozzle for the jet mixer should also be utilized. 1. Run the drill pipe to just above the thief zone or into the intermediate casing. 2. Initially batch mix a 36 barrel (5.7 m3) CaCO3 pill (18 barrels in each of the cementing unit's tanks). The size of the pill may vary somewhat, depending upon the amount of open hole and volume of the mixing unit's tanks. Batch mix as follows: a. Mix 1 sack of Kelzan XCD Polymer. b. Batch mix 30-35 sacks of (145 kg/m3) of "325" Grind" CaCO3 (Extra Fine Grind). c. Then mix 20-30 sacks (110 kg/m3) of "Feed Grit" CaCO3 (Coarse Grind). 3. Displace the pill to the bottom of the drill pipe at approximately 0.5-0.6 m3/min. 4 bbl's/min.).

(3-

a. While displacing, add an additional 16-18 sacks (75 kg/m 3) each of "Poultry Grit" CaCO3 (Extra Coarse Grind), and the next coarser size, "Hard Shell" CaCO3 (1/4" diameter sized CaCO3). b. At the same time, small amounts of Kelzan XCD Polymer may have to be added for additional viscosity control. c. Near the end of the displacement, quickly add another 5 sacks of "325 Grind" CaCO3 (Extra Fine Grind). 4. Slowly displace the pill into the thief zone at approximately 0.15 m 3/min. (1 bbl./min.). Leave approximately 1-2 m3 (10-15 bbls.) inside the drill string for further squeezing. 5. Try to fill the annulus with the mud pump. Pump a maximum of the total annular volume, or until the hole fills.

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6. Close the hydril and squeeze 2-3 barrels ( 0.5 m 3) every 10 minutes until the pill is out of the drill string. Generally, do not exceed 3500 kPa pressure on the annulus.

5.2.4

CALCIUM CARBONATE (CaCO3) PILL - NO CEMENTING UNIT REQUIRED Return to table of contents

This type of pill is basically the same as the previous pill, except it is formulated with finer grind Calcium Carbonate, and therefore can be mixed in a premix tank, rig tank or pill tank. 1. Run the drill pipe to just above the thief zone. 2. All of the following materials can be batch mixed as follows: a. b. c. d.

Mix approximately 1.5-3.0 kg/m3 of Kelzan XCD Polymer for viscosity control. Then mix 145 kg/m3 of "325 Grind" CaCO3 (Extra Fine Grind). Mix approximately 110 kg/m3 of the next coarser "O" Grind CaCO3 (Fine Grind). Follow with approximately 75 kg/m3 each of the next two coarser grinds of Calcium Carbonate; i.e.: "Feed Grit" CaCO3 (Coarse Grind) and "Poultry Grit" CaCO3 (Extra Coarse Grind).

3. Displace the pill to the bottom of the drill pipe at approximately 0.5-0.6 kg/m3 (3-4 bbl's/min.). 4. Slowly displace the pill into the thief zone at approximately 0.15 m 3/min. (1 bbl./min.) Leave approximately 1-2 m3 (10-15 bbl's) inside the drill string for further squeezing. 5. Try to fill the annulus with the mud pump. Pump a maximum of the total annular volume, or until the hole fills. 6. Close the hydril and squeeze 2-3 barrels every 10 minutes until the pill is out of the drill string. Generally do not exceed 3500 kPa pressure on the annulus.

5.2.5

DIASEAL "M" PILL


Diaseal M is a blend of "diatomaceous earth" which forms a stable, high solids slurry. The slurry dehydrates rapidly after being spotted in a thief zone, and leaves behind a solid, acid soluble plug. The slurry will lose all of its water in 1 or 2 minutes on a standard API water loss test. This equates to a water loss of approximately 1000 cm 3 and results in a cake more than one inch thick. Bridging type LCM material and Barite can be added as needed. Bridging is needed in impervious zones in the fracture or vug close to the wellbore, to initiate filtration and let Diaseal M form a plug. In permeable loss zones, there is little need for LCM. The initial density of the slurry is 1080 kg/m3. Barite may be added to increase the density to approximately 2275 kg/m 3. Diaseal “M” is a very effective LCM pill, although sufficient time will be required to ensure that this product is available in sufficient quantities in Alberta or B.C. If this pill is to be considered, sufficient time must be required to ensure that the product is available.

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FORMULATION TO PREPARE 1 m 3 OF DIASEAL “M” WEIGHTED SLURRY WITH FRESH WATER

Density (kg/m3) 1080 1200 1320 1440 1560 1680 1800 1920 2040 2160 2280

Kilograms of Diaseal “M” 140 140 134 120 108 97 88 80 71 63 48

Barite (kilograms) 0 171 342 513 655 826 997 1140 1311 1482 1653

Water Required (m3) 0.87 0.84 0.80 0.77 0.74 0.70 0.67 0.63 0.60 0.56 0.52

Squeeze Procedure: 1. Generally mix twice the open hole volume. This should cover all possible places where the loss could be occurring (since that is seldom known exactly), plus it provides additional volume for squeezing. 2. It is preferred to mix the slurry in a premix tank, or a ribbon blender if available. If the mud tanks are used, clean them well before mixing the slurry. It is preferable to use a cementing unit for displacement of the slurry. The slurry can be pumped through a bit with large or no nozzles in the bit, but if possible, it is always best to pump the pill open ended. 3. Begin with approximately 80% of the prescribed water volume. To the water, add Diaseal “M”, Barite, and the remainder of the water, followed by any additional LCM material. 4. If the LCM pill is to be weighted, it should be of the same density as the mud. 5. Some additional LCM will usually help. 15-60 kg/m3 total LCM is recommended, depending upon the loss conditions. The higher the density of the LCM pill, the less supplemental LCM material should be used. A mixture of medium Kwik Seal, Prima Seal, Walnut Shells or Cellophane has proven to be good. Do not use any LCM material coarser than medium. Actual concentration of supplemental LCM material will depend upon bit nozzle size, etc. 6. It is recommended that the adjustable choke pressure gauge be taken off the standpipe and put on the “chicksan” line running from the cement truck to the wellhead. In this way, accurate pressure readings can be seen on the drill pipe and casing from the choke gauges. 7. Run in with drill pipe to a depth that will leave one open hole volume equivalent of slurry inside the casing above the casing shoe. 8. Pump the slurry at 0.3 m3/min. (2 bbl's/min.) until it reaches the end of the drill pipe. Observe the annulus and fill the hole with water before closing the hydril. 9. Close the hydril and pump at 0.15 m3/min. (1 bbl./min.). This will force the Diaseal M slurry down the hole to the point of loss. Pump the full open hole volume, plus an additional 4 -5 m3, leaving the remainder of the slurry in the casing. 10. Leaving the hydril closed, shut the pump down for approximately 2 hours. This will allow enough time for the water to leak from the slurry and form the plug.

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11. Idle the pump and begin pumping at 40-50 litres/min. (1/4 bbl./min.) When 350 kPa pressure is reached, shut the pump down and wait 10-15 minutes. Repeat this procedure to 350 kPa one to two more times. Then try a higher pressure such as 500-700 kPa, stop the pump and wait 15 minutes. Continue this procedure to progressively high pressures. There may be a pressure bleedoff each time the pump is stopped, but with each successive squeeze, the hole should stabilize at a higher holding pressure. 12. A 3500 kPa squeeze is very good. If it can be held for 30 minutes to an hour, it will aid in setting a more permanent plug. It may be advisable to go ahead and squeeze to a higher known equivalent mud density, if the higher density will be needed later in the hole. 13. Bleed the pressure off the annulus slowly, and then circulate the remaining Diaseal “M” slurry out of the hole. Return back to bottom slowly. Any remaining Diaseal “M” may be retained in the mud.

5.2.6

THIXOTROPIC CEMENT SQUEEZE


Thix-Mix is a special blend of Class "A" and Gyp-Cement used to impart thixotropic properties to the cement; i.e.: low viscosities are prevalent while pumping. But when movement is stopped, the viscosity of the slurry becomes very high, or it thickens to the extent that it will resist flow (5-10 minutes). It is imperative that pumping is not interrupted while mixing or displacing the pill. Utilize a standby cementing unit or the mud pump in the event that the primary cement unit should break down. The slurry can be pumped through a bit with jet nozzles, but it is recommended that the nozzles be left out, or pumped open ended. 1. Attempt to drill with partial returns or blind through the entire thief zone. 2. Pull up to just above the thief zone to spot the pill. If intermediate casing is set above the loss of circulation zone, setting a Baker Model "K" retainer in the casing and "bullheading " the cement through the retainer is recommended. 3. Mix a thixotropic cement plug of approximately twice the open hole volume as follows: (based on Nowsco's slurry properties). Water Requirement: Yield: Slurry Density:

0.594 m3/tonne 0.915 m3/tonne 1741 kg/m3

Thickening Time:

% CaCl2 0 1 2 3

Thickening Time 6:00 + 4:00 + 3:33 -

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6:08 3:00 2:00 1:40

5.2.7

SEPIOLITE (Sea Mud / Salt Gel) LCM PILL


The use of this high fluid loss slurry containing LCM can be advantageous in that a plug of LCM and mud solids will be quickly deposited in the loss zone as the fluid rapidly de-waters after the initial bridge forms. The following formulation is recommended: 60-70 kg/m3 As required.

Sea Mud/Salt Gel (Sepiolite) Assorted LCM

The type and amount of LCM will depend upon the situation, i.e.: nozzle sizes, open ended, etc. PROCEDURE: 1. Fill the premix tank with water and mix 60-70 kg/m3 of Sea Mud (Sepiolite) or Salt Gel (Attapulgite Clay). This product requires shear to aid in yielding. Ensure that the fluid is premixed at least 12-24 hours prior to encountering the potential LCM zone, if possible. 2. Add 1 sack of Lime to ensure that the slurry has a high fluid loss. 3. Initially, pretreat with LCM that is compatible with the nozzle sized (if present). Higher concentrations and larger particle sizes and types can be employed only if open ended. 4. Spot the pipe above the zone and fill the pipe with the slurry. 5. Pump out 5-10 m3 slowly and wait 15-20 minutes. Repeat until all the slurry is displaced, Repeat as required.

5.2.8

“ULTRA SEAL” LCM PILL


SEEPAGE LOSSES ( 0 – 1.5 m3/hour): Mix 30-35 kg/m3 Ultra Seal “XP” and sweep the hole. PARTIAL LOSSES (1.5 – 3.0 m3/hour): Mix 35-70 kg/m3 Ultra Seal “XP”, and spot across the thief zone. HEAVY LOSSES: Mix 70 kg/m3 Ultra Seal “C” and 35 kg/m3 of Ultra Seal “XP”. This pill should be spotted above the thief zone, and staged out of the bit at a rate not to exceed 0.4 m 3/minute (SLOW PUMP RATE). TOTAL LOSSES: Mix 85-171 kg/m3 Ultra Seal “Plus” into a minimum of 15 m3 of drilling fluid. Again, this pill should be spotted above the thief zone, and staged out of the bit at a rate not to exceed 0.4 m3/minute (SLOW PUMP RATE).

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5.2.9

ULTRASEAL “POLY PLUG” GEL SEALANT


Ultraseal Poly Plug Gel Sealant is a combination of current cross-linking Polymer technology, combined with patented fibers found in the Ultra Seal additives. The same basic chemistry also produces superior Gels for total shut-off squeeze treatments that effectively seal off water or gas. Ultraseal Poly Plug is a complete single sack system composed of selected sized fibers, Polymer and a cross-linking agent in a single sack. The product can be easily mixed at the well site using conventional rig equipment. The Gel Sealant invades the pore spaces for permeability reduction in matrix rock, or reduces flow in secondary porosity of naturally fractured zones. It can be used to selectively shut off a zone and to seal open hole sections in vertical as well as horizontal well bores. POLY PLUG MIXING PROCEDURES: When mixing Poly Plug, slurries above 1680 kg/m3, it is recommended to utilize a “blender” (i.e.: RMX Dowell or Halliburton Blender). The Poly Plug is a high molecular weight Polyacrylamide Polymer, crosslinking and LCM. Once mixed, the slurry has a high viscosity (± 120 sec/L unweighted slurry). When adding a large amount of Barite, the viscosity will be ± 150 sec/L. This high viscous slurry can overwhelm the centrifugal pump(s) running the hopper. SLUGGING OR PILL TANK RECOMMENDATIONS: 1.

2. 3. 4.

The pill tank and all circulating lines must be clean and free of any drilling fluids. Additionally, the tank must be free of any leaks. This will eliminate possible contamination of the pill prior to pumping. Add the appropriate amount of water to the tank. Add the appropriate amount of Retarder if required – Ultraseal “XLR”. Add the appropriate number of sacks of Ultraseal Poly Plug – 1 sack per initial bbl. of water (6 sacks per cubic metre of water). Note: If the pill is to be weighted, add half of the Poly Plug Gel Sealant. Weight the slurry to the desired density and then add the remaining Poly Plug Sealant.

5. Control any foaming with an Alcohol de-foamer only, such as XL Defoamer. Do NOT use Aluminum Sterate or Try-butyl Phosphate. 6. A 5 m3 high viscosity spacer should be built from the existing mud system. The viscosity should be ± 120 sec/L. Place 2.5 m 3 of spacer in front of the pill, and 2.5 m 3 behind the pill. This will minimize contamination while displacing. 7. Displace at a rate of ± 1 m 3/min. Reduce to a slow pump rate when the material is near the thief zone. 8. The pill MUST be squeezed into the formation to prevent subsequent operations from removing the crosslink Gel from the wellbore. Pull above the pill and squeeze until pressure holds. Hole squeeze pressure for 4 hours. After waiting 4 hours, begin washing through the plug. After 4 hours, the crosslink will have developed maximum strength. 9. Fill the pill tank with water or mud to wash out the remaining Poly Plug. This can be used as part of the displacement volume.

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BLENDER RECOMMENDATIONS: 1. 2. 3. 4. 5.

Fill the blender with water and flush blender. Add the appropriate amount of water to the blender. Add the appropriate amount of Retarder if required – Ultraseal “XLR” and circulate the tank for 5 minutes. Pre-treat the tank with 0.3-0.6 litres/m3 of an alcohol base Defoamer XL Defoamer. Do NOT use Aluminum Stearate or Tri-butyl Phosphate defoamers. Add the appropriate amount of Poly Plug – 1 sack per bbl. of water (6 sacks per cubic metre of water). Note: The mix rate should be 1-2 minutes/sack of Poly Plug. This will minimize “fish eyes”. Additionally, use the booster pumps for maximum shear.

6.

If weighting the slurry, add 2/3 of the Poly Plug, and then begin adding Barite. It is recommended to utilize a bulk truck and blow the weight material in. You can add the remaining Poly Plug while adding the weight material. Pressure mud scales will be required to obtain an accurate weight measurement. 7. A 5 m3 high viscosity spacer should be built from the existing mud system. The viscosity should be ±120 sec/L. Place 2.5 m 3 of spacer in front of the pill, and 2.5 m 3 behind the pill. This will minimize contamination while displacing. 8. Displace at a rate of ± 1 m 3/min. Reduce to a slow pump rate when the material is near the thief zone. 9. The pill MUST be squeezed into the formation to prevent subsequent operations from removing the crosslink Gel from the wellbore. Pull above the pill and squeeze until pressure holds. Hole squeeze pressure for 4 hours. After waiting 4 hours, begin washing through the plug. After 4 hours, the crosslink will have developed maximum strength.

Summary of lost circulation material tests (after Howard and Scott)

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5.3

SHALE PROBLEMS AND BOREHOLE STABILITY Return to table of contents

There is not a drilling fluid system available that will maintain a "completely" stable wellbore under all geological and mechanical conditions in the foothills. This is due to physical factors, not chemical factors relating to the drilling fluid. There are many variables involved to maintain borehole stability. A checklist of information must be known to determine the proper action to follow in altering the drilling fluid parameters or downhole equipment. First, there should be a complete mud check taken and reported at regular intervals. The viscosity variation (taken at the flowline and suction tank) of the mud should be monitored closely and reported during the course of the day. Drilling parameters such as whether the mud is in turbulent flow around the collars should be looked at. Geological analysis of the formation is needed. The amount of background gas should be known. Additional details are required on the bottom hole assembly (square drill collars, stabilizers, reamers, keyseat wipers and any other downhole equipment) and whether any recent changes have been made in the assembly. Details are needed in porosity (i.e.: drilling breaks), therefore the possibility of excessive filter cake buildup. Deviation surveys, the amount of torque or drag, how the hole acted coming off bottom, condition of the connections and what type of shale is coming out of the hole (slivers, rounded or jagged chunks) must be known. A close watch on hole cleaning must be observed. The drilling fluid must have a high enough effective annular viscosity to clean the hole, especially in washed out section. Tripping rates should be monitored with pressure losses calculated to keep the surge and swab pressures at a minimum.

5.3.1

RUBBLE ZONES:


Some of the most severe drilling problems occur from foothill rubble zones in the Blackstone, Wapiabi, Brazeau, Lea Park and Fort St. John or Fernie Groups of Western Canada. The result of these formations being forced up along fault lines is high formation dip angles, fractured, crushed and stressed sections of shale that are sensitive to any form of physical disturbance. Many operators use Invert or Inhibitive Potassium Sulfate / PHPA Polymer or Polyglycol muds to drill these intervals, which will provide the greatest degree of borehole stability. Sloughing shale can still occur using these muds. Listed below is a method used to drill a rubble zone with an Invert mud. Success of this method is totally dependent on rig crew awareness of the problem, its symptoms and how to combat it. a) Maintain constant rheological properties and use the solids control equipment effectively to keep a stable, uniform, low solids drilling fluid. The activity of the water phase should be no higher than 0.75 prior to drilling the rubble zone. b) On the last trip out of the hole prior to penetrating the zone remove all stabilization equipment (if any), and add jars to the string. c) Once the rubble zone has been penetrated, trip time should be kept at a 30 sec./stand minimum to reduce surge and swab pressures, which can rapidly, break down this formation.

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d) While drilling the rubble, watch closely for the following symptoms: -

increase in standpipe pressure torque increase tight connections fill on connections sudden drilling break indicating rubble or overpressured section.

If any one or more of the above symptoms occurs while drilling in the rubble zone, pick up the string and make a five stand dummy trip, noting the amount of reaming and fill going back to bottom. In any case, do not drill more than 2 metres into any rubble zone without coming off bottom and ensuring the hole is clean before continuing. If little or no fill is on bottom, then continue this procedure. Large chunks of shale must be broken up before the drilling fluid will carry them to surface. e) If hole conditions continue to deteriorate, weighting the mud system should be considered. A leak-off test may be performed prior to weighting to determine maximum weight which may be employed without losing circulation. f) Mud weight alone may not solve the problem. Mud properties must be closely monitored to ensure effective cleaning. The activity of various rubble zones in the foothills may be as low as 0.40. If the sloughing is severe, consideration should be given to increasing the activity of the water phase with Envirofloc (Calcium Nitrate) and/or Calcium Chloride. Watch returns at the shaker while tripping and reaming. It may be necessary to pump "high viscosity pills" periodically to clean the hole. The above techniques should allow effective drilling of the Cretaceous shales and continue to intermediate casing point with a minimum of problems.

5.3.2

SHALE HYDRATION AND DISPERSION:


Shale is a mixture of many minerals, although clay minerals predominate. The clay minerals are usually from the following groups, Montmorillonite (Smectite), Kaolinite, Illite, Chlorite or mixed layer clays. It is the clay components that are responsible for the majority of hole problems. a) Hydration: These clays have the ability to absorb water; Smectite being the highest. Water absorbed by the shale will increase the internal stress within the rock and reduce the strength, causing an unstable wellbore. When a large hydration force is present, the shale is capable of absorbing an enormous volume of water. The shale, being confined to overburden stresses, can relieve the increased internal stresses only by expanding (hydrating), which leads to sloughing or heaving shale conditions. b) Dispersion: An important cause of shale problems and a problem that should be diagnosed separately is the dispersion of shale cuttings. Dispersion refers to a continuous and rapid disintegration of the shale surface upon contact with a water base fluid. Dispersion and the hydration of shales are not directly related, however the degree of dispersion tends to reflect the amount of clay capable of swelling.

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The effects of dispersion on the wellbore are often difficult to distinguish from those of swelling and sloughing. Uncontrolled dispersion can lead to an excessive buildup of fine, low gravity solids. Often this situation cannot be remedied with solids control equipment alone and dilution is necessary.

SHALE CLASSIFICATION Class

Characteristics

Clay Content

1 2

Soft, high dispersion Soft, fairly high in dispersion

3

Medium hard, moderate dispersion, sloughing tendencies Hard, little dispersion, sloughing tendencies Very hard, brittle, no significant dispersion, caving tendencies

Higher in Montmorillionite, some Illite Fairly high in Montmorillionite, high in Illite High in interlayered clays, high in Illite, Chlorite Moderate Illite, moderate Chlorite High in Illite, moderate Chlorite

4 5

EXAMPLES OF PROBLEM SHALES Clay Content (Density Percent) Class 1 2 3 4 5

Montmorillonite

Illite

Interlayed

Chlorite

40.4 25.4 -

5.5 42.0 35.0 14.8 48.3

15.0 -

6.7 15.0 3.2 8.3

c) Inhibitive Muds: Generally, inhibitive muds have been utilized to maintain wellbore stability from shale hydration and/or dispersion. The term "inhibitive" refers to minimizing the swelling or dispersion tendencies of a shale. This has been accomplished in Western Canada, primarily with the use of Potassium, Ammonium, or Oil-Base muds. KCl (Potash) or Potassium Sulfate provides a source of Potassium ions, and DAP or Ammonium Sulfate provides a source of Ammonium ions, which act rapidly to slow down the hydration of drilled solids. A Polyacrylamide PHPA Polymer (Alcomer 110RD or 60RD ) is a slower reacting inhibitive agent that largely stops the hydration and dispersion, by forming a protective encapsulating film around the clay particles. This film seals off the particle from further contact with water. Invert emulsion muds provide the maximum inhibition by exhibiting an all oil filtrate and balancing the activity of the shale.

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d) Blacknight Mud System: 1. The Blacknite product in mud systems in a concentration of 2-3% by volume was designed to allow maximum bore hole stability in an environmental friendly water base mud system. 2. The Blacknite product has the ability to bond to the shales and prevent water from penetrating. This is achieved from the Glycol in the product, and also due to the fine particle size distribution of the Gilsonite products. The particle size distribution of the Gilsonite seals the micro fractures and does not allow the fluid or the solids into the formation. Blacknight stabilizes the borehole as it attaches chemically to unsatisfied positive charges of the clay platelets. 3. The Blacknite product blends to produce a drilling fluid with the lowest HT-HP fluid loss and the tightest and thinnest filter cake possible. As the bottom hole temperature increases. The Gilsonites softens for a lower HT-HP fluid loss and a tighter filter cake. 4. The Blacknite mud system is easy to maintain and keep the mud properties in line. There are no Biocides or defoamers required in the Blacknite mud system, as Polymers are kept to a minimum, and the mud system does not tend to foam. 5. The Blacknite mud system is compatible with all salts and can be run in a Potassium or Calcium based mud system for added inhibition. 6. The Blacknite mud system can easily be dispersed, and allow the gas units to be kept to a minimum. With no foam or gas trapped in the mud system, there is no problem running solids or mixing equipment. 7. When drilling deep problem wells in the foothills, it is imperative that the hole and tank volumes are consistent to allow proper well control procedures.

5.4

COAL


Drilling deeply buried coal seams can result in expensive and lengthy fishing or sidetracking operations. Early reaction to a drilling break, experience on the brake handle, a good hole cleaning mud with pump rates that ensure laminar flow and moderate annular pressure losses, a relatively slick drill string, minimum surge and swabbing action, and a lot of patience are the keys to drilling coal successfully. Deeply buried coal seams react under compression due to overburden pressure much readily than do shales. When unexpected coal seams are drilled, the coal stress relieves and can explode into the wellbore in the form of chunks or slivers, and unless reacted upon immediately, a stuck drill string will often result. Take extreme caution in drilling coal. In wildcat areas, it is difficult to catch drilling breaks of less than 0.5 metres, although in most of our areas, the approximately depth of coal seams is usually known and anticipated. Suspect any abrupt drilling break, as coal seams until proven otherwise; do not use an automatic driller. The best procedure is to drill into the seam no more than 0.5 metres, and circulate a sample to surface to verify whether or not it is a coal section. Ensure the mud has enough carrying capacity to clean the hole. Shallow coal is more lignite in nature, and will go into solution in a water base mud, and possibly lower the viscosity. Coal will not affect the viscosity of an Invert Mud.

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Never pull out of coal seam without rotating. Work the pipe up and down, rotating steadily to crush the coal. Watch the shaker closely to observe the type of returns and whether the coal is continuing to come over the shaker. Do not open too much coal until the annulus is clean. Check the viscosity at the flowline and suction regularly; ensure it is high enough to clean the hole. Patience is the key to staying out of trouble.

5.5

FOAMING


A small amount of foaming occurs in most drilling muds. Foaming occurs due to high interfacial surface tension phenomena or mechanical air entrapment. Most foaming occurs on the surface and normally does not adversely affect the mud. If the foam or air bubbles become dispersed throughout the mud, the pump may stroke in an erratic manner, which could cause serious mechanical damages. Causes: 1. 2. 3. 4. 5. 6. 7.

Air leak in mud pump The discharges of the desilter/desander or mud hopper can whip air into the mud. High chloride content in mud. Salt water muds have an inherent tendency to foam. Lignosulfonates have a tendency to foam, especially in high concentrations. Over treatment of mud detergents. Air entrapped in drill pipe after tripping. High pressure-low volume formations or swabbing when tripping may cause the mud to become gas cut. 8. Thick mud containing a large amount of drilled solids are particularly susceptible to foaming. 9. Bacteria fermentation of the mud. Effect On Mud Properties: 1. 2. 3. 4. 5.

Viscosity increase Plastic viscosity decrease Yield Point and Gel Strength increase Apparent solids increase Mud will have a "fluffy" appearance.

Treatment: 1. The mud has to be thinned in order to permit effective removal and prevent a build-up of foam. Lower the viscosity, YP and in particular the Gel Strengths with dispersants (Desco CF, Alcomer 74 or 72L, etc.) or Lignite as required to allow the foam to dissipate. 2. Alcohol base defoamers (Defoamer Silicone, XL Defoamer, Foam Buster) or Aluminum Sterate (oil soluble only; mix with diesel oil) may be added directly into the suction tank. 3. Avoid air leaks in pumps and suctions. 4. Prevent whipping air into mud. Submerge all surface guns, hopper and solids control equipment discharges. 5. "Roll" the tanks with the submerged guns to allow the air or gas bubbles to escape into the atmosphere. 6. If a wash gun is available, spray the surface of the mud with a fine spray of diesel or water.

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5.6

BARITE PLUG


A very critical situation can arise when a well begins kicking and losing circulation at the same time. Increasing the mud weight to control the pressure zone will only complicate the problem of lost circulation. When the pressure zone lies below the thief zone, Barite plugging can be used to control the well. An extremely heavy, high water-loss slurry is required for this technique. Barite settling and deposition will form a solid plug on the open hole, weighting down and sealing off the pressure zone. In addition, the high fluid loss results in rapid dehydration, bridging the hole and further aiding in sealing off the pressured zone. Once a Barite plug is in place, normal steps for regaining circulation may be taken with relative safety. Barite plugs weighing from 2150 to 2875 kg/m3 may be prepared using Barite, fresh water, phosphate (SAPP) and Caustic Soda. No viscosifiers are used, and care must be taken to prevent contamination of the slurry with mud, because rapid settling of the Barite once it is spotted is a necessity. The plug should be set as close to bottom as possible and pumped rapidly. The drill pipe then should be withdrawn to avoid sticking. Coarse grind Barite is not recommended, because it will not stay suspended long enough to spot. Brackish or saltwater should not be used because the settling rate is reduced drastically. A cementing truck must be used to mix the slurry. Barite is mixed with fresh water containing 2.0 kg/m3 phosphate (SAPP) and 0.75 kg/m3 Caustic Soda. The lines from the cementing truck can be connected directly to the drill pipe through a plug valve. To minimize the possibility of stuck pipe, the derrickman should be in the derrick and the elevators ready to come out of the hole immediately after pumping is completed. Barite Plug Formulation: Material for 1m3

Density (kg/m3) 2150 2280 2400 2520 2640 2750 2875

Water (m3) 0.65 0.61 0.57 0.57 0.53 0.49 0.41

Caustic Soda (kg/m3) 0.75 0.75 0.75 0.75 0.75 0.75 0.75

SAPP (kg/m3) 2.0 2.0 2.0 2.0 2.0 2.0 2.0

Barite (kg) 1515 1670 1830 1985 2150 2300 2465

Procedures for Settling Plug: 1. Determine how many meters of plug in the open hole is desired (150 metres is usually adequate). 2. Choose a slurry weight (higher weights are preferable). 3. Calculate cubic meters of slurry required and add 0.5 m 3. 4. Calculate amounts of Barite, Phosphates, Caustic Soda and fresh water needed. 5. Calculate the length of the Barite plug with the drill pipe and collars in the hole. Calculate the drill pipe capacity above the top of the plug (this is the mud needed to displace the slurry).

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6. Mix the slurry and pump it down the drill pipe (spot close to bottom and be ready to come out quickly.) 7. Under displace by 0.5 m3.with mud. 8. Immediately pull up above the plug. Circulate until gas dissipates. Proceed with normal operations.

5.7

CORROSION


INSTRUCTIONS FOR USING DRILLPIPE CORROSION COUPONS a) STORAGE, HANDLING AND PREPARATION OF COUPONS: Drillpipe Corrosion Rings are made from CD seamless mechanical tubing, which is similar in composition to drillpipe. The coupons are machined, and the surface is probably more sensitive to corrosion than the drillpipe surface. Corrosion Rings are used to study the corrosive effects of drilling fluids on the drillstring, to determine the need for a corrosion inhibitor treating program, and to evaluate the effectiveness of a treating program for the prevention or control of corrosion. Pre-weighted coupons are available to fit all commonly used API drillpipe tool joints, and different part numbers identifies the sizes. Rings should be stored in a dry place, away from dampness, humidity and containers of corrosive chemicals. If this is not possible, the storage life will be reduced. Each ring is wrapped with an impregnated paper, which should preserve the coupon for about 2 years under normal conditions. Rings should not be removed from their packing until immediately before use, and it is not recommended to touch the surface with the fingers, as this is likely to provoke localized corrosion due to contamination from the skin, and brown fingerprints will develop on the coupon. The use of gloves, when handling the rings is recommended. The drillpipe Corrosion Rings may be rinsed with gasoline before use, in order to remove any vapor phase inhibitor from the surface. However, this need not be regarded as essential. b) INSTALLATION OF CORROSION RINGS IN THE DRILLSTRING The normal method for installing a drillpipe Corrosion Ring is to place it in a tool joint prior to going back in the hole after a trip. The coupons are so designed that they will not interfere with the normal process of making up the tool joint. The normal position in the drillstring is in one of the tool joints immediately above the collars, so that the ring will be exposed as near as possible to the bit. Additional rings may be installed as desired, near the surface and (for deep holes), or at intermediate points in the drillstring. c) EXPOSURE TIME The exposure time is not critical, so there is no need for any interference with the normal progress of the drilling operations. However, for good results, it is recommended to expose the coupons for an absolute minimum of 50-75 hours drilling time. Best results have been obtained with 100-125 hours drilling time. The coupons may be left in the string for several trips, if necessary.

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d) RECORDING DRILLING FLUID PROPERTIES The drilling fluid properties should be recorded at the beginning and end of the exposure period, and the data should be written in the appropriate space on the coupon envelope. Any bit or drillstring failures, which occur during the coupon exposure period, should be described, and the description should be sent with the ring for examination. The description should include the number and type of failures, such as a wash out, twist off, and/or lost cone from bit. e) REMOVAL AND INITIAL EXAMINATION OF COUPON On removal of the coupon from the tool joint, it should be examined before cleaning, and the appearance should be noted. Particular attention should be paid to the color of any deposits other than drilling fluid residues, including the color of any spots or patches on the coupon. Any visible cracks, deformities or mechanical damage should be recorded. The coupon may be quickly rinsed and wiped with a rag to remove any drilling fluid and dried completely with a paper towel to prevent the occurrence of any further attack upon the coupon before it reaches the laboratory. The coupon should then be wrapped in paper or paper towel, replaced in its envelope with some Silica Gel if handy, and sent for examination. f)

CORROSION COUPONS - MUD ENGINEERS ON SITE MONITORING: Equipment Needed: 1. 2. 3. 4. *5. *6. *7. *8.

Use of geologist's microscope, or magnifying glass Iron Sulfide Detecting Solution HCl (Hydrochloric Acid) Magnet 2 Test Tubes Distilled water Sulfate Indicator Solution Calcium Indicator Solution

*Optional - Only if there are high concentrations (or build ups) of scale type deposits on the ring. A visual inspection with the aid of the geologist's microscope will tell whether the rate is severe enough to cause concern. A little practice will be necessary, but done. Besides estimating the severity of corrosion, it is important to identify the products and thereby determine the corrosive agents. With this information, possible to adjust the corrosion control program.

corrosion it can be corrosion it is now

The following steps are suggested for on site analysis: 1. Run the ring for 75 to 150 hours. They must be exposed this long to reach a stabilized corrosion rate. 2. When the ring is removed from the drillpipe, wash it carefully in soapy water to remove traces of drilling mud, then dry thoroughly.

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3. Place the ring under the geologist's microscope where there is a good light and add a drop of the Iron Sulfide Detecting Solution to an area where there is a significant amount of corrosion products. This test solution is Sodium Arsenite in a strong acid solution. This step will tell two things: a. If Iron Sulfide is present on the surface of the ring, a bright yellow precipitate is formed. There should be no mistaking this because the precipitate is a brilliant yellow and may appear to have a slightly “limey” tinge. Quite often H2S gas is evolved which can be easily detected by its odor. b. A significant amount of odorless gas will probably be Carbon Dioxide, which is generated by the reaction of the acid with a Carbonate compound. The Carbonate compound could be Iron Carbonate or Calcium Carbonate. Iron Carbonate is generally black or at least very dark in color; when it reacts with acid the reaction is fairly slow. Very small bubbles form at the surface of the metal and grow as they rise through the acid. This can be easily seen through a 12-power microscope. Calcium Carbonate (scale) reacts much more rapidly with the acid, also giving of CO2 gas; the reaction appears as a fizzing or foaming. Calcium Carbonate will be fairly light in color, in some cases almost white. The presence of Iron Carbonate indicates CO2 corrosion, while Calcium Carbonate is scale. 4. The next step is to scrape a small portion of the corrosion products onto a filter paper. Pass a small magnet below and against the paper; if the material follows the magnet when the latter is moved, the material is iron oxide or magnetite. Its presence is a clear indication of oxygen corrosion. *5. Do not throw away the material scraped from the ring. This should be transferred to a clean test tube with about 4 cm3 of distilled water and shaken thoroughly. This mixture will probably be cloudy, so it will be necessary to pass it through a filter paper. Put about 2 cm3 of the filtered water into a test tube and add 2 drops of Sulfate Indicator Solution. If the water turns cloudy or milky from the white precipitate, Calcium is present. Positive tests for either Calcium or Sulfate indicate the presence of scale. It might be pointed out that if Sulfate is present, it is almost certain that Calcium will be present. *

Optional - follow throughout if needed according to amount of deposit build up.

6. Should the mud engineer's report indicate a low alkalinity; i.e. the Pf low in relation to the Mf, it may be possible to actually run a qualitative test to detect the presence of CO 2 in the drilling mud. Simply mix some Lime in a water sample (2 or 3 grams in 100 cm 3 water) and then filter off some of this water through the filter press. Put 3 or 4 cm 3 of mud filtrate in a clean test tube and add 2 drops of the Lime water to the sample. A faintly cloudy appearance will be discernible at concentrations as low as 50 mg/L of CO2. Although not conclusive, recent experience in Northeastern British Columbia indicates that this amount of Carbon Dioxide can be damaging. In any case, any detectable amount of CO2 should be a matter of concern and reason enough to take immediate corrective control measures.

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H. OR - USE THIS OTHER METHOD STARTING AFTER STEP 2: 3. A sample of the deposits may be scrapped off, without scratching the coupon, and placed in a titrating dish, or on a ceramic spot test plate. The following tests may be carried out: a. For Iron Sulfide: Appearance - black, blackens fingers and is hard to wash off. Generally soft, and may be “slimy”, but may also occur on the back of scaly deposits as harder, thin layers. Occurrence on the back of scaly deposits may indicate that sulfate reducing bacteria is present. Action of HCl (Hydrochloric Acid) - effervescence. Hydrogen sulfide evolved. Identify Hydrogen Sulfide gas by the smell (rotten eggs), or by placing a Hydrogen Sulfide test paper (from Hach Hydrogen Sulfide detection kit) over the gas being evolved. If the paper turns brown or black, Hydrogen Sulfide was present. Iron Sulfide Detecting Solution, can be used for positive identification of Iron Sulfide. One drop of the solution is placed on the deposit to be tested. Effervescence will occur, and Hydrogen Sulfide will be evolved if the deposit contains Iron Sulfide. In addition, a bright canary yellow precipitate will form on the surface of the deposit, which identifies the deposit as being or containing Iron Sulfide. b. For Iron Oxide: Appearance - can be yellowish or brownish red, or brown or black. The brighter and lighter deposits may be softer, while the black deposits may be scaly. The deposits may consist of combinations of different colored oxides. Action of HCl - dissolves to form a yellow solution. Magnetite dissolves with difficulty. Use of magnet - Black scaly deposits, if attracted by a magnet, contain magnetite or magnetic iron oxide, which consists mainly of Ferric Oxide. Ferrous Oxides, Hydroxides and Hydrated Oxides tend to be softer and lighter in color, and are not attracted by a magnet. Action or Iron Sulfide detecting solution - dissolves to form yellow solution. No canary yellow precipitate. Record all information on corrosion report. Show Company man results. Using the system below, you can assess part of the problem and increase treatment rates as needed. Never decrease treatment until rings are weighed in the laboratory and results forwarded to the rig. FIELD ASSESSMENT (POINT SYSTEM): (A)

1 2 3 4 5

Generalized Generalized with pits Localized Localized with pits Pitted

(B)

Add (A) and (B) together.

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1 2. 3 4 5

80% Bright Metal 60% Bright Metal 40% Bright Metal 20% Bright Metal 10% Bright Metal

Total Points 2 3 4 5 6

Assessment Negligible (Good Protection) Satisfactory Protection Poor Protection Moderate Corrosion High Corrosion

7

Severe Corrosion

8

Severe Corrosion

9

Severe Corrosion

10

Severe Corrosion

Treatment No Change No Change Increase Residuals Increase Residuals Re-check Residuals and Contact Corrosion Engineer Re-check Residuals and Contact Corrosion Engineer Re-check Residuals and Contact Corrosion Engineer Re-check Residuals and Contact Corrosion Engineer Re-check Residuals and Contact Corrosion Engineer

With these steps, one should be able to control corrosion within 1 lb/ft2/yr (25 mils/yr.).

CLASSIFICATION OF SEVERITY OF CORROSION

CORROSION RATE CLASSIFICATION CATEGORY LOW (Acceptable) MODERATE HIGH SEVERE

CORROSION RATE RANGE (mils/yr. – mpy) 0 to 50 50 to 100 100-150 150 and above


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TABLE OF CONTENTS – CHAPTER 6 Chapter 6

Solids Control

Return to Glossary


TOPICS 6.1 6.2 6.3 6.4

6.5

6.6

6.7 6.8 6.9

6.10

6.11

6.12

6.13

6.14

PAGE

ABSTRACT INTRODUCTION – SOLIDS CONTROL & RELATED EQUIPMENT PARTICLE SIZE AND CUT POINT 6.3.1 CUT POINT SEPARATION BY SCREENING 6.4.1 SCREEN SURFACES 6.4.2 SCREEN CLOTH 6.4.3 OPENING SIZE 6.4.4 PERCENT OPEN AREA 6.4.5 SHAPE OF OPENING 6.4.6 EQUIVALENT SCREEN MESH 6.4.7 SCREEN PLUGGING AND BLINDING 6.4.8 SCREEN CAPACITY 6.4.9 THREE-DIMENSIONAL SCREEN PANELS 6.4.10 STANDARDIZATION SHALE SHAKERS 6.5.1 RIG SHAKERS 6.5.2 FINE SCREEN SHAKERS 6.5.3 SCREEN ORIENTATION AND SHAPE 6.5.4 SCREEN TENSIONING MECHANISM 6.5.5 VIBRATOR MECHANISMS 6.5.6 MAINTENANCE 6.5.7 GENERAL GUIDELINES MUD CLEANERS AND MUD CONDITIONERS 6.6.1 APPLICATIONS 6.6.2 INSTALLATION 6.6.3 GENERAL GUIDELINES 6.6.4 MAINTENANCE SEPARATION BY SETTLING AND CENTRFIGUAL FORCE SAND TRAPS HYDROCYCLONES 6.9.1 HYDROCYCLONE CUT POINT 6.9.2 ROPE DISCHARGE DESANDERS 6.10.1 INSTALLATION 6.10.2 MAINTENANCE DESILTERS 6.11.1 INSTALLATION 6.11.2 GUIDELINES 6.11.3 MAINTENANCE DECANTING CENTRIFUGE 6.12.1 SEPARATION PROCESS 6.12.2 UNWEIGHTED MUD APPLICATIONS 6.12.3 WEIGHTED OIL-BASE MUD APPLICATIONS 6.12.4 OPERATING PROCEDURES AUXILLARY EQUIPMENT 6.13.1 AGITATION / MIXING EQUIPMENT 6.13.2 DEGASSERS 6.13.3 DRYING SHAKERS BASIC ARRANGEMENT RULES

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1 2 3 4 6 6 7 8 8 9 9 10 10 11 11 12 13 14 15 16 16 17 17 17 19 20 20 21 21 22 24 25 25 25 26 27 27 28 28 28 29 29 30 32 32 32 32 33 35 36

CHAPTER 6 SOLIDS CONTROL 6.1

ABSTRACT


Of all the problems that could conceivably occur during the drilling of a well, mud contamination from drilled solids is a certainty. The volume and type of solids present in drilling mud exert a considerable influence over mud treating costs, drilling rates, hydraulics, and the possibility of differential sticking, kicks, and lost returns. Solids control is one of the most important phases of mud control – it is a constant issue every day, on every well. If drilled solids can be removed mechanically, it is almost always less expensive than trying to combat them with chemicals and dilution. The primary reason for using mechanical solids control equipment is to remove unwanted drilled solids particles from the mud in order to prevent drilling problems and reduce mud and waste costs, thereby reducing overall drilling costs. The benefits of solid’s removal by mechanical separation can best be seen in terms of two outcomes: 1) reduced total mud solids and 2) reduced dilution requirements. The presence of large amounts of drilled solids in a drilling mud usually spells trouble for the drilling operation. These solids adversely affect the performance characteristics of the mud and can lead to a multitude of costly hole problems. Drilled solids decrease the life of a mud pump’s parts and thus, can decrease drilling efficiency due to lost time for pump repairs. Continued re-circulation of drilled solids produces serious mud problems because re-circulated solids will gradually be reduced in size. The smaller the solids become, the more they negatively influence mud properties and hydraulic performance. The greatest impact of the solids is seen in reduced ROP (rate of penetration). The higher the drilled solids content the lower the penetration rate. If mud solids are not properly controlled, the mud’s density can increase above its desired weight, and the mud can get so thick that it becomes extremely difficult, or even impossible to pump. Since the earliest days of the oilfield, drillers have been trying to combat high solids content through the use of settling pits. However, some drilled solids are so finely ground that they tend to remain in suspension. This results in increased mud viscosity and Gel Strength, which, in turn results in larger particles also remaining in suspension. Thus, the approach of removing cuttings through settling alone is of limited practical value. Solids control equipment was developed in order to more effectively remove unwanted solids from drilling mud. A variety of devices (which are discussed later in this chapter) are available which mechanically separate the solids particles from the liquid phase of the mud. Thus the driller, depending on the particular situation and equipment used, can regulate to a finer degree the amount and size of solids particles that are removed or maintained in any given drilling mud. Such control of mud solids through mechanical separation allows the mud to perform its drilling – related functions, and avoids the down hole problems caused by excessive solids contamination. Effective solids control permits viscosity and density to be kept within desired levels, dramatically

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increase the life of pump parts an drill bits, and promotes faster penetration – all of which decrease the time and expense of drilling.

6.2

INTRODUCTION – SOLIDS CONTROL & RELATED EQUIPMENT Return to Table of Contents

The goal of modern solids control systems is to reduce overall well costs by prompt, efficient removal of drilled solids while minimizing the loss of liquids. Since the size of drilled solids varies greatly – from cuttings larger than one inch in diameter to sub-micron size – several types of equipment may be used depending upon the specific situation. The fundamental purpose for solids removal equipment is just that – remove drilled solids. The end result is reduced mud and waste disposal costs. To reach this goal, each piece of equipment will remove a portion of the solids, either by screening or centrifugal force. Each type of equipment is designed to economically separate particles of a particular size range from the liquid. Also to operate effectively, each type of equipment must be sized, installed, operated, and maintained properly. The efficiency of the solids control system can be evaluated by comparing the final volume of mud accumulated while using the equipment, to the volume of mud that would result if drilled solids were controlled only by dilution. The overall results of solids removal can be monitored by the use of flow meters to determine the actual mud volume built. The efficiency of solids removal equipment and/or systems used can be evaluated in two ways: 1) Efficiency of drilled solids removal, 2) Efficiency of liquid conservation. The greater percentage of drilled solids removed, the higher the removal efficiency. The higher the solids fraction of the waste stream, the better. Both aspects should be considered. For example, a desilter usually does well at removing solids, but at the cost of significant losses of liquid; sometimes 80% of the volume of the waste stream will be liquid. By contrast, a properly operating shale shaker or centrifuge typically removes 1 barrel or less of mud with each barrel of solids. Most remaining equipment delivers a lesser degree of dryness than do the shakers or centrifuges. Most solids control systems include several pieces of equipment connected in series. Each stage of processing is partly dependent upon the previous equipment functioning correctly so as to allow the next stage to perform its role. Should one piece of equipment fail, the equipment downstream will soon lose efficiency or fail completely. The first piece of equipment used to separate the solids from the mud is usually a vibrating screen or series of screens. The cuttings that are larger than the mesh openings are removed by the screen but carry an adhered film of mud. The screen mesh should be sized to prevent excessive losses of whole mud over the end screen. The second step is to remove the sand-sized, silt sized and larger clay particles that were not removed in the shakers by using hydrocyclones. Hydrocyclones with a cone diameter of 6 to 12 inches are called desanders, and hydrocyclones with a cone diameter of less than 6 inches are called desilters. These units should normally be sized to process 125% of the maximum flow rate used to drill.

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Sometimes a screen is used below a hydrocyclone to “dry-out” the cone’s discharge to minimize the loss of fluid. The hydrocyclone and vibrating screen device is called a mud cleaner or mud conditioner. If a location must be “sumpless”, then the screens are essential to minimize the liquid waste volume. The final step may be to remove the ultrafine silt and clay-sized solids with the use of a decanting centrifuge. On a weighted mud, two centrifuges may be used in series: the first to salvage Barite, the second to remove fine solids and reclaim the valuable liquid phase.

6.3

PARTICLE SIZE AND CUT POINT


Modern drilling rigs may be equipped with many different types of mechanical solids removal devices depending on the application and requirements of a particular project. Each device has a specific function in the solids control process. Equipment commonly utilized and the effective removal range for each are listed in Figure 6-1. Figure 6-1 Particle Diameter and Ideal Equipment Placement

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6.3.1 CUT POINT


Notice the removal range, or Cut Point, is given as a range of the particle size removed. Mechanical solids control equipment classifies particles based on size, shape, and density. It is typical to refer to particles as being either larger than the cut point of a device (oversize), or smaller than the cut point (undersize). Figure 6-2 shows a typical cut point curve. The cut point curve represents the amount of solids of a given size that will be classified as either oversize or undersize. Particles to the right of the cut point curve, in the area labeled “A”, represent the removed, oversize solids. Particles to the left of the curve, in the area labeled “B”, represent the undersize solids returned with the whole mud. Particular interest is given to three points along the cut point curve. The D50, or median cut point, is the point where 50% of a certain size of solids in the feed stream will be classified as oversize, and 50% as undersize. The D16 and D84 are the points where 16% and 84%, respectively, of the solids in the feed stream will be classified as oversize. These two points are statistically significant because they are one standard deviation from the D50 in a normal distribution. An “ideal” classifier (the dashed line) would show very little difference between the D50, D16 and D84. Separation Efficiency is a measure of the D50 size relative to the number of undersize particles that are removed, or oversize particles that are not removed. The higher the separation efficiency, the lower the false classification. An example will assist in understanding this concept. Figure 6-2 Typical Cut Point Curve

Figure 6-3 shows the cut point curves for two screens, each with the same D50. Curve No. 1 is almost vertical with a small tail at each end. This results in a very sharp, distinct cut point. Almost all particles larger than the cut point are rejected, with very few undersize solids.

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Curve No. 2 is an S-shaped curve with a large tail at each end. Even though the D50 is the same as for Curve No. 1, the D16 and D84 are very different. Many solids larger than the D50 are returned with the undersize solids and many solids smaller than the D50 are discarded with the oversize solids. If curves number 1 and 2 in Figure 6-3 illustrate typical removal gradients for two different types of oilfield shale shaker screens, we can draw conclusions about separation performance. The area between the curves marked “A” represents solids Screen No. 1 removes and Screen No. 2 returns. Likewise, the area marked “B” represents solids recovered by Screen No. 1, but discarded by Screen No. 2. Figure 6-3 Separation Curve

This is not to say that Screen no. 1 is “better” than Screen No. 2, or vice versa; it simply illustrates that two devices with similar “cut point” (as measured by the D50, alone) may perform very differently. As an example, consider solids removal from a weighted drilling fluid using vibrating screens. An effective solids control program for a weighted mud should remove as many undesirable, sand-sized solids as practical, while retaining most of the desirable, silt sized Barite particles. Referring back to Figure 6-3, Screen No. 2 would return all the sand in area “A” that Screen No. 1 would catch, and Screen No. 2 would remove the silt size material in area “B” (including all weighting material) that Screen No. 1 would recover. Therefore, in a weighted mud, Screen No. 2 would not perform as well as Screen No. 1. Further, if the area to the right of both curves (representing total mass solids removal) were calculated, Screen No. 1 could prove superior in terms of mass solids removal. As shown by this example, it is important to view “cut point” as a continuous curve, rather than a single point. This concept is equally true with screens, hydrocyclones, centrifuges, or any other separation equipment – the relative slope and shape of the cut point curve are more important than a single point on the curve.

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6.4 SEPARATION BY SCREENING


One method of removing solids from drilling mud is to pass the mud onto the surface of a vibrating screen. Particles smaller than the openings in the screen pass through the holes of the screen along with the liquid phase of the mud. Particles too large to pass through the screen are thereby separated from the mud for disposal. Basically, a screen acts as a “go-no-go gauge”: either a particle is small enough to pass through the screen opening or it is not. The purpose of vibrating the screen in solids control equipment is to transport the cuttings off the screen and increase the liquid handling capacity of the screen. This vibrating action causes rapid separation of whole mud from oversized solids, reducing the amount of mud lost with the solids. For maximum efficiency, the solids on the screen surface must travel in a predetermined patternspiral, elliptical, orbital or linear motion – in order to increase particle separation efficiency and reduce blockage of the screen openings. The combined effect of the vibration and the screen surfaces result in the separation and removal of oversized particles from drilling mud.

6.4.1 SCREEN SURFACES


Screening surfaces used in solids control equipment are generally made of woven wire screen cloth, in many different sizes and shapes. The following characteristics of screen cloth are important in solids control applications. Screens may be constructed with one or more layers. Non-layered screens have a single layer, fine mesh, screen cloth (reinforced by coarser backing cloth) mounted on a screen panel. These screens will have openings that are regular in size and shape. Layered screens have two or more fine mesh screen cloths, usually of different mesh (reinforced by coarser backing cloth), mounted on a screen panel. These screens will have openings that vary greatly in size and shape. To increase screen life, especially in the 120200 mesh range, manufacturers have incorporated two design changes. 1) A coarse backing screen to support fine meshes, and 2) Pre-tensioned screen panels. The most important advance has been the development of pre-tensioned screen panels. Similar panels have been used on mud cleaners since their introduction, but earlier shakers did not possess the engineering design to allow their use successfully. With the advent of modern, linear-motion shakers, pre-tensioned screen panels have extended screen life and justified the use of 200-mesh screens at the flow line. The panels consist of a fine screen layer and a coarse backing cloth layer bonded to a support grid (Figure 64). The screen cloths are pulled tight, or tensioned, in both directions during the fabrication process for proper tension on every screen. The pre-tensioned panel is then held in place in the bed of the shaker.

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Figure 6-4 Pre-tensioned Screen Today, fine screens may be reinforced with one or more coarse backing screens. The cloth may also be bonded to a thin, perforated metal sheet. This extra backing protects the fine screen from being damaged and provides additional support for heavy solids loads. The screens equipped with a perforated plate may be available with several size options for the perforation to allow improved performance for a given situation. Most manufacturers limit themselves to one support grid opening size to reduce inventory and production costs. The opening size is typically 1” for maximum mechanical support. Brandt/EPITM provides screen panels with a variety of openings to allow rig personnel to choose the desired mechanical support and total open area (translating to more liquid flow), depending on the application. Mesh is defined as the number of openings per linear inch. Mesh can be measured by starting at the center of one wire and counting the number of openings to a point one-inch away. Figure 6-5 shows a sample 8-mesh screen. A screen counter is useful in determining screen mesh (see Figure 6-6).

6.4.2 SCREEN CLOTH


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There are several types of wire cloth used in the manufacture of oilfield screens. The most common of these are Market Grade and Tensile Bolting Cloth. Both of these are square mesh weaves, differing in the diameter of wire used in their construction. Market grade cloths use larger diameter wires and are more resistant to abrasion and premature wear. Tensile bolting cloths use smaller diameter wire and have a higher Conductance. Since screen selection is a compromise between screen life, liquid capacity, and particle separation, both types are in wide use.

6.4.3 OPENING SIZE


Size of Opening is the distance between wires in the screen cloth and is usually measured in fractions of an inch or microns. Figure 6-7 shows a screen with a ½ inch opening.

Figure 6-7 One-half Inch Opening Screens of the same mesh may have different sized openings depending on the diameter of the wire used to weave the screen cloth. Smaller diameter wire results in larger screen openings, with larger particles passing through the screen. The larger the diameter of the wire, the smaller the particles that will pass through the screen. Remember, it’s the size of the openings in a screen, not the mesh count, that determines the size of the particles separated by the screen. Also, normally the larger the diameter of the wire used in the weaving process, the longer the screen cloth will last.

6.4.4 PERCENT OPEN AREA


Percent open area is the amount of the screen surface that is not blocked by wire. The greater the wire diameter of a given mesh screen, the less open space between the wires. For example, a 4 mesh screen made of thin wire has a greater percent of open area than a 4 mesh screen made of thick wire (see Figure 6-8).

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Figure 6-8 Percent of Open Area The higher the percent of open area of a screen, the greater its theoretical throughput. Open area can be increased for a given mesh by using smaller diameter wire, but at the sacrifice of screen life. The choice of any particular screen cloth therefore involves a compromise between throughput and screen life. Calculating the percent open area for layered screens is difficult and inaccurate. This is due to the random and wide variety of openings present. Conductance of a screen is an experimental measure of the flow capacity of a screen. The higher the conductance of a screen, the greater its flow capacity.

6.4.5 SHAPE OF OPENING Return to Table of Contents Shape of Opening is determined by the screen’s construction. Screens with the same number of horizontal and vertical wires per inch produce square-shaped openings and are referred to as Square Mesh screens. Screens with a different number of horizontal and vertical wires per inch produce oblong – or rectangular – shaped openings and are referred to as Rectangular (or Oblong) Mesh screens. This is illustrated in Figure 6-9.

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Figure 6-9 Shape of Opening Use of a single number in reference to a screen usually implies square mesh. For example, “20 mesh” usually identifies a screen with 20 openings per inch in either direction. Oblong mesh screens are generally labeled with two numbers. For example, a 60 x 20 screen has 60 openings per inch in one direction and 20 openings per inch in the other direction. It has become common industrial practice to add the two dimensions of an oblong mesh screen and refer to the sum of the two numbers as the mesh of the screen. For example, a 60 x 20 mesh screen is often called an “oblong 80” mesh. This screen has oblong openings measuring 1040 x 193 microns, much larger than the square openings of a “square 80” mesh screen (177 x 177 microns). The “oblong 80” will allow much larger, irregularly shaped particles to pass through its openings than the 80 x 80 square mesh screen.

6.4.6 EQUIVALENT SCREEN MESH


Screen manufacturers now compare different types of screen through charts, such as the one shown in Figure 6-10.

Figure 6-10 Equivalent Screen Sizes The oblong-mesh screens listed in the left-hand column remove similar sized solids as the square-mesh screens listed in the right-handed column. These screens are referred to as “equivalent”. In actual field use, the conductance and screen life of the oblong mesh screens is noticeably higher than the equivalent square mesh screen, but the shape of the cut point curve discussed earlier is not as sharp or distinct. In a similar fashion, a layered screen will often be designated by a single number, e.g. “layered 210” mesh. This implies a screen with openings smaller than a “square 200” mesh screen (74 x 74 microns). However, the actual opening size and shape of a layered screen is a combination of the multiple screen layers and will produce a wide variety of opening sizes and shapes. Therefore, the “ layered 210” mesh screen will remove some solids smaller than 74 microns, but will also allow some particles larger than 74 microns to pass through the screen openings. 6.4.7

SCREEN PLUGGING AND BLINDING

Screen plugging and blinding, while present to some degree on rig shakers fitted with coarser screens, is most frequently encountered on fine screen shakers. If the mesh openings plug with near-size particles or if the openings become coasted over, the throughput capacity of the screen can be drastically reduced and flooding of the screen may occur. Plugging can often be controlled by adjusting the vibratory motion or deck angle, but sometimes requires changing screens to a coarser or finer mesh. A coarser screen should be used only as

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a temporary solution until the particular formation responsible for near-size particle generation is passed. Changing to a finer mesh screen often presents a better, more permanent solution. Solution blinding is caused by sticky particles in viscous mud coating over the screen openings, or by the evaporation of water from dissolved solids or from grease, and requires a screen washdown to cure. This wash-down may simply be a high-pressure water wash, a solvent (in the case of grease, pipe dope or asphalt blinding), or a mild acid soak (in the case of blinding caused by hard water). Stiff brushes should not be used to clean fine screens because of the fragile nature of fine mesh screen cloth. Screen life of fine mesh screens varies widely from design to design, even under the best of conditions because of differences in operating characteristics. Following these general precautions can maximize screen life: • • • • •

6.4.8

Keep screens clean. Handle screen carefully when installing. Keep screens properly tensioned. Do not overload screens. Do not operate shakers dry.

SCREEN CAPACITY

Screen capacity, or the volume of mud that will pass through a screen without flooding, varies widely depending on shaker model and drilling conditions. Drilling rate, mud type, density and viscosity, bit type, formation type, screen mesh – all affect throughput to some degree. Drilling rate affects screen capacity because increases in drilled solids loading reduce the effective screen area available for mud throughput. The mesh of the screen in use is also directly related to shaker capacity because, in general (but not always), the finer a screen’s mesh, the lower its throughput. Increase viscosity, usually associated with an increase in percent solids by volume and/or increase in mud weight, has a markedly adverse effect on screen capacity. As a general rule, for every 10% increase in viscosity, there is a 2-5% decrease in throughput capacity.

Figure 6-11 shows the relationship of mud weight viscosity, and screen mesh on shaker capacity. Figure 6-11 Shaker Capacity vs. Mud Weight, Viscosity, and Screen Mesh Mud type also has an effect on screen capacity. Higher viscosities that may be associated with an oil-base invert emulsion mud, usually results in lower screen throughput than would be possible with a water-base mud of the same mud weight. Some mud components such as synthetic polymers also have an adverse effect on screen capacity. As a result, no fine mesh screen can offer a standard throughput for all operating conditions.

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Due to the many factors involved in drilling conditions, mud characteristics and features of certain models, capacities on fine screen shakers can range from 50 to 800 GPM (190 – 3000 LPM). Multiple units, most commonly dual or triple units, can be used for higher throughput requirements. Cascade shaker arrangements, with scalping shakers installed upstream from the fine screen shakers, can also increase throughput.

6.4.9

THREE-DIMENSIONAL SCREEN PANELS


To increase screen capacity without increasing the size or number of shale shakers, threedimensional screen panels are available. The design of these 3-D, Pinnacle™ shaker screens: • • • •

Provides even distribution of fluid across the screen surface Eliminates unwanted fluid loss near the screen edges Improves dryness of solids discharge Allows the use of finer screens

3-D screen panels increase the usable screen area of a screen panel by corrugating the screen surface. Similar to the surface of a pleated air filter or oil filter, 3-D screen panels are most effective when installed as the submerged, feed-end screen on linear-motion shakers to take full advantage of the additional screen area. Past the fluid end point, a three-dimensional screen tends to “channel” the drilled solids, and increases solids bed depth and the amount of liquid carried off the screen surface. Using a flat screen at the discharge end of the shaker eliminates channeling, increases cuttings dryness, and decreases fluid loss.

6.4.10 STANDARDIZATION


Standardization of screen cloth designations has been recommended by the API committee on Standardization of Drilling Fluid Materials, in API RECOMMENDED PRACTICE 13E (RP13E), THRID EDITION, MAY 1,1993. The purpose for this practice is to provide standards for screen labeling of shale shaker screen cloths. The procedures recommended for labeling allow a direct comparison of separation potential, the ability to pass fluid through a screen, and the amount area available for screening. The API screen labeling includes of the following: 1. Manufacturer’s designation; 2. Separation Potential and 3. Flow Capacity. The Manufacturer’s designation contains the individual company’s procedures for naming their screens. It may include the type of screen panel, composition and other data required by the manufacturer. The API separation potential is reported in the terms of three “Cut” points. The term “Cut” point is not the same as the traditional cut point. The “Cut” point allows a ranking of a screen’s separation potential that can be used to compare screen performance. Three values (D50, D16, and D84) imply the opening sizes and variation in opening size of the screen. Flow capacity is the rate at which a shaker can process mud and solids. Under constant conditions, a shale shaker has a flow capacity that depends upon screen conductance and area. The area available for screening is the net unblocked area, in square feet, available for fluid passage through the screen panel. Conductance defines the ease of passage of a fluid through a piece of wire cloth. Conductance is calculated from the mesh count and wire diameters of the screen. Transmittance is the product of conductance times the panel area.

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These designations give the end user a more accurate assessment of solids removal capability and liquid throughput capacities of competitive screens.

6.5

SHALE SHAKERS


The first line of defense for a properly maintained drilling fluid has been, and will continue to be, the shale shaker. Without proper screening of the drilling fluid during this initial removal step, reduced efficiency and effectiveness of all downstream solids control equipment on the rig is virtually assured. The shale shaker, in various forms, has played a prominent role in oilfield solids control schemes for several decades. Shakers have evolved from small, relatively simple devices capable of running only the coarsest screens to the models of today. Modern, high-performance shakers of today are able to use 100 mesh and finer screens at the flow line in most applications. The evolutionary process has taken us through three distinct eras of shale shaker technology and performance as shown in Figure 6-12. These eras of oilfield screening development may be defined by the types of motion produced by the machines: • Elliptical, “unbalanced” design. • Circular, “balanced” design. • Linear, “straight-line” design. The unbalanced, elliptical motion machines have a downward slop as shown in Figure 6-12, A. This slope is required to properly transport cuttings across the screen and off the discharge end. However, the downward slope reduces fluid retention time and limits the capacity of this design. Optimum screening with these types of shakers is usually in the 30-40 mesh (400-600 micron) range. The next generation of machine, introduced into the oilfield in the late 1960s and early 1970s, produces a balanced, or circular, motion. The consistent, circular vibration allows adequate solids transport with the basket in a flat, horizontal orientation, as shown in Figure 612, B. This design often incorporates multiple decks to split the solids load and to allow finer mesh screens, such as 80-100 square mesh (150 – 180 microns) screens to be utilized.

Figure 6-12 Shale Shakers The newest technology produces linear, or straight-line, motion, Figure 6-12, C. This motion is developed by a pair of eccentric shafts rotating in opposite directions. Linear motion provides superior cuttings conveyance and is able to operate at an uphill slope to provide improved liquid retention. Better conveyance and longer fluid retention allow the use of 200 square mesh (74 micron) screens. Today, shale shakers are typically separated into two categories: Rig shakers and Fine Screen Shakers.

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6.5.1

RIG SHAKERS


The rig shaker is the simpler of two types of shale shakers. A rig shaker (also called “Primary Shale Shaker” or “Coarse Screen Shaker”) is the most common type of solids control equipment found on drilling rigs. Unless a fine screen shaker replaces it, the rig shaker should be the first piece of solids control equipment that the mud flows through after coming out of the hole. It is usually inexpensive to operate and simple to maintain. Standard rig shakers generally have certain characteristics in common (see Figure 6-13): • Single rectangular screening surface – usually about 4’x5’ in size. Some designs have utilized dual screens, dual decks and dual units in parallel to provide more efficient solids separation and greater throughput. Depending on the particular unit and screen mesh used, capacity of rig shakers can vary from 100-1600 GPM or more. • A low-thrust horizontal vibrator mechanism, using eccentric weights mounted above, or central to, the screen basket. • Vibration supports to isolate the screen basket from its skid. • Skid with built-in mud box (sometimes called a “possum belly”) and a bypass mechanism. • Method of tensioning screen sections.

Screen sizes commonly used with rig shakers range from 10 to 40 mesh. Figure 6-14 shows the particle sizes separated by these mesh screens. In this graph the area to the left of each Figure 6-13 Rig Shaker Components

line represents solids which are smaller than that mesh size. These would pass through the screen and would not be removed. The area to the right of each line represents solids that are larger than the mesh size and would be removed from the mud.

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In Figure 6-14, the area to the right of the 10-mesh line is confined, because it is limited by the size of the page. In actual usage, this area is unlimited. This means that a 10 mesh screen will remove all particles larger than 1910 microns – it doesn’t matter if they are the size of BB’s, marbles or baseballs- they will be removed and discarded by a 10 mesh screen.

Figure 6-14 Particle Removal by Rig Shaker Screens Rig shakers are generally adequate for top hole drilling and for shallow and intermediate depth holes when backed up by other solids control equipment. For deeper holes and when using expensive mud systems, fine screen shakers are preferred.

6.5.2

FINE SCREEN SHAKERS


The fine screen shaker is the more complex and versatile of the two types of shale shakers. Fine screen shakers remove cuttings and other larger solids from drilling mud, but are designed for greatly improved vibratory efficiency over simple rig shakers. They are constructed to vibrate in such a way that they can use screens as fine as 150-200 mesh and still give reasonable screen life. They are versatile pieces of equipment and can operate on all types of mud. Figure 6-15 shows the range of particle sizes separated by the screens commonly used with fine screen shakers. A fine screen shaker can be installed on the rig in one of four ways: 1. Instead of the conventional rig shaker for use from top hole to total depth, if it is of a design capable of using coarse screens as well as fines screens. 2. Placed in series with the rig shaker by tapping into the flowline with a “Y”, thus keeping the rig shaker available as a “scalping shaker”. 3. Replacing the rig shaker after top hole is completed. 4. Downstream from the rig shaker to accept fluid after it passes through the coarse screen shaker (requires secondary pump).

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Figure 6-15 Fine Screen Shaker Particle Separation Because fine screen shakers have a wide variety of designs, they have few characteristics in common. The various designs are differentiated by screen orientation and shape, screen tensioning mechanism, placement and type of vibrator, and other special features.

6.5.3

SCREEN ORIENTATION AND SHAPE


Screen orientation and shape refers to the arrangement of the screen or screens in the unit. Screens are usually rectangular and may be single screens or multiple screens placed in series or in parallel, as shown in figure 6-16. Single deck, single screens (Figure 6-16 A & B) are the simplest design, with all mud passing over one screen of uniform mesh. This type of shaker requires efficient vibrator mechanisms to function properly under all possible drilling conditions and requires high throughput (conductance) per square foot of screen cloth. Units with screens placed in parallel (Figure 6-16 C, D & E) have two or more screen sections acting as one large screen so that no cuttings can fall between them. All screen sections should be the same mesh, since the coarsest mesh section determines the unit's screening ability. Shakers with screens stacked in series (Figure 6-16 F) have a coarse screen above a finer screen, with the finer screen being the controlling mesh size. The operating theory is that the top screen will remove some of the cuttings from the mud to take part of the load off the bottom screen, and thereby increase overall screening efficiency.

Figure 6-16 Shaker Screen Configurations

6.5.4

SCREEN TENSIONING MECHANISM


Shakers are designed to use either a hook strip or a rigid panel screen. Hook strip screens are made without a rigid frame and can prematurely fail if installed and allowed to operate with uneven tension. The shaker manufacturer’s instructions for screen installation should be followed, but the following steps may apply: • • • •

Inspect the supports and tension rails to be sure they are in good condition and clean Position the panel on the deck and inspect the screen to be sure it lays flat Install both rails loosely to the hook strip Push one side of the screen against the positioning blocks, if present; and fully tighten

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the screen against these blocks • Evenly tighten the tension bolts on the other side • Torque to the manufacturer’s recommended setting Rigid panel screen installation should proceed as per the manufacturer’s instructions. Panel screens can usually be installed or replaced much quicker than a hook strip screen since the cloth is already pre-tensioned, and the mechanical devices lock the panel with much less manual effort.

6.5.5

VIBRATOR MECHANISMS


Vibrator mechanisms vary widely in design and placement, and greatly affect the throughput efficiency of fine screen shakers. Most modern shakers utilize linear motion vibration with the vibrator mechanism mounted above the screen bed. One important advantage of linear motion is positive conveyance of cuttings across the screen surface, even when the surface is at a positive angle. This generally allows the use of an uphill sloped screen deck, greatly increasing throughput capacity and cuttings dryness. Most vibrators are electrically operated, although a few are hydraulically operated. In some units the vibration-inducing eccentric weights are separated from the drive motor, while in others the eccentric weights and motor form an integral assembly. In some units, the nature of the vibratory motions can be easily modified to take advantage of specific solids-conveying characteristics, but most units have a fixed vibratory motion.

6.5.6

MAINTENANCE

Because of their greater complexity and use of finer mesh screens, fine screen shakers generally require more attention than rig shakers. Nonetheless, their more effective screening capabilities more than justify the higher operating cost. This is especially true when expensive mud systems are used. Besides periodic lubrication, fine screen shakers require the same minimum maintenance as rig shakers while make a trip: • • • •

Wash down screens. Check screen tension. Shut down shaker when not drilling to extend screen life. Dump and clean possum belly.

In addition, frequent checks must be made for screen plugging and blinding, screen flooding and broken screens. All will occur more frequently on fine screen shakers than on coarse mesh rig shakers.

6.5.7

GENERAL GUIDELINES

General rules in operating shale shakers – whether coarse screen rig shakers or fine screen shakers – which have not already been mentioned, include the following: • Use the finest mesh screen capable of handling the full volume from the flow line under the particular drilling conditions. This will reduce solids loading on downstream hydrocyclones, and screens, improving their efficiency. Several screen changes, normally to progressively finer mesh screens over the course of the hole, are quite common. • Large cuttings which settle in the mud box (possum belly) of the shaker should never

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be dumped into the mud system. (Dump them into the sump or waste pit) • Except in extenuating circumstances (such as the presence of lost circulation material), all mud should be screened. This includes make-up mud hauled in from other locations. • Unless water sprays are absolutely necessary to control screen-blinding, water should not be used on the screen surface while drilling. Water sprays tend to was smaller cuttings through the screen which would otherwise e removed by their clinging to larger particles ( piggy-back effect). For a more complete analysis of different types of screens and shakers, ask the solids control representative for copies of the latest Product Bulletins.

6.6

MUD CLEANERS AND MUD CONDITIONERS


In many cases, combinations of vibratory screening and settling/centrifugal force are used together to provide an effective separation. The most familiar combination separator is the Mud Cleaner or Mud Conditioner ( Figure 6-17). Mud cleaners were developed in the early 1970s to remove fine drilled solids from weighted mud without excessive loss of barite and fluid. They have also proved valuable tools in closed systems and other “dry” location applications. These devices use a combination of desilting hydrocyclones and very fine mesh vibrating screens (120 – 400 mesh) to remove fine drilled solids while returning valuable mud additives and liquids back to the active mud system.

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Traditional mud cleaners use multiple 4” or 5” cyclones, mounted over a vibrating screen are able to effectively process 400 – 600 GPM. The process capacity is limited by screen capacity and it’s ability to discard “ dry” solids. With the introduction of linear motion vibrating screens, the capacity of the mud cleaner screen has been greatly increased. This, in turn, allows the use of additional hydrocyclones and higher, overall process capacities. The combination of hydrocyclones and linear-motion vibrating screens is called a Mud Conditioner to differentiate these machines from earlier mud cleaners. Mud conditioners often combine both desander and desilter cones mounted above the screen deck to take full advantage of the higher process capacity, usually 1000 – 1500 GPM (3785 – 5675 LPM), and reduce the overall size and weight of the unit, when compared to mud cleaners. After removal of large cuttings with a shaker, feed mud is pumped into the mud cleaner/conditioner’s hydrocyclones with a centrifugal pump. The overflow from the cyclones is returned to the mud system. Instead of simply discarding the underflow, the solids and liquid exiting the bottom of the cyclones are directed onto a fine screen. Drilled solids larger than the screen openings are discarded; the remaining solids, including most barite in a weight system, pass through the screen and are returned to the mud system. The cut point and amount of mass solids removed by a mud cleaner/conditioner depends primarily on the mesh of the fine screen used, Figure 6-18. Since there are many designs of mud cleaners/conditioners available, performance and economics will vary with machine and drilling variables.

Figure 6-17 Mud Cleaners and Mud Conditioners

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6.6.1

APPLICATIONS


Mud Cleaners/conditioners should be considered in these applications: 1. 2. 3. 4. 5.

Whenever the application requires finer screens than the existing shaker can handle Unweighted oil base mud Expensive polymer systems When the cost of water is high Unweighted water base mud with high disposal costs and/or environmental restrictions 6. When use of lost circulation material requires bypassing the shaker 7. Workover and completion fluids

Figure 6-18 Particle Removal by Mud Cleaner Screens

Mud cleaners/conditioners are simply a bank of hydrocyclones mounted over a fine-mesh screen. In many instances (even with modern fine screen shakers), a finer separation is required than can be provided with existing shakers. The question to answer becomes how to achieve the necessary level of screening at the lowest cost. The alternatives are: 1) Add additional similar shakers to handle the flow rate, 2) Replace the existing shakers with more efficient units or, 3) Add a mud cleaner/conditioner downstream from the existing shakers. Any of these may be correct, but a thorough study of the capital cost (the actual cost of new equipment, plus transportation, rig modifications, and installation) and the operating cost (screens and other expendables, plus fuel) is necessary to make the proper choice. Also, because of the cut points produced by some “modern” layered screens, the use of mud cleaner/conditioners may be indicated downstream of linear motion shakers. An increasingly important application of mud cleaners/conditioners is the removal of drilled solids from unweighted water-base mud in semi-dry form. This system is commonly used in

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areas where environmental restrictions prohibit the use of earthen reserve pits, and expensive vacuum truck waste disposal from steel pits is the alternative. The mud cleaner/conditioner is used to discard drilled solids in semi-dry form, which is classified as legal landfill in most areas, and is subject to economical dry-haul disposal techniques (dump truck or portable waste containers). Using a centrifuge, with a mud cleaner/conditioner to form a “closed” system, which eliminates discarding of any fluid, can carry this approach to dry-solids disposal further. In a closed system, underflow from the mud cleaner/conditioner screen is diverted to a holding tank and then centrifuged, which results in disposal of very fine, semi-dry solids and return of liquid to the active system. Such a system virtually eliminates the need for reserve pits, minimizes dilution, eliminates vacuum truck services, and meets environmental constraints when drilling within ecologically sensitive areas.

6.6.2

INSTALLATION


Installation of the mud cleaner/conditioner is made downstream of the shale shaker and the degasser. The same pump used to feed the rig’s desander or desilter is often reconnected to feed the mud cleaner/conditioner when weight material is added. (Most mud cleaner/conditioners are designed to also function as a desilter on unweighted mud by rerouting the cone underflow, or by removing or blanking off the screen portion of the unit. The mud cleaner/conditioner may then be used to replace or augment the rig’s desilter during top hole drilling.) Follow these guidelines when installing mud cleaner/conditioners to allow peak efficiency: • Size the mud cleaner/conditioner cyclones to process 110-125% of the full circulating flow rate • Take the mud cleaner/conditioner suction from the compartment receiving fluid processed by the degasser (weighted muds). • When using mud conditioners that have both desander and desilter cones, use a separate feed pump for the desander cones, and another feed pump for the desilter cones. The desander cone suction should be from the degasser discharge compartment. The desilter cone suction should be from the desander discharge compartment. • Keep all lines as short and straight as possible • Install a guard screen with approximately ½” openings at the suction to prevent large trash from entering the unit and plugging the cones. • Position the mud cleaner/conditioner on the pit high enough so the overflow manifold will gravity-feed fluid into the next downstream compartment at an angle of approximately 45°. • Avoid vertical overflow discharge lines from hydrocyclones.

6.6.3

GENERAL GUIDELINES


To operate mud cleaner/conditioners at maximum efficiency, remember these fundamentals: • Operate mud cleaners/conditioners continuously on the full circulating volume to achieve maximum drilled solids removal. • Operate mud cleaners/conditioners within the limits of the screen capacity. A mud cleaner/conditioner with a cyclone throughput of 800 GPM (3028 LPM) is of little value if the cone underflow exceeds the screen capacity, resulting in flooding and high mud additive losses

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• Feed the cone underflow to the screen at a single point. Multiple feed points on the screening surface minimize use of the available screen area and reduce overall capacity and efficiency. • Screen throughput is reduced by increased solids content and viscosity. The cyclone underflow plays a critical role in overall mud cleaner/conditioner efficiency. It is often desirable to modify the performance characteristics of the cones to decrease the amount of ultra fines in the cone underflow. This minimizes near-size screen plugging and Barite loss due to “piggy-backing”. • Do not judge screen efficiency simply on the basis of cuttings dryness or color. The total amount of drilled solids in the discarded material, along with the ratio of Barite to drilled solids, must be determined to correctly evaluate economic performance. • Select the number of cones to be operated and the particular mesh screen to be used according to drilling conditions. As a general rule, use the finest mesh screen possible (to process the full circulating rate) and size the number of cones accordingly. In some instances, a number of cones will have to be blanked off in order for the desired screen mesh to be used. This may involve an experimental determination of the number of cones and screen mesh to optimize performance. In some cases, more than one mud cleaner/conditioner will be needed.

6.6.4

MAINTENANCE


Maintenance of mud cleaners/conditioners generally combines the requirements of desilters and fine screen shakers: • • • • • •

6.7

Periodic lubrication Check screen tension Inspect the screen to ensure it is free of tears, holes and dried mud before start up Shut down unit when not circulating to extend screen life Check feed manifold for plugging of cyclone feed inlets Check cyclones for excessive wear and replace parts as necessary

SEPARATION BY SETTLING AND CENTRFIGUAL FORCE Return to Table of Contents

Using vibrating screens to remove drilled solids from mud uses only one characteristic of solids particles – their size. Another factor, which affects separation, is particle density. Solids control devices which take advantage of both particle size and particle density, speeds up the settling process by application of centrifugal force. These devices utilize Stokes Law as the basis for their operation. Stokes Law defines the relationship of factors governing the settling velocity of particles in a liquid. This relationship may be stated in its simplest form as : • Larger particles (of the same density) settle more rapidly than smaller ones. • High density solids settle more quickly than low density ones. • High acceleration and low viscosity speed up the settling rate. Settling pits, hydrocyclones, and centrifuges all utilize this principle in their operation. Settling pits simply use the force of gravity to separate solids. The larger and/or heavier a solid is, the faster it will settle through fluid in a settling pit. There is no way to speed up this natural settling

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process other than reducing the viscosity of the fluid, or flocculating the solid particles with the addition of chemicals. Settling pits are often large and require closure or remediation. The reduction in waste mud achieved through efficient solids control, greatly reduces the wastewater remediation treatment costs.

6.8

SAND TRAPS


A sand trap (Figure 6-19) is a settling tank, usually the first compartment of the first pit in the mud system. A shale shaker would normally sit on top of the sand trap and discharge into it. Sand traps can serve an important role in solids control by protecting downstream equipment against the results of torn shale shaker screens or by-passed shakers, by removing large particles which could plug cyclones or other equipment downstream. In normal operation, they also play a minor solids removal role by settling out a portion of the coarse drilled solids, which pass through the shaker screen.

Figure 6-19 Cutaway View of Sand Trap Normally, sand traps should have a top weir over which mud can flow into the next compartment, a slanted bottom, and a quick-opening, quick-closing dump valve or gate so that settled solids can be discharged with minimum fluid loss. In some highly sensitive environments, the extra liquids lost from dumping the sand trap cannot be allowed, and the desander suction is arranged to allow processing of the sand without creating a lot of liquid waste.

6.9

HYDROCYCLONES


Hydrocyclones (also referred to as cyclones or cones) are simple mechanical devices, without moving parts, designed to speed up the settling process. Feed energy is transformed into centrifugal force inside the cyclone, to accelerate particle settling in accordance with Stokes Law. In essence, a cyclone is a miniature settling pit which allows very rapid settling of solids under controlled conditions. Hydrocyclones are important in solids control systems because of their ability to efficiently remove particles smaller than the finest mesh screens. They are also uncomplicated devices, which make them easy to use and maintain. A hydrocyclone (see Figure 6-20), consists of a cylindrical/conical shell with a small opening at the bottom for underflow discharge, a larger opening at the top for liquid discharge through an

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internal “vortex finder”, and a feed nozzle on the side of the body near the cylindrical (top) end of the cone. Drilling mud enters the cyclone using energy created by a centrifugal feed pump. The velocity of the mud causes the particles to rotate rapidly within the main chamber of the cyclone. Heavy, coarse solids and the liquid film around them tend to spiral outward and downward for discharge through the solids outlet. Light, fine solids and the liquid phase of the mud tend to spiral inward and upward for discharge through the liquid outlet. Design features of cyclone units vary widely from supplier to supplier, and no two manufacturer’s cyclones have identical operating efficiency, capacity or maintenance characteristics. In the past, cyclones were commonly made of cast iron with replaceable liners and other wear parts made of rubber or polyurethane to resist abrasion. Newer designs are made entirely of polyurethane, and are less expensive, last longer, and weight less.

Figure 6-20 Hydrocyclone Most well designed oilfield cyclones operate most efficiently when 75 feet (22 meters ± 1.5 meters) of inlet head (± 5 ft) is applied to the cone inlet. Centrifugal pumps must be properly sized for cones to operate efficiently. Centrifugal pumps are constant energy (head) devices, and NOT constant pressure devices. Feed head is constant regardless of mud weight; pressure varies with mud weight. Although centrifugal pump theory and sizing exercises are beyond the scope of this text, if you are not able to properly size your centrifugal pump to create 75 feet (22 meters) of inlet head to your set of cyclones, it is highly recommended that you contact the solids control technical

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services staff for assistance. Remember, more errors in hydrocyclone applications are made with centrifugal pumps, rather than with the cyclones themselves. The size of oilfield cyclones commonly varies from 4” to 12” (101 mm to 305 mm). This measurement refers to the inside diameter of the largest, cylindrical section of the cyclone. In general – but not always – the larger the cone, the coarser its cut point and the greater its throughput. Typical cyclone throughput capacities are listed in Figure 6-21 Manifolding multiple cyclones in parallel can provide sufficient capacity to handle the required circulating volume, plus some reserve as necessary. Manifolding may orient the cyclones in a vertical position or nearly horizontal – the choice is one of convenience, as it does not affect cyclone performance. The internal geometry of a cyclone also has a great deal to do with its operating efficiency. The length and angle of the conical section (and the ratio of cone diameter to cone length), the size and shape of the feed inlet, the size of the vortex finder, and the size and adjustment means of the underflow opening, all play important roles in a cyclone’s effective separation of solids particles. CONE SIZE 4 in 5 in 6 in 8 in 10 in 12 in (I.D.) 101.6 mm 127 mm 152.4 mm 203.2 mm 254 mm 304.8 mm CAPACITY (GPM) 50 – 75 70 – 80 100 - 150 150 - 250 400 – 500 400 – 500 (LPM) 190 – 285 265 – 300 375 - 570 570 - 950 1500 – 1890 1500 – 1890 FEED PRESSURE 30 – 40 30 – 40 30 - 40 25 - 35 20 – 30 20 – 30 (PSI) Figure 6-21 Hydrocyclone Capacities Operating efficiencies of cyclones may be measured in several different ways, but since the purpose of a cyclone is to discard maximum abrasive solids with minimum fluid loss, both solids and liquid aspects of removal must be considered In a cyclone, larger particles have a higher probability of reporting to the bottom underflow (apex) opening, while smaller particles are more likely to report to the top (overflow) opening. The most common method of illustrating particle separation in cyclones is through a cut point curve. Figure 6-22 shows the approximate cut point ranges for cyclones used with unweighted water-base mud, and operated at 22 meters ± 1.5 meters (75 feet ±5 feet) of inlet head. Figure 6-22 Hydrocyclone Capacities CONE SIZE (I.D.) CUT POINT (MICRONS)

4 in 5 in 6 in 8 in 10 in 101.6 mm 127 mm 152.4 mm 203.2 mm 254 mm 15 - 20

20 - 25

25 - 30

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30 - 40

30 – 40

12 in 304.8 mm 30 – 40

6.9.1

HYDROCYCLONE CUT POINT


Particle separation in cyclones can vary considerably depending on such factors as feed head, mud weight, percent solids, and properties of the liquid phase of the mud. Generally speaking, increasing any of these factors will shift the cut point curse to the right, increasing the size of solids actually separated by the cyclone. By itself, the cut point does not determine a cyclone’s overall efficiency because it ignores the liquid loss rate. The amount of fluid in the cone underflow is important; if the solids are two dry, they can cause “roping” or “dry-plugging” of the underflow. In contrast, a cyclone operating with a spray discharge ( see Figure 6-23) gives solids a free path to exit. A cone operating in spray discharge will remove a significantly greater amount of solids than a cone in “rope” discharge.

6.9.2

ROPE DISCHARGE


Hydrocyclones should not be operated in rope discharge because it will drastically reduce the cone separating efficiency. In a rope discharge, the solids become crowded at the apex, cannot exit freely from the underflow, and become caught by the inner spiral reporting to the overflow. Solids which otherwise would be separated are forced into the overflow stream and returned to the mud system. This type of discharge can also lead to plugged cones and much higher cyclone wear.

Figure 6-23 Spray vs. Rope Discharge While a spraying cyclone appears to discharge more fluid, the benefits of more efficient solids removal and less cone wear outweigh the additional fluid loss. In cases where a dry discharge is required, the underflow from hydrocyclones can be screened or centrifuged to recover the free liquid.

6.10

DESANDERS


Desanders are hydrocyclones larger than 5” (127 mm). Generally, the smaller the cone, the smaller size particles the cone will separate ( see Figure 6-24). Desanders are primarily used to remove the high volumes of solids associated with extremely fast drilling of a large diameter hole.

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Desanders are installed downstream from the shale shaker and degasser. The desander removes sand sized particles and larger drilled solids which have passed through the shaker screen and discards them along with some liquid into a waste pit.

6.10.1 INSTALLATION


When installing a desander, follow these general recommendations: • Size the desander to process 110 – 125 % of the total mud circulation rate. • Keep all lines as short and straight as possible with a minimum of pipe fittings. This will reduce loss of head on the feed line and minimize back pressure on the overflow discharge line. • Do not reduce the diameter of the overflow line from that of the overflow discharge manifold. • Direct the overflow line downward into the next downstream compartment at an angle of approximately 45°. The overflow discharge line should not be installed in a vertical position – doing so may cause excessive vacuum on the discharge header and pull solid through the cyclone overflow, reducing the cyclone’s efficiency.

Figure 6-24 Particle Removal by Desander Cyclones (200 Mesh Screen Included for Comparison) • Keep the end of the discharge line above the surface of the mud to avoid creating a vacuum in the line. • Position the underflow trough to easily direct solids to the waste pit. • Install a low equalizer line to permit back flow into the desander suction. Operating desanders at peak efficiency is a simple matter, since most desanders are relatively uncomplicated devices. Here are a few fundamental principles to keep in mind: • Operate the desander unit at the supplier’s recommended feed head (usually around 75 feet (22 meters)). Too low a feed head decreases efficiency, while excessive feed head shortens the life of cyclone wear parts. • Check cones regularly to ensure the discharge orifice is not plugged.

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• Run the desander continuously while drilling and shortly after beginning a trip for “catch-up” cleaning. • Operate the desander with a spray rather than a rope discharge to maintain peak efficiency.

6.10.2 MAINTENANCE


Maintenance of desanders normally entails no more than checking all cone parts for excessive wear and flushing out the feed manifold between wells. Large trash may collect in feed manifolds which could cause cone plugging during operation. Preventive maintenance minimizes downtime, and repairs are simpler between wells than during drilling. Use of desanders is normally discontinued when expensive materials such as Barite and/or polymers are added to a drilling mud, because a desander will discard a high proportion of these materials along with the drilled solids. Similarly, desanders are not generally cost effective when an oil-base mud is in use, because the cones also discard a significant amount of the liquid phase.

6.11

DESILTERS


A desilter uses smaller hydrocyclones - usually 4” or 5” ID (101.6 mm or 127 mm ID) than a desander, and therefore generally removes smaller particles. The smaller cones enable a desilter to make the finest particle size separation of any full flow solids control equipment – removing solids in the range of 15 microns and larger ( Figure 6-25). This makes it an important device for reducing average particle size and removing abrasive grit from an unweighted mud.

Figure 6-25 Particle Removal by Desilter Cyclones (200 mesh Screen Included for Comparison) The cyclones in desilter units operate on the same principle as the cyclones used on desanders. They simply make a finer cut, and the individual cone throughput capacities are less than desander cones. Multiple cones are usually manifolded in a single desilter unit to meet throughput requirements. Desilters should be sized to process 110 – 125 % of the full rig flow rate.

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6.11.1 INSTALLATION


Installation of desilters is normally downstream from the shale shaker, sand trap, degasser and desander, and should allow ample space for maintenance. Here are some fundamentals for installing desilters: • Take the desilter suction from the compartment receiving fluid process by the desander. • Do NOT use the same pump to feed both the desander and desilter. If both pieces of equipment are to be operated at the same time, they should be installed in series and each should have its own centrifugal pump. • Keep all lines as short and straight as possible. • Install a guard screen with approximately ½ “ (12.7 mm) openings to prevent large trash from entering the unit and plugging the cones. • Position the desilter on the pit high enough so the overflow manifold will gravity-feed fluid into the next downstream compartment at an angle of approximately 45°. Remember – no vertical overflow discharge lines. • Keep the end of the discharge line above the surface of the mud to avoid creating a vacuum in the line. • Install a low equalizer line for back flow to the desitler’s suction compartment • Position the underflow trough to easily direct solids to the waste pit. Running a desander ahead of a desilter takes a big load off the desilter and improves its efficiency. If the drilling rate is slow and the amount of solids being drilled is only a few hundred pounds per hour, then the desander may be turned off ( to save fuel and maintenance costs), and the desilter may be used to carry the total desanding/desilting load.

6.11.2 GUIDELINES


To operate desilters at maximum efficiency, follow these basic guidelines: • Operate the cones with a spray discharge. Never operate the desilter cones with a rope discharge since a rope underflow cuts cone efficiency in half or worse, causes cone plugging, and increases wear on cones. Use enough cones and adjust the cone underflow openings to maintain a spray pattern. • Operate the desilter unit at the supplier’s recommended feed head. This is generally between 70 – 80 feet (21 – 25 meters) of head. Too much energy will result in excessive cone wear. • Check cones regularly for bottom plugging or flooding, since a plugged cone allows solids to return to the mud system. If a cone bottom is plugged, unplug it with a welding rod or similar tool. If a cone is flooding, the feed is partially plugged or the bottom of the cone may be worn out. • Run the desilter continuously while drilling and also for a short while during a trip. The extra cleaning during the trip can reduce overload conditions during the period of high solids loading immediately after a trip.

6.11.3 MAINTENANCE A desilter’s smaller cyclones are more likely than desander cones to become plugged with oversized solids, so it is important to inspect them often for wear and plugging. This may generally be done between wells unless a malfunction occurs while drilling. The feed manifold should be flushed between wells to remove trash. Keep the shale shaker well maintained – never bypass the shaker or allow large pieces of material to get into the active system.

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A desilter will discard an appreciable amount of Barite, because Barite particles fall within the silt size range. Desilters are therefore not recommended for use with weighted muds. Similarly, since hydrocyclones discard some absorbed liquid along with the drilled solids, desilters are not normally used with an oil-base mud, unless another device (centrifuge or mud cleaner/conditioner) is used to “deliquor” the cone underflow.

6.12

DECANTING CENTRIFUGE


Centrifuges for oilfield applications were first introduced in the early 1950’s. These early units were adapted from existing industrial decanting centrifuges. In the mid 1960’s, a perforated rotor type machine was developed which does not perform like a pure decanter. Commonly called “Barite recovery” centrifuges, these early designs were limited in capacity and application. Today, the centrifuge is the most important part of solids control. In addition, the increase use of low-solids mud, and environmental dewatering applications require high process volumes, greater clarification and solids capacity, and additional fine solids removal. Equipment selection is decided by site-specific requirements. Proper system selection is the first step to effective solids control.

6.12.1 SEPARATION PROCESS


A Decanting Centrifuge is so named because it Decants, or removes, free liquid from separated solids. A decanting centrifuge consists of a conveyor screw inside a rotating bowl, (see Figure 6–26).

Figure 6 – 26 Decanting Centrifuge Decanting centrifuges operate on the principle of exposing the process fluid to increased “Gforces”, thus accelerating the settling rate of solids in the fluid. A rotating bowl creates high Gforces and forms a liquid pool inside the bowl. The free liquid and finer solids flow toward the larger end of the centrifuge, and are removed through the effluent overflow weirs. The larger solids settle against the bowl wall forming a layer. These solids are pushed by a screw conveyor across a drainage deck, or beach. Dewatering actually takes place on the beach, with the decanted solids discharged through a series of underflow ports. A gearbox changes the relative speed of the conveyor to the bowl, causing them to rotate at slightly different rates. This speed differential is required to convey and discharge solids.

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The bowl and conveyor are rotated at speeds between 1500 and 4000 rpm’s depending on bowl diameter. This rotation develops centrifugal force sufficient to settle solids along the inner surface of the bowl wall. A gearbox is used to rotate the conveyor and bowl at slightly different speeds (slower or faster). This speed differential conveys and discharges solids from the machine. Mud, (sometimes diluted with water), is pumped into the conveyor hub through the feed tube. As the conveyor rotates, centrifugal force pushes the feed mud out the feed ports into the bowl. The heavy, coarse particles in the mud are forced against the inner surface of the bowl, where the scraping motion of the conveyor blades moves them toward the solids discharge ports. A drainage deck, called the beach, is where dewatering of the solids actually takes place. The deliquified solids are then discharged through a series of underflow ports. The light, fine solids, tend to remain in suspension in the pools between the conveyor flights and are carried out the overflow ports along with the liquid phase of the mud. The operating principle is similar to that of the cyclone, but it is mechanical rotation rather than fluid head, which induces the centrifugal force required to accelerate the particle-settling rate. Residence time of fluid in the bowl and a more “gentle” separation environment differentiate separation in a centrifuge from that of a cyclone. Centrifuges make the finest cut of any separation device used on the rig, usually 2 – 5 microns. Bowl sizes in common oilfield applications include diameters of 14”, 15”, 18”, and 24” (35.5 cm, 38.1 cm, 45.7 cm and 60.96 cm). Larger 24” (60.96 cm) diameter units generally have the highest liquid throughput and solids tonnage capacity. To figure out the gravitational forces of any centrifuge, one can use the formula that follows, or you may use the graph at Figure 6 – 27. (bowl rpm) x 0.0000142 x bowl diameter in inches = gravitational force “G” To determine the bowl rpm of a centrifuge the formula is as follows: (motor rpm x clutch sheave size) / bowl sheave size = bowl rpm In unweighted mud applications, feed mud capacity can range from 25 – 250 GPM (95 – 945 LPM), depending on unit capability and fluid requirements. Solids tonnage rates range from 1.25 tons/ hour to 8 tons/ hour. In weighted mud applications, feed mud capacity rarely exceeds 25 GPM ( 95 LPM). Total liquid throughput may be as high as 40 GPM (150 LPM), including dilution liquid. Dilution liquid is required to compensate for increasing viscosity, generally associated with increasing mud weight, in order to maintain satisfactory separation efficiency. The raw mud feed rate is substantially decreased as mud weight increases. In field operation, the decanting centrifuge is fitted with a housing over the bowl, liquid and solids collection hoppers, skid, feed slurry pump, raw mud and dilution liquid connections, power source, meters and controls.

6.12.2 UNWEIGHTED MUD APPLICATIONS


In the classic weighted mud applications, the solids discharge (containing the majority of the weight material) is returned to the mud system. The liquid effluent (containing the majority of the colloidal size solids) is discarded. As part of a “closed loop”, larger high capacity 75 – 250 GPM (285 – 945 LPM) decanting centrifuges (and sometimes standard centrifuges) are used to maximize fine solids removal. The coarser solids fraction is discarded in dry form, while the liquid and colloidal solids fraction is returned to the mud system.

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Figure 6-27 TO DETERMINE CENTRIFUGAL FORCE, DRAW A STRAIGHT LINE FROM BOWL DIAMETER THROUGH THE SPEED BEING USED.

CONTINUE THIS LINE TO THE COLUMN MARKED CENTRIFUGAL FORCE

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Decanting centrifuges are becoming more popular for processing unweighted oil muds, especially if 1) the mud has been brought in from another location and may contain a large amount of fine drilled solids, 2) slow, hard drilling with a gradual buildup of ultra-fine solids is anticipated or 3) the liquid mud phase is valuable.

6.12.3 WEIGHTED OIL-BASE MUD APPLICATIONS


In weighted, oil-base mud applications, decanting centrifuges are operated in series. The first unit returns the coarse solids fraction (weight material) to the active system, with the light, liquid fraction being routed to a holding tank (rather than being discarded as in a classic weighted mud application). A second unit, often a higher capacity machine, strips out the solids and discards them, returning the effluent to the active system. This process is not as effective as a single unit for viscosity control – a large portion of the colloidal size solids are returned to the active mud system in the effluent stream of the second unit – but the effluent stream from the first unit is too valuable to discard, especially with synthetic oil muds. Usually the coarse solids fraction is discarded and the base fluid is retained for reuse.

6.12.4 OPERATING PROCEDURES


Operating procedures will vary from model to model, but a few universal principles apply to almost all centrifuges: • Before starting a centrifuge, rotate the bowl or cylinder by hand to be sure it turns freely. • Start up the centrifuge before starting the mud feed pump and dilution water feed. • Set the raw mud and dilution feed rates according to the manufacturer’s recommendations ( usually variable with mud weight). • Remember to turn the feed and dilution water off before the machine is stopped. Centrifuges are relatively easy to operate, but they require special skills for repair and maintenance. Rig maintenance of centrifuges is limited to routine lubrication and speed adjustment of the unit.

6.13

AUXILLARY EQUIPMENT


6.13.1 AGITATION / MIXING EQUIPMENT All compartments in an active mud system other than the sand trap must be agitated in order to suspend solids and maintain a consistent mixture throughout the surface system. Suspension of the solids prevents their settling and keeps them in the active mud system so that they can be separated by mechanical solids control equipment. MUD GUNS For many years “Mud Guns” (see figure 6-28) were used as the sole means of agitation. These devices usually carry mud from a downstream compartment, and spray it at high velocity into an upstream compartment to keep solids suspended.

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Figure 6 – 28 Mud Gun

However, the true mixing effect of mud guns tends to be localized around the point where the nozzle spray discharges, leaving dead spots in other areas of the tank. Mud guns also increase the load on downstream solids control equipment, since each nozzle may add 100 – 200 GPM (378 – 757 LPM) of mud into the tank above and beyond the normal flow from the well. MECHANICAL AGITATORS Mechanical agitators ( see Figure 6 – 29) provide more thorough mixing of pits without the problems associated with mud guns. Agitators use an electric motor to drive impeller blades which flow the mud in a pattern throughout the tank. Given proper tank design, agitator sizing, and impeller placement, this method of agitation prevents settling, enhances the efficiency of solids removal devices, and maintains a well-blended mud system.

6.13.2 DEGASSERS Return to Table of Contents After passing through a shale shaker and a sand trap, all drilling mud should be directed through a degasser, see Figure 6 – 30. Degassers are often essential to the solids removal process to ensure the proper performance of hydrocyclones used in downstream solids control devices. The centrifugal pumps that feed the cyclones have difficulty maintaining their efficiency when pumping gas-cut mud, and the cones will not function properly if feed head fluctuates or if there is gas in the incoming mud. Also, recirculation of gas-cut mud is dangerous and could result in a blowout, since the density of gas-cut mud is lighter than the mud weight that should be maintained in the well bore. Figure 6 – 29 Mechanical Agitator There are three basic methods of degassing which can be utilized separately or in combination. The three degassing techniques are : atmospheric, vacuum and cyclonic. ATMOSPHERIC DEGASSERS Atmospheric degassers sit in the mud tank and consist of an elevated spray chamber and a submerged centrifugal pump. The gas-cut mud is pumped to the spray chamber at high velocity through a disc valve. The mud strikes the inside wall of the spray chamber with enough force to drive most of the entrapped gas out of the mud. The removed gas is usually discharged to atmosphere at pit level and the degassed mud returned to the active system. These devices are simple to operate and maintain, but heir effectiveness is often limited by the ability of the centrifugal pump to handle gas-cut mud. A second method of degassing is provided by the use of a vacuum. VACUUM-TYPE DEGASSERS Vacuum-type degassers separate gas bubbles from drilling mud by spreading the gas-cut mud into thin layers and then drawing off the gases with a vacuum pump. The mud is usually thinned by flowing it over a series of baffles or plates. Vacuum degassers are normally skid-mounted and installed on top of the mud tanks.

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Some models incorporate more than one degassing technique with-in a single unit. For example, one degasser spreads the mud into thin sheets through centrifugal force, sprays the mud onto an impact shield for residual gas separation, and draws off the gases with a vacuum pump.

Figure 6-30 Degassers INSTALLATION

Actual placement of the degasser and related pump will vary with the design of the degasser, but these recommendations may be used as a general rule: • Install a screen in the inlet pipe to the degasser to keep large objects from being drawn into the degassing chamber. Locate the screen about one foot (30 cm) above the pit bottom and in a well agitated spot. • There should be a high equalizer line between the suction and discharge compartment. The equalizer should be kept open to allow backflow of processed mud to the suction side of the degasser. • Route the liquid discharge pipe to enter the next compartment or pit below mud level to prevent aeration. • Install the gas discharge line to safely vent the separated gas to atmosphere or to a flare line. Maintenance of degassers varies considerably depending on make and model. In general, the following guidelines apply: • Check to make sure the suction screen is not plugged. • Routinely lubricate any pumps and other moving parts and check for wear.

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• Keep all discharge lines open and free from restrictions, such as caused by solids build up around valves • If the degasser utilizes a vacuum, keep it at the proper operating level, according to the manufacturer’s recommended range for the mud weight and process rate. • Check all fittings for air leaks. • If the unit uses a hydraulic system, check it for leaks, proper oil level, and absence of air in the system.

6.13.3 DRYING SHAKERS


A drying shaker, or dryer, is a vibrating screen separator used to remove free liquid from cuttings prior to discharge and recover the liquid for re-use. Drying shakers are usually installed to process the cuttings discharged from primary scalping and /or fine screen shakers. A typical drying shaker is a linear motion, multi-screen unit, with a feed hopper in place of the traditional back tank. Drying shakers are optimized to provide maximum retention time and cuttings dryness. Large hole sizes or high penetration rates may require more than one drying shaker to provided acceptable cuttings dryness and liquid recovery. Shale shakers are often the cause of excess mud loss during drilling operations, primarily due to screening too fine for drilling conditions, and the design of some shakers. This mud loss can greatly increase mud costs and site clean-up costs, especially when oil-base muds (OBM), or synthetic-base muds (SBM), are used. One characteristic of SBM is the increased amount of liquid retained on the cuttings, compared to water base muds (WBM) or conventional OBM. The drying shaker is designed to expose wet drilled cuttings to an additional vibrating screen surface, and separate some of the bound liquid coating the surface of the solids. The liquid is then returned to the active system or transferred to a storage tank for future use. DRYING SHAKER DESIGN The first drying shakers were “High-G” units, operating at 6.5 to 8 G’s. Prevalent thinking was that the additional impact force provided by the higher g-force would improve cutting dryness. Recent field studies indicate this is not necessarily true. Oil content on cuttings is primarily a function of retention time on the screen surface and the exposure of the cutting to the vibrational force of the shaker. The G-force greatly affects the speed at which cuttings move form the feed end of the screen surface to the discharge end. At 4 G’s, the conveyance rate is close to 1 inch ( 25.4 mm) per second, while at 7 Gs the conveyance rate is about 5 inches (127 mm) per second. Given a screen length of 24 inches (60.96 mm) and operation at 4 Gs, a cutting will take approximately 24 seconds to travel from the feed end of the screen to the discharge end. Increasing the G-force to 7 G’s reduces the exposure time to 6 seconds and will actually increase the amount of oil remaining on the cuttings. Since the amount of oil remaining on the cutting is a function of exposure time, screen deck length and deck angle will greatly influence cuttings dryness. Screen deck length determines the distance a cutting must travel prior to discharge and deck angle influences retention time – the longer the screen deck and the steeper the deck angle, the greater the retention time. However, longer screen decks may not fit the available space and too steep a deck angle will result in cuttings grinding and unacceptable build-up of fine solids.

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INSTALLATION • Locate the drying shaker(s) at a lower level from the main linear shakers and other solids control equipment. Feed to the drying shaker should be through open hopper sized to eliminate solids build-up or plugging. Cuttings should evenly deposited as close to the feed end of the drying shaker as possible to maximize usable screen area and cuttings dryness. • Provide slides or conveyors to direct “dry” cuttings to solids collection bins or discharge chutes. • Supply a flooded pump suction in the liquid collection tank for transfer by pump to the desired storage or processing tank. • The mesh of the screens on the drying shaker should be close to, or finer than, the screens on the main shakers to prevent the re-introduction of separated solids to the active system. • Use three-dimensional, Pinnacle™ screen panels at the feed end of the dryer to usable increase screen area. The middle screen panel may be either a 3-D or flat panel, depending on deck angel and desired fluid end point. The discharge end screen should be a flat screen panel to minimize cuttings bed depth and maximize liquid recovery. • Adjust screen deck angle design to properly convey solids, reduce liquid loss, and prevent cuttings grinding. • The liquid recovered from the drilled cuttings will contain base fluid, plus any solids finer than the screen mesh of the drying shaker. The recovered liquid should be processed through a decanting centrifuge to remove ultra-fine solids before the mud is returned to the active system or storage tank. In some installations, the decanting centrifuge may be eliminated, but only after careful consideration of cuttings size and their effect on fluid properties.

6.14

BASIC ARRANGEMENT RULES


Mechanical solids control is the most cost-effective method to control drilled solids. Proper solids control requires: • Proper planning before the well begins. • Proper selection, installation, and operation of available equipment • Sequential Treatment – It follows from previous recommendations that the solids control equipment should be arranged so that each piece of equipment removes successively finer solids. • Compartment Mixing – To provide a uniform solids load to the equipment each compartment, except the sand trap, should be well stirred. If mud guns are used, they should be arranged so that no flow bypasses the solids control equipment. Agitators are preferable. • Arrangement – Each piece of solids control equipment must be arranged so that the suction is taken from a compartment upstream of the discharge compartment, i.e.; there must be a wall or division with an equalizer opening between the suction and discharge, even if it is boards placed in the tank temporally. • Upstream Flow Through Equalizer – If the flow into the suction compartment is greater than the rate of flow processed by the equipment, then mud is flowing downstream through the equalizer. In other words, the flow through compartment equalizers should always be from the discharge to the suction. If it is not then mud is bypassing the equipment.

Page-228

• Dedicated Feed Pumps - Manifolding pumps and equipment so that multiple configurations are available depending on valve positions is always a mistake. There should be only one button to push to begin the pump and the discharge valve opened slow to be in operation of the solids control unit. • Use a separate centrifugal pump for each hydrocyclone device ( do not use the same pump for more than one piece of equipment). Equipment selection is decided by site-specific requirements. Proper system selection is the first step to effective solids control.


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CHAPTER 7

Return to Glossary


PRODUCT DATA INFORMATION ChapReturnter 7

ReturnProduct Data Information

PRODUCTS Return to Table of Contents 7.1 7.2 7.3 7.4 7.5 7.6 7.7 7.8 7.9 7.10 7.11 7.12 7.13 7.14 7.15 7.16 7.17

7.18 7.19 7.20 7.21 7.22 7.23 7.24 7.25 7.26 7.27 7.28 7.29 7.30 7.31 7.32 7.33 7.34 7.35 7.36 7.37 7.38

2K7 WATER SOLUBLE PAKS (Bronopol) ABI HIGH YIELD BENTONITE ACTIVATED CARBON ALCOMER 110 RD ALCOMER 60 RD ALCOMER 72L ALCOMER 74 ALKAPAM A-1103D & ALKAPAM A-1703D ALKAPAM C-1803 ALKAPAM N-1003D ALUM ALUMINUM STEARATE AQUA-STAR “D” BARITE CAGE ABSORBANT T408 CALCIUM CARBONATE (#0, #325 Grind) CALCIUM CARBONATE (Supercal, Poultry Grit Grind) CALCIUM CHLORIDE (77%) FLAKE CALCIUM CHLORIDE HT POWDER CALCIUM CHLORIDE (Mini-Pellets 94-97%) CAN-BREAK EBS CAN-BREAK I CAN-FREE CAN-EX CAN-OIL FLC CAUSTIC POTASH (90% KOH Flake) CAUSTIC SODA CELLOPHANE CHEMCIDE CHEM-CLEAN (Rig Wash) CHEMFOAM CHEMOIL-BREAK CHEMOIL-BUFF CHEMOIL-GEL CHEMOIL-LINK CHEMOIL PRODUCTS (General) CHEMUL-I CHEMUL-II

Page-230

PAGE 4 5 6 7 8 9 10 11 12

13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 41 42

7.39 7.40 7.41 7.42 7.43 7.44 7.45 7.46 7.47 7.48 7.49 7.50 7.51 7.52 7.53 7.54 7.55 7.56 7.57 7.58 7.59 7.60 7.61 7.62 7.63 7.64 7.65 7.66 7.67 7.68 7.69 7.70 7.71 7.72 7.73 7.74 7.75 7.76 7.77 7.78 7.79 7.80

CHEMWET-OM CITRIC ACID (Anhydrous) CMC CORINOX CORRIN O/S CYPAN DEFOAMER SILICONE DESCO CF DRIL-DOKTOR DRILLING DETERGENT “L” DRILLING DETERGENT “P” DRILSTAR HT DRILSTAR (Yellow) DRISPAC REGULAR / SUPER LO EMUL-BREAK ENKAPSAFLOC ENVIROFLOC (Calcium Nitrate) ENVIROPLUG MEDIUM AND #8 EXTRA HIGH YIELD BENTONITE GILSONITE HT PULVERIZED GLASS BEADS GRAPHITE GUAR GUM GYPSUM HEC 10 POLYMER HME COUPLER HSO-0600G HYDRATED LIME

HYPERDRILL AD-855 HYPERDRILL AF-204 RD HYPERDRILL AF-207 RD HYPERDRILL AF-247 RD “K2” KELZAN XCD POLYMER LIGNOCAL LIQUISPERSE MAGMA FIBER MAGNESIUM OXIDE MICA MUD-FLOC II D NATURAL GEL NUTSHELL

Page-231

43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84

PRODUCT DATA INFORMATION (Continued) Chapter 7

Product Data Information

PRODUCTS Return to Table of Contents 7.81 7.82 7.83 7.84 7.85 7.86 7.87 7.88 7.89 7.90 7.91 7.92 7.93 7.94 7.95 7.96 7.97 7.98 7.99 7.100 7.101 7.102 7.103 7.104 7.105 7.106 7.107 7.108 7.109 7.110 7.111 7.112 7.113 7.114 7.115 7.116 7.117 7.118 7.119 7.120 7.121

OILGEL 3000 OMV-100 PERCOL 338 RD (ALCOMER 338 RD) PERCOL 351 (MAGNAFLOC 351) PERCOL 728 (ZETAG 7692) PERCOL 757 (ZETAG 7235) PERCOL 787 (ZETAG 7587) POL-E-FLAKE POLYDRILL POLYTHIN POLY-VIS II POLY-XAN POLYMER POTASSIUM CHLORIDE POTASSIUM FORMATE POTASSIUM SULFATE PRIMA-SEAL PROCESSED LIME (Hot Lime, Quick Lime) SAF-KOTE SALT GEL SALT SAPP SAWDUST SODA ASH SODIUM BICARBONATE SODIUM SULFITE CATALYZED STAFLO REGULAR / EXLO SUPREME STARLOSE STARPAK DP SULPHAMIC ACID SUPER-LIG T-352 BIOCIDE THIN-TEX TORQ-2000 TORQ-GLIDE TORQ-TROL II ULTRA SEAL (XP, C, PLUS) WALNUT WYOMING GEL XANVIS POLYMER XL-DEFOAMER ZINC CARBONATE Page-232

PAGE 85 86 87 88 80 90 91 92 93 94 95 96 97 98 99 100 101 102 103 104 105 106 107 108 109 110 111 112 113 114 115 116 117 118 119 120 121 122 123 124 125

7.1

2K7 WATER SOLUBLE PAKS (Bronopol)


DESCRIPTION 2-Bromo-2-Nitropropane-1,3-Diol (BNPD) 2K7 (Bronopol) is a highly effective bactericide. For convenience of handling, the product is packaged in a 1 kg water-soluble package within a disposable outer poly bag. The water-soluble package is used to minimize exposure to the bactericide. PROPERTIES Physical

Appearance: Mol. Wt.: Melting Point: Flash Point:

Free-flowing crystalline 200 130º C Not Flammable

Chemical

Type: Solubility: pH: Microtox:

Bactericide Soluble (water) 5.0-7.0 (1% @ 20ºC) 10% @ (.03 kg/m3)

APPLICATION Use 0.06-0.1 kg/m3 active ingredients based on the total volume of the drilling fluid system until bacteria control is achieved. A periodic dosage of 0.01-0.025 kg/m3 should be made to maintain bacterial control. MIXING AND HANDLING Use the chemical barrel to dissolve the water-soluble package. The water temperature in the chemical barrel should be above 10ºC to dissolve the package. Open the outer poly bag and add the water-soluble package of 2K7 directly into the chemical barrel. Agitate until the package and product is dissolved then add to the system as needed.

NOTE: Flush chemical barrel with water prior to adding 2K7. Caustic Soda will greatly reduce the ability of 2K7 to control bacteria. WHMIS: See MSDS Registration. #21790 Pest Product Control Act

TDG: Regulated (see MSDS)

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PACKAGING: Fibre keg, 251kg water-soluble bags in poly packages.

7.2

ABI HIGH YIELD BENTONITE


DESCRIPTION ABI High Yield Bentonite is a highly concentrated, polymer enhanced, sodium montmorillonite. In distilled water it yields a minimum 220 bbl/ton of 15 cps viscosity mud. PROPERTIES Physical

Appearance: Specific Gravity: Bulk Density: Moisture Content: Flash Point:

Grey to tan color powder 2.5 Not available Not available Not applicable

Chemical


Sodium montmorillonite Not soluble (forms a colloidal suspension) Not available Not applicable

APPLICATION ABI High Yield is used for providing quick viscosity when needed. It is especially advantageous in remote locations where transportation of large quantities of product is prohibitive or where small volumes of high viscosity mud are required. (i.e.: seismic drilling, water well drilling, river crossings, etc.). The level of water purity will affect the performance of the Bentonite. Prior to mixing, acidic and/or hard water should be treated with soda ash to a pH of 8.5-9.0. MIXING AND HANDLING Mix directly through the hopper at no faster than 4-6 minutes per sack. A mask and goggles should be worn to prevent inhalation of dust and contact with the eyes. Fresh air ventilation should be provided in the mixing area.

WHMIS: Controlled (see MSDS)

TDG: Not regulated

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PACKAGING: 50 lb sack

7.3

ACTIVATED CARBON


DESCRIPTION Activated Carbon is a very active product with a high proportion of medium and large pores. It is recommended for the adsorption of large quantities of high molecular weight substances. PROPERTIES

Physical

Appearance: Specific Gravity: Boiling Point: Flash Point:

Dark gray/black powder .22-.32 2150ºC Not flammable

Chemical


Charcoal Negligible (water, oil) 4.0-6.0 Not applicable

APPLICATION The use of granular Activated Carbon in wastewater treatment systems is a proven process for removal of organic compounds. As a tertiary treatment method, carbon adsorption and regeneration have been used to process domestic wastewaters contaminated with industrial wastes of organic origin as well as biologically treated wastewaters. Activated Carbon, when contacted with water containing organic material, will remove these compounds selectively by a combination of adsorption of the less polar molecules, filtration of the larger particles, and partial deposition of colloidal material on the exterior surface. The quantity of Activated Carbon required will depend upon the degree of contamination. MIXING AND HANDLING Fluids may be filtered through Activated Carbon or the Activated Carbon may also be added directly to a contaminated fluid to remove impurities. It is advisable to use a dust mask and eye protection while mixing all powdered products.

WHMIS: Not controlled

TDG: Not regulated

Page-235


7.4

ALCOMER 110 RD


DESCRIPTION Alcomer 110 RD is readily dispersible acrylamide-based copolymer. PROPERTIES

Physical

Appearance: Specific Gravity: Bulk Density: Flash Point:

Off-White powder .65 Not available Not available

Chemical

Type: Solubility: pH: Microtox: Character:

Flocculant Dispersible-Soluble 6.0 (1% solution) >91% @ (3.0 kg/m3) HMW Anionic

APPLICATION Alcomer 110 RD has been developed to give enhanced performance in conventional clear water or low solids drilling fluids while maintaining functionality in K+, polymer and high salt systems. With improved dispersibility over conventional PHPA powders, Alcomer 110 RD provides all the benefits normally associated with PHPA type additives. Alcomer 110 RD will provide viscosity, shale stabilization, flocculation and lubrication. As a viscosifier, Alcomer 110 RD is very efficient and cost effective in low solids, low salinity-drilling fluids. Normal dosage rates are between 0.75-3.0 kg/m3. Alcomer 110 RD can be used alone or in conjunction with clay stabilizers such as K+ to inhibit shale hydration. Sufficient polymer must be maintained in the system to provide a protective coating on the well bore and drill cuttings. Normal addition rates are 0.6-3.0 kg/m3. MIXING AND HANDLING

Alcomer 110 RD is added either at the flow line to promote solids settling in the sump or at a point prior to mechanical separation equipment. A 0.5% stock solution is most commonly prepared using (1) one viscosity cup of polymer per 50 gallons of fresh water. Alcomer 110 RD must be mixed slowly to prevent "humping" and the subsequent loss of polymer at the shaker screen. Alcomer 110 RD becomes very slippery when it comes in contact with water. A spill should be cleaned up with an absorbent material. It is advisable to use a dust mask and eye protection while mixing all powdered products. WHMIS: Not controlled

TDG: Not regulated

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PACKAGING: 25 kg sack

7.5

ALCOMER 60 RD


DESCRIPTION Alcomer 60 RD is a readily dispersible, acrylamide-based co-polymer. PROPERTIES Physical

Appearance: Specific Gravity: Moisture Content: Flash Point:

Off white powder 0.85 Not available None exhibited

Chemical


Co-polymer Dispersible-Soluble Not available >91% @ (3.0 kg/m3) LMW Anionic

APPLICATION

Alcomer 60 RD has been developed to provide improved shale stabilization / inhibition in drilling fluids with minimal effect on rheology. It is suitable for use in fresh water, seawater, K+ polymer, and other inhibitive water-based systems. Its improved rheological properties allow addition of higher concentrations with reduced viscosity humping in solids laden muds. Dosage rates are 2.0-6.0 kg/m3. Alcomer 60 RD exhibits improved dispersibility over conventional PHPA's while providing the following benefits: 1. Shale stabilization/inhibition, minimized viscosity increases, added lubricity, lower fluid loss, improved filter cake quality, and is readily dispersible with no formation of fish eyes. 2. The solid grade form is more cost effective than liquids and is environmentally friendly. MIXING AND HANDLING Because of its excellent dispersibility and mixing Alcomer 60 RD can be added directly to the mud system without pre-wetting in a solvent. A small hole should be cut into the bottom of the bag, allowing it to flow at a steady rate into the mud hopper. If necessary Alcomer 60 RD can be prehydrated at concentrations of 10.0-15.0 kg/m3 in a separate tank and fed into the main circulating system to maintain concentrations of 2.0-6.0 kg/m3. Alcomer 60 RD becomes very slippery when it comes in contact with water. A spill should be cleaned up with an absorbent material. It is advisable to use a dust mask and eye protection while mixing all powdered products.


TDG: Not regulated

Page-237


7.6

ALCOMER 72L


DESCRIPTION Alcomer 72L is a highly efficient, thermally stable drilling fluid thinner or deflocculant. It is a cost effective, environmentally acceptable alternative to heavy metal lignosulphonates, lignites and tannins. PROPERTIES Physical

Appearance: Specific Gravity: Flash Point:

Pale yellow liquid 1.29 Not applicable

Chemical


Polymer thinner Dispersible-Soluble 7.0-7.5 Pending LMW Anionic

APPLICATION Alcomer 72L functions primarily as a rheology control agent by reducing viscosity and gel strengths. It provides excellent rheological control at high (175οC) and low temperatures in conventional or low solids water-based drilling fluids. Its effectiveness has been proven in fresh water gel, K+ polymer, gyp, and salt muds up to 10,000 mg/L Chlorides. Alcomer 72L is effective at any pH and due to its rapid dissolution; it immediately affects the rheology of a drilling fluid. Requirements are typically ¼ that of lignosulfonate with the actual amount required dependent upon the amount of solids present in the system. The thinning efficiency of Alcomer 72L is actually improved by the presence of moderate levels of calcium up to a maximum of 800-1000 mg/L. Alcomer 72L has also been found to be a very effective thinner in situations where carbonate/bicarbonate and sulfate contamination occur and conventional thinners have little or no effect. Concentrations for normal use range from 0.4-4.0 L/m3. MIXING AND HANDLING Alcomer 72L should be added directly to the mud system. This product is stable at high and low temperatures and has excellent freeze-thaw stability. Alcomer 72L is very slippery when spilt and should be cleaned up immediately with an absorbent material. WHMIS: Not controlled

TDG: Not regulated

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PACKAGING: 20 liter pail

7.7

ALCOMER 74


DESCRIPTION Alcomer 74 is a highly efficient, thermally stable deflocculant or thinner with improved capabilities in high solids and contaminated muds. It is a cost effective, environmentally acceptable alternative to heavy metal lignosulfonates, lignites and tannins. PROPERTIES

Physical

Appearance:

Specific Gravity:

Flash Point:

White micro bead 0.75-0.85 Not applicable

Chemical


Acrylate co-polymer Dispersible (water) 7.0-7.5 (1% solution) >91% @ (0.7 kg/m3) LMW Anionic

APPLICATION Alcomer 74 functions primarily as a rheology control agent by reducing viscosity and gel strengths. It has been designed to offer increased thermal stability (260ºC) and provide better rheology control and cost efficiency than Alcomer 72L when drilling green cement, salt or anhydrite stringers. Its effectiveness has been proven in fresh water gel, K+ polymer, gyp, and saturated salt muds. Alcomer 74 is effective at any pH and due to its rapid dissolution, immediately affects the rheology of a drilling fluid. Alcomer 74 will also function as a gel suppressor and help reduce the fluid loss in most mud systems. A highly concentrated "pill" of Alcomer 74 will induce wall cake breakdown prior to completion, cementing or stimulation operations. Dose requirements are typically ¼ that of lignosulfonate with the actual amount required dependent upon the amount of solids present in the system. Alcomer 74 has also been found to be a very effective thinner in carbonate/bicarbonate and sulfate contaminated muds where conventional thinners have little or no effect. Concentrations range from 0.3-3.0 kg/m3. MIXING AND HANDLING Alcomer 74 should be added directly to the mud system through the mixing hopper. Store away from acids. It is advisable to use a dust mask and eye protection while mixing all products. Alcomer 74 is slippery when spilled and should be cleaned up with an absorbent material. WHMIS: Not controlled

TDG: Not regulated

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7.8

ALKAPAM A-1103D & ALKAPAM A-1703D


DESCRIPTION Alkapam A-1103D and A-1703D are water-soluble acrylamide co-polymers. disperse readily in water minimizing the formation of "fish eyes".

They

PROPERTIES Physical


White granules 0.80 @ 25ºC Not available >93ºC (will burn)

Chemical


Co-polymers Dispersible-Soluble Not available >100% @ (2.86 kg/m3) >75% @ (2.86 kg/m3) A-1103D HMW Anionic A-1703D (Very) HMW Anionic

APPLICATION Alkapam A-1103D and A-1703D are effective anionic polymer flocculants used for clear water drilling. They should be added through a chemical barrel at the flow line or injected directly into a centrifuge from a premixed polymer tank, usually in a 0.5% stock solution. They can also be used for fluid clarification when added at the centrifuge in sumpless drilling operations. Alkapam A-1703D will provide shale stabilization and viscosity when used in higher concentrations of 0.3-3.0 kg/m3. MIXING AND HANDLING Mix directly into the hopper at 30 minutes per sack or add (with agitation) to a chemical barrel or polymer-mixing tank. Avoid mixing too rapidly. A mask and goggles should be worn to prevent inhalation of dust and contact with eyes. Alkapam A-1103D and A1703D become very slippery when coming in contact with water. A spill should be cleaned up with an absorbent material.


TDG: Not regulated

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7.9

ALKAPAM C-1803 Return to Table of Contents

DESCRIPTION

Alkapam C-1803 is a water-soluble polyelectrolyte, supplied in a free flowing granular form. PROPERTIES Physical


White granular solid 0.80 Not available Not available Not applicable

Chemical


Flocculant Dispersible-Soluble Not available Pending HMW Cationic

APPLICATION Alkapam C-1803 is an effective cationic polymer flocculant used for clear water drilling and fluid clarification in closed systems. It is very effective in dewatering water-based systems especially those that contain significant amounts of biopolymers and PACs. Alkapam C-1803 should be added through a chemical barrel at the flow line or injected directly into a centrifuge from a premixed polymer tank, usually in a 0.5% stock solution. Additions of Alkapam C-1803 should be preceded by the appropriate organic or inorganic coagulant additions. MIXING AND HANDLING Mix slowly into a chemical barrel or polymer mixing tank and allow product to hydrate. Avoid mixing too rapidly. A mask and goggles should be worn to prevent inhalation of dust and contact with eyes. Alkapam C-1803 becomes very slippery when it comes in contact with water. A spill should be cleaned up with an absorbent material.


TDG: Not regulated

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7.10

ALKAPAM N-1003D Return to Table of Contents

DESCRIPTION

Alkapam N-1003D is a water-soluble acrylamide co-polymer with a non-ionic charge. It disperses readily in water reducing the formation of "fish eyes". PROPERTIES Physical


White granular solid 0.80 @ 25ºC Not available Not available >930ºC (will burn)

Chemical


Co-polymer Dispersible-Soluble Not available >100 @ (2.85 kg/m3) HMW Non-ionic

APPLICATION Alkapam N-1003D is an effective non-ionic polymer flocculant used for clear water drilling. It should be added through a chemical barrel at the flow line or injected directly into a centrifuge from a premixed polymer tank, usually in a 0.5% stock solution. Alkapam N-1003D can also be used for fluid clarification when added at the centrifuge in sumpless drilling operations. It is especially effective in situations where high levels of clay are present. MIXING AND HANDLING Mix directly into the hopper at 20 minutes per sack or add (with agitation) to a chemical or polymer-mixing tank. Avoid mixing too rapidly. A mask and goggles should be worn to prevent inhalation of dust and contact with eyes. Alkapam N-1003D becomes very slippery when it comes in contact with water. A spill should be cleaned up with an absorbent material.


TDG: Not regulated

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7.11

ALUM


DESCRIPTION Aluminum Sulfate (Alum) is a coagulating agent used in water treatment. PROPERTIES

Physical


White/creamy powder Not available 1089 kg/m3 Not flammable

Chemical


Coagulant Soluble (water) 3.5 (1% solution) Not applicable

APPLICATION Alum is used in the flocculation of fine solids in the treatment of water and some waste drilling fluids. Addition concentrations will vary based upon particular requirements. MIXING AND HANDLING Alum may be added through a mixing hopper or at a point of suitable agitation. It is advisable to use a dust mask and eye protection while mixing all powdered products.



Page-243


7.12

ALUMINUM STEARATE Return to Table of Contents

DESCRIPTION

Aluminum Stearate (Al(Cl8H35O2)3) is a surface-active organo-metallic compound. PROPERTIES

Physical

Appearance: Specific Gravity: Melting Point: Flash Point:

White powder 1.01 115-125ºC Not applicable

Chemical


Defoamer Negligible 3.0-4.0 (5% dispersion) = 7% @ (0.285 kg/m3)

APPLICATION Aluminum Stearate is generally used as a defoamer in dispersed or gel-chemical mud systems. Aluminum Stearate is not water-soluble. It is recommended to pre-mix the Aluminum Stearate in mineral or diesel oil (concentration approximately 20.0-25.0 kg in 20 liters of mineral or diesel oil) prior to adding it directly to the mud active system. MIXING AND HANDLING Aluminum Stearate should be stored in a dry, cool environment. Some dust will occur while mixing. Care should be taken to avoid contact with the eyes. If contact is made, rinse the eyes for five to fifteen minutes with water. It is advisable to use a dust mask and eye protection while mixing all powdered products.


TDG: Not regulated

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7.13

AQUA-STAR “D” Return to Table of Contents

DESCRIPTION

Aqua-Star D is a derivatized starch-based fluid loss control agent capable of enhancing rheology and providing lubricity when used in conjunction with various shear-thinning polymers. It is a sodium carboxymethyl starch. PROPERTIES

Physical


Tan off-white powder >1.0 Not available Not applicable

Chemical


Complex Starch Soluble (water) 6.0-8.5 (1% solution) =52% @ (16.0 kg/m3)

APPLICATION Aqua-Star D exhibits fluid loss control efficiencies similar to the celluloses. The synergistic behavior of Aqua-Star D with Bentonite and other polymers enhances the shear thinning properties of a drilling fluid and thus provides excellent hole cleaning at low shear rates. Aqua-Star D’s ability to coat clay and shale particles aids in controlling dispersion and the eventual destabilisation of well bores. Aqua-Star D’s ability to encapsulate drilled solids facilitates their removal at surface. With the addition of an oxygen scavenger Aqua-Star D can be temperature stable up to 150ºC. Aqua-Star D is non-fermenting and requires no biocide under normal conditions. Aqua-Star D exhibits greater stability to enzyme contamination than typical stabilized fluid loss polymers. Aqua-Star D is used in concentrations ranging from 5.0-25.0 kg/m3 depending on fluid loss requirements and the amount of solids in the system. MIXING AND HANDLING Aqua-Star D mixes readily and may be added to a mud system through the hopper at 10-15 minutes per sack. It is advisable to use a dust mask and eye protection while mixing all powdered products. WHMIS: Not controlled

TDG: Not regulated

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7.14

BARITE Return to Table of Contents

DESCRIPTION

Barite is ground Barium Sulfate (BaSO4) with a minimum specific gravity of 4.2 and conforming to the following API specifications: Wet Screen Analysis: 3% residue (max) on US Sieve #200 (74 microns) 5% residue (min) on US Sieve #325 (44 microns) Soluble Alkaline Earths as Calcium: 250 mg/L (max).

PROPERTIES Physical


Grey-white powder 4.2-4.4 1580º C Not applicable

Chemical


Inorganic Barium Salt Insoluble (water, oil) 7.0-9.5 Not applicable

APPLICATION In its pure form Barite is chemically inert in fresh water and oil-based drilling fluids and can be used to increase mud densities to as high as 2400 kg/m3. To calculate the amount of barite required to raise the weight use the following formula: Barite (kg/m3) = 4200 (W2 – W1) 4200 – W2 where W1 = present mud weight in kg/m3 where W2 = desired mud weight in kg/m3 Every l00 sacks of Barite added will increase the volume of the system by one cubic metre. MIXING AND HANDLING Barite can be mixed through the mud hopper as rapidly as needed. When large quantities are added to a mud system it may be necessary to add water to prevent mud dehydration. WHMIS: Not controlled

TDG: Not regulated

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7.15

CAGE ABSORBANT T408 Return to Table of Contents

DESCRIPTION

Cage T408 is a granular absorbent in the form of the naturally occurring mineral Zeolite. Cage T408 has a high affinity for hydrocarbon absorption. It is a solid sponge, which absorbs high and low viscosity materials into its molecular structure. One half kilogram of Cage T408 can have the equivalent internal surface area of a football field. Cage T408 is a free-flowing material that will reach spills in areas that are hard to access. PROPERTIES

Chemical

Physical Appearance: Specific Gravity: Bulk Density: Flash Point:

Brown angular solid 2.1-2.5 770-980 kg/m3 Not applicable


Mineral Not soluble Not available Not applicable

APPLICATION Cage T408 is an oil-absorbing medium used in areas of high traffic due to its ability to provide safe footing in areas where oil has been spilled. The Cage T408 will not release the oil it has absorbed even when immersed in water. Cage T408 can be applied to petroleum spills of many kinds for the purposes of clean up. It provides safer footing in areas where there is the potential of slippery conditions i.e.(ice, oil muds, rig floor). It may be used to build or line berms where there is the potential of petroleum product spillage. The Cage T408 absorbs odors, and will chemically bond to many metals such as lead, zinc and copper in solution. Cage T408 may also find application as a lost circulation material and in imparting some lubricity to the drill-string in the same manner as walnut shell. MIXING AND HANDLING Cage T408 can be added directly to hydrocarbon spills and onto slippery surfaces like the rig floor. Skin and eye protection should be observed. See MSDS. It is advisable to use a dust mask and eye protection while mixing all powdered products.


TDG: Not regulated

Page-247


7.16 CALCIUM CARBONATE (#0, #325 Grind) Return to Table of Contents

DESCRIPTION

Calcium Carbonate (CaCO3) is a naturally occurring, ground limestone. PROPERTIES

Physical

Appearance: Specific Gravity: Melting Point: Flash Point: Grind Size:

White-gray-buff powder 2.7-2.9 2570ºC Not flammable #0 (99% passing 40 mesh) #325 (96% passing 325 mesh)

Chemical


Mineral 1.3mg/100g @ 18ºC 8.3-9.7 (1% slurry) Not applicable

APPLICATION As Calcium Carbonate #0 or #325 grind, these finer grades of Calcium Carbonate are used primarily as weighting materials. Calcium Carbonate readily dissolves in the presence of hydrochloric acid. Because of this, Calcium Carbonate is an ideal weighting agent for use in drilling pressured zones or in completion and workover fluids where the clean up of the production zone is critical to well productivity. MIXING AND HANDLING

Calcium Carbonate may be added directly at the suction with agitation or through the mud hopper. To avoid settling out in the surface tanks the fluid viscosity should be raised sufficiently to provide adequate suspension. It is advisable to use a dust mask and eye protection while mixing all powdered products.


TDG: Not regulated

Page-248


7.17

CALCIUM CARBONATE (Supercal, Poultry Grit Grind ) Return to Table of Contents

DESCRIPTION

Calcium Carbonate (CaCO3) is a naturally occurring, ground limestone. PROPERTIES

Physical

Appearance: Specific Gravity: Melting Point: Flash Point: Grind Size:

White-gray-buff powder 2.7-2.9 2570ºC Not flammable Supercal (99.2% passing 20 mesh) Poultry Grit (99.8% passing 5 mesh)

Chemical


Mineral 1.3mg/100g@18ºC 8.3-9.7 (1% slurry) Not applicable

APPLICATION Supercal is a "medium grind" carbonate with a particle size larger than "325" or "0" grind, but less than "Poultry" Grit. It can be used in combination with other sized carbonates to provide a wide spectrum of bridging agents for drilling fluids. Its acid solubility also makes it especially suitable as a weighting or bridging agent in completion/work over and stimulation operations. MIXING AND HANDLING Supercal and Poultry Grit may be added directly through the hopper. To minimize settling in the surface tanks, the fluid should be of sufficient viscosity, or the agitation such that the particles are kept in suspension. It is advisable to use a dust mask and eye protection while mixing all powdered products.


TDG: Not regulated

Page-249


7.18

CALCIUM CHLORIDE (77%) FLAKE Return to Table of Contents

DESCRIPTION

Calcium Chloride (77%) Flake (CaCl2·2H2O) is a basic manufactured salt, which is hygroscopic and highly soluble in water. PROPERTIES

Physical


Small white flakes 1.85 176ºC Not applicable

Chemical


Salt Soluble (Water 98g/100ml) 7.0-10.0 Not applicable

APPLICATION Calcium Chloride (77%) Flake has a wide variety of oilfield uses. It is used as: - a salinity source in oil muds (only when pre-dissolved in water) - a flocculant for clear water drilling - a completion/work over fluid - a packer fluid - an accelerator for oil well cement (up to 4% wt. cement) MIXING AND HANDLING Calcium Chloride (77%) Flake can be added directly through the hopper or predissolved in a chemical barrel or cement mix-water tank prior to use. Use good industrial hygiene practices to avoid eye and excess skin contact. Wear a protective dust mask and goggles when handling and mixing. Store in a cool, dry place and keep container tightly closed when not in use. Failure to store material properly may result in caking or wetness from atmospheric moisture.


TDG: Not regulated

Page-250


7.19

CALCIUM CHLORIDE HT POWDER Return to Table of Contents

DESCRIPTION

Calcium Chloride HT Powder (CaCl2) is a basic manufactured salt, which is hygroscopic and highly soluble in water. PROPERTIES

Physical Appearance: Specific Gravity: Boiling Point: Flash Point:

Chemical

White powder 2.2 >204ºC Not applicable


Salt Soluble (745 gm/L @ 20ºC) 7.0-10.0 Not applicable

APPLICATION Calcium Chloride HT Powder has a wide variety of oilfield uses. It is used as: - a salinity source in oil mud - a completion/work over fluid - a packer fluid - an accelerator for oil well cement (up to 4% wt. cement) MIXING AND HANDLING Calcium Chloride HT Powder can be added directly through the hopper or pre-dissolved in a chemical barrel or cement mix-water tank prior to use. Use good industrial hygiene practice to avoid eye and excess skin contact. Wear a protective dust mask and goggles when handling and mixing. Store in a cool, dry place and keep container tightly closed when not in use. Failure to store material properly may result in caking or wetness from atmospheric moisture.


TDG: Not regulated

Page-251


7.20

CALCIUM CHLORIDE (Mini-Pellets 94-97%) Return to Table of Contents

DESCRIPTION

Calcium Chloride Mini Pellets (CaCl2٠2H2O) is a pelletized manufactured salt, which is hygroscopic and highly soluble in water. PROPERTIES

Physical


White pellets 1.85 176ºC Not applicable

Chemical


Salt Soluble (water 98g/100ml) 7.0-10.0 Not applicable

APPLICATION Calcium Chloride Mini Pellets (94-97 %) have a wide variety of oilfield uses. - a salinity source in oil muds (only when pre-dissolved in water) - a flocculant for clear water drilling - a completion/work over fluid - a packer fluid - an accelerator for oil well cement (up to 4% wt. cement) MIXING AND HANDLING Calcium Chloride Mini Pellets can be added directly through the hopper or pre-dissolved in a chemical barrel or cement mix-water tank prior to use. Use good industrial hygiene practices to avoid eye and excess skin contact. Wear a protective dust mask and goggles when handling and mixing. Store in a cool, dry place and keep container tightly closed when not in use. Failure to store material properly may result in caking or wetness from atmospheric moisture.


TDG: Not regulated

Page-252


7.21

CAN-BREAK EBS Return to Table of Contents

DESCRIPTION

Can-Break EBS is a water-soluble chemical breaker for organic polymers. PROPERTIES

Physical


White powder 1.6 Not applicable Not applicable

Chemical


Enzymes and acid blend Soluble (water) Not determined Not applicable

APPLICATION Can-Break EBS is an enzyme acid blend designed to breakdown and consume most polymer chains excluding Xanthan gums. Can-Break EBS works best in systems where down hole temperatures are below 60οC and the pH of the fluid has been reduced to 5.0 or below. Can-Break EBS should be added to the mud system over one complete circulation so that it will be dispersed evenly throughout the entire system. Regular dosage rates of 2.5-3.5 kg/m3 will usually reduce viscosity within 24 hours. Can-Break EBS also provides a clean, economical method of reducing viscosity in polymer systems when separation of the liquid and solid phase is required for disposal. Note: Will not break Xanthan Polymers. MIXING AND HANDLING Can-Break EBS can be added directly to the mud system through the mixing hopper. It is advisable to use a dust mask and eye protection while mixing all powdered products. In case of contact, immediately flush with copious amounts of water. Flush eyes with flowing water immediately and continuously for 20 minutes. See a physician if necessary. Remove contaminated clothes and shoes. Wash clothes before re-use. Employ eye and skin protection when handling this product.


TDG: Not regulated

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PACKAGING: 22.7 kg sack

7.22

CAN-BREAK I Return to Table of Contents

DESCRIPTION

Can-Break I is a water-soluble chemical breaker for organic polymers. PROPERTIES

Physical


White granular powder 2.4 Not available Not applicable

Chemical


Oxidizing agent Soluble (water) 6.5-7.5 Not applicable

APPLICATION Can-Break I is a blend of oxidizers designed to react with and degrade organic polymers. Can-Break I is specially designed to work in fluids with temperatures above 40ºC. Can-Break I should be added to the mud system over one complete circulation so that it will be dispersed evenly throughout the entire system. Regular dosage rates of 2.53.5 kg/m3 will usually reduce viscosity within 24 hours. Can-Break I also provides a clean, economical method of reducing viscosity in polymer systems when separation of the liquid and solid phase is required for disposal purposes. MIXING AND HANDLING Can-Break I can be added directly to the mud system through the mixing hopper. Avoid contact with eyes, skin and clothing. It is advisable to use a dust mask and eye protection while mixing all powdered products. In case of contact, immediately flush with copious amounts of water. Flush eyes with flowing water immediately and continuously for 20 minutes. See a physician if necessary. Remove contaminated clothing. Wash clothes before re-use. Note: Do not mix with organic solvents or oil.



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PACKAGING: 22.7 kg sack

7.23

CAN-FREE Return to Table of Contents

DESCRIPTION

Can-Free is a viscous, blend of proprietary surface-active agents (sulfonates) to free differentially stuck pipe. PROPERTIES

Physical


Amber liquid, petroleum odor 0.96 Not determined 73.3ºC (TCC)

Chemical


Blend Dispersible (water) Not determined =30% @ (0.5 L/m3)

APPLICATION Can-Free is designed to penetrate and lubricate the medium between the drill pipe and the well-bore equalizing the pressure differences associated with differential sticking. To relieve differentially stuck pipe, mix 25.0 L/m3 of Can-Free to diesel or crude oil. Prepare a volume that is sufficient to more than fill the annulus for the entire “stuck” interval, leaving 1.0 m3 in the drill string. After displacement, let the Can-Free/Oil mixture "soak" for at least two hours before commencing to slowly pump an additional 0.2 m3 of spotting fluid every one-half hour while the drill string is being worked. NOTE: To increase the density of the spotting fluid, an organophilic clay (Oilgel 3000) must be added to the oil phase. Add the Can-Free and weighting agent once the desired viscosity has been achieved. Approximately, 10.0-30.0 L/m3 of Oilgel 3000 will be required depending on the final density. MIXING AND HANDLING Avoid eye and skin contact. Should contact occur flush thoroughly with water. When Can-Free is added directly to the mud, some shear or moderate agitation should be applied. As a spotting fluid, Can-Free mixes readily with diesel or crude oil.


TDG: Not regulated

Page-255

PACKAGING: 60 litre drum

7.24

CAN-EX Return to Table of Contents

DESCRIPTION

Can-Ex is a polymeric additive designed to enhance the yield of Bentonite. PROPERTIES

Physical


White to pink granules .90 Not determined Not determined Not applicable

Chemical


Polymer Dispersible-Soluble Not determined >75% @ (0.14 kg/m3)

APPLICATION Can-Ex is used primarily in low solids drilling fluids. Its principal function is to increase the yield of Bentonite and minimize the accumulation of drilled solids by the selective flocculation of low yield clays and shales. When Can-Ex is used in conjunction with Lime and Calcium Chloride it becomes a total flocculant suitable for use in clear water drilling. The optimum Bentonite/Can-Ex ratio for obtaining the maximum yield from the Bentonite is 5:1. For any Bentonite, over treatment with Can-Ex will result in a decrease in the Bentonite yield. This is especially true of those Bentonites, which are peptized, or beneficiated in the manufacturing process. MIXING AND HANDLING Can-Ex is usually added in conjunction with Bentonite through the mud-mixing hopper. Additions should be slow and even in order to avoid lumping. It is advisable to use a dust mask and eye protection while mixing all powdered products.


TDG: Not regulated

Page-256

PACKAGING: 50 lb carton (25 x 2 lb plastic bottles)

7.25

CAN-OIL FLC Return to Table of Contents

DESCRIPTION

Can-Oil FLC is a primary fluid loss control additive with secondary application as a rheology modifier for any oil based drilling fluids, with particular application in weighted systems. Can-Oil FLC in conjunction with Gilsonite HT will provide lower fluid-loss values than can be achieved with Gilsonite HT alone. PROPERTIES

Physical

Appearance: Specific Gravity: Pour Point: Flash Point:

Clear pale amber liquid 1.08 -10ºC >100ºC

Chemical


Surfactant Soluble (water) 6.5-8.0 Not applicable

APPLICATION Can-Oil FLC functions as a fluid loss control agent and rheological modifier in oil based drilling fluid systems. Can-Oil FLC is particularly suited to weighted “all-oil” systems where the lack of an emulsion produces inherently high fluid losses. Concentrations will fall in the range of 2.0-10.0 L/m3 depending on fluid loss requirements. MIXING AND HANDLING Can-Oil FLC may be added directly to the mud system. Skin and eye protection should be observed. See MSDS.


TDG: Not regulated

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7.26

CAUSTIC POTASH (90% KOH Flake) Return to Table of Contents

DESCRIPTION

Potassium Hydroxide (KOH) or Caustic Potash is a basic alkali used in a variety of industrial processes. Its advantage over Caustic Soda (NaOH) in the oil well drilling industry is that it also provides a source of K+ ions while providing pH control. PROPERTIES

Physical

Appearance: Specific Gravity: pH: Melting Point: Flash Point:

White flakes odorless 2.04 @ 20ºC 12.0 (0.01 moles/litre) 400ºC Non-flammable

Chemical


Alkali Hydroxide Soluble (water) 12.0 (0.01 moles/liter) Not applicable

APPLICATION

Potassium Hydroxide is a strong alkali used to increase pH and alkalinity of drilling, work over and completion fluids. MIXING AND HANDLING Potassium Hydroxide is a strong alkali and produces a strong basic solution. The reaction with water generates heat. Always add potassium hydroxide to water and watch for bubbling and splashing. Potassium Hydroxide will cause severe burns and skin/eye contact is to be avoided at all times. Wear full clothing, rubber gloves and goggles or face mask. The use of a rubber protective apron is also recommended. In the event of contact wash immediately with water for at least fifteen minutes. Seek medical attention, especially if burning persists or the contacted area is inflamed. It is advisable to use a dust mask and eye protection while mixing all powdered products.



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7.27

CAUSTIC SODA Return to Table of Contents

DESCRIPTION

Caustic Soda or Sodium Hydroxide (NaOH) is generally available in a white pelletized form. PROPERTIES

Physical


White pellets odorless 2.13 1169 kg/m3 Not applicable

Chemical


Sodium Hydroxide 100% Soluble (water) 13.0 (1% solution) Not applicable

APPLICATION Caustic Soda is a strong alkali used to increase the pH and alkalinity of the liquid phase. For a given pH, the amount needed is affected by many drilling additives and formation related factors. MIXING AND HANDLING Caustic Soda is a strong alkali and produces a strong basic solution. The reaction with water generates heat. Caustic Soda will cause severe burns and skin/eye contact is to be avoided at all times. To avoid contact, wear a protective apron, full clothing, rubber gloves, goggles and face mask. In the event of contact wash immediately with water for 15 minutes. Seek medical attention if burning persists or if the contacted area is inflamed. *DANGER* Always add Caustic Soda to the water and watch for bubbling and splashing. WHMIS: Controlled (see MSDS)

TDG: Regulated (see MSDS) PACKAGING: 50 lb sack

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7.28

CELLOPHANE Return to Table of Contents

DESCRIPTION

Clear multi-sized flakes of polycellulose, with an average size of 9.5mm (3/8"). PROPERTIES

Physical


Polycellulose flakes 1.0 Not determined Not determined Not determined

Chemical


Lost circulation material Not soluble (water) Not determined Not applicable

APPLICATION Cellophane is used to provide a sealing agent supplement to other lost circulation material in water based drilling muds. It is also a basic additive in cement slurries, providing a matting effect in the control of losses. Typical rates of addition up to 2% by wt. cement are used as a preventative measure. MIXING AND HANDLING Mix into a viscous mud with agitation. Cellophane will not pass through the shaker screen. In order to maintain the Cellophane concentration in the mud the shale shaker must be by-passed. Note: Bypassing the shaker could result in plugged jets. For cement applications add the Cellophane to the cement slurry in the mix tub prior to displacement. No special mixing precautions are required when mixing Cellophane.


TDG: Not regulated

Page-260


7.29

CHEMCIDE Return to Table of Contents

DESCRIPTION

This product is a registered Biocide under Agriculture Canada's "Pest Control Products Act". (Registration # 22316). Chemical family: N-Coco Alkyltrimethylenediamine acetates. PROPERTIES Physical


Yellow-orange liquid, ammonia vinegar odor 1.05 >100ºC (PMCC)

Chemical


Bactericide Soluble (water) 7.5-8.0 =11% @ (0.1 L/m3)

APPLICATION In drilling, well completion, work-over and stimulation applications, for control of algae, slime forming and sulfate reducing bacteria. Dosage levels of up to 1500mg/L (active) in normal situations and up to 3000 mg/L (active) for severe contamination are suggested. In packer fluids, doses up to 300mg/L (active) are recommended. Product Dosage Rate for Proper Concentration of Active Ingredient mg/L of Active Ingredient Treatment Rate of Chemcide (L/m3) 150 0.75 300 1.50 500 2.50 1000 5.00 1500 7.50 3000 15.00 Chemcide finds application in Secondary Oil Production, Petroleum Transport Storage Systems, Surface Equipment and in general industrial areas.

MIXING AND HANDLING Chemcide should be added at a point of low agitation to avoid foaming problems. Utilize eye/skin protection and dust mask when mixing. Notice to user: Chemcide is a controlled product to be used only in accordance with the directions on the product label. It is an offence under the "Pest Control Products Act" to use a controlled product within unsafe conditions. WHMIS: Controlled (see MSDS)

TDG: Not regulated

Page-261


7.30

CHEM-CLEAN (Rig Wash) Return to Table of Contents

DESCRIPTION

Chem-Clean (Rig Wash) is an environmentally friendly and biodegradable organic solvent-based degreaser.

PROPERTIES


Physical Clear liquid, Citrus odor 0.9397 Not available 48ºC (TCC)

Chemical Type: Degreaser Solubility: Soluble (water) pH: 4.2 Microtox: Pending

APPLICATION Chem-Clean is a powerful organic solvent degreaser, emulsifier and deodorizer designed to remove oil and grease in many cleaning applications. Chem-Clean can be used effectively in rig cleanup of any kind but particularly in areas where hydrocarbon residues need to be removed. Chem-Clean contains no petroleum distillates, and can be applied neat or diluted with water depending on the difficulty of a particular cleanup. MIXING AND HANDLING

For extra heavy duty degreasing Chem-Clean can be used full strength. For routine cleaning use Chem-Clean diluted at 1:5 ratio with water. Skin and eye protection should be observed (see MSDS). Do not use Chem-Clean on hot surfaces and hot or running motors.


TDG: Not regulated

Page-262


7.31

CHEMFOAM Return to Table of Contents

DESCRIPTION

CHEMFOAM is a blend of surfactants designed for maximum foam height and half-life in all types of waters. CHEMFOAM is a special derivative of a sodium fatty alcohol ethoxy sulfate blended with amphoterics, solubilizers, and water. PROPERTIES

Physical


Amber liquid 1.0 -15ºC 28ºC (Tag CC)

Chemical


Surfactant blend Soluble (water 100%) 7.0-8.0 Not applicable

APPLICATION CHEMFOAM may be used for foam drilling in fresh or brackish water, and is compatible with up to 15% hydrocarbon combination. CHEMFOAM is easily dispersible in water. It produces high foam volumes in fresh or brackish water, and waters contaminated with hydrocarbons. CHEMFOAM has high solids and hydrocarbon tolerance. MIXING AND HANDLING Utilize eye/skin protection and dust mask when mixing. Add directly to make-up water with mild agitation to ensure even mixing or inject directly into water line with a chemical pump capable of metering proper treatment levels. If polymers are to be used, premix them in the make up water.



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7.32

CHEMOIL-BREAK Return to Table of Contents

DESCRIPTION

Chemoil-Break is a breaker for the Chemoil mud system. Chemoil-Break is a component part of the Chemoil mud system and has no application in other mud systems. Chemoil-Break is designed to break the system back to base oil and release any colloidal solids. PROPERTIES

Physical


Clear liquid 1.18 Not determined Not flammable

Chemical


Caustic surfactant Miscible (water) >13.0 Not applicable

APPLICATION Chemoil-Break is designed exclusively for use in the Chemoil system. It is very important to pilot test Chemoil-Break prior to treatment. Chemoil-Break will break the viscosity of the system allowing fine particles be easily removed. Use the minimum amount of Chemoil-Break required. If the system is not over treated, it can be re-gelled with Chemoil-Buff to neutralize the breaker or by adding Chemoil-pH. Additions of any Chemoil product will vary depending on the type of base oil being used. MIXING AND HANDLING Chemoil-Break may be added through the hopper or anywhere there is sufficient agitation. Rubber gloves, rubber apron a mask and skin and eye protection should be used when adding Chemoil-Break. Wash any contaminated clothing prior to re-use.



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7.33

CHEMOIL-BUFF Return to Table of Contents

DESCRIPTION

Chemoil-Buff is a buffering agent for the Chemoil mud system. Chemoil-Buff is a component part of the Chemoil mud system it has no application in other mud systems. PROPERTIES

Physical


Clear liquid 1.2 100ºC Not flammable

Chemical


Acid mixture Soluble (Oil) <3.0 Not applicable

APPLICATION Chemoil-Buff is a buffering agent for the Chemoil system. It is designed to buffer the pH of the fluid to a range of 3.0 – 5.0 prior to the addition of Chemoil-Gel and ChemoilLink. Full yield will be achieved in 6-10 hours. Should a shorter yield time be required add more Chemoil-Buff. Additions of any Chemoil product will vary depending on the type of base oil being used. NOTE: Test the pH using approximately a 5cc sample of oil. Dilute the sample to a range of 3.0–5.0, with approximately 50cc of distilled water. Shake the mixture and test the pH of the water in the conventional manner. MIXING AND HANDLING It is recommended that Chemoil-Buff be added to the system in the range of 0.751.5 L/m3. If premixed in a liquid mud plant, 0.75 L/m3 should be sufficient. Rubber gloves, rubber apron a mask and skin and eye protection should be used when adding Chemoil-Buff. Wash any contaminated clothing prior to re-use.


TDG: Not regulated

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7.34

CHEMOIL-GEL Return to Table of Contents

DESCRIPTION

Chemoil-Gel is a viscosifier for the Chemoil mud system. Chemoil-Gel is a component part of the Chemoil mud system it has no application in other mud systems. PROPERTIES

Physical


Amber liquid glycol odor 1.19 Not determined Not combustible

Chemical


Silica gellant Very soluble (Oil) 4.0-5.0 Not applicable

APPLICATION Chemoil-Gel is designed exclusively for use in the Chemoil system. Chemoil-Gel and Chemoil-Link are added in a 1:1 ratio. Concentrations range from 1.5-9.0 L/m3 depending on the type of oil to be gelled. The nominal concentration is 3.0 L/m3. Additions of any Chemoil product will vary depending on the type of base oil being used. MIXING AND HANDLING Chemoil-Gel may be added through the hopper or anywhere there is sufficient agitation. Rubber gloves, a rubber apron, mask and skin and eye protection should be used when adding Chemoil-Gel. Wash any contaminated clothing prior to re-use.


TDG: Not Regulated

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7.35

CHEMOIL-LINK Return to Table of Contents

DESCRIPTION

Chemoil-Link is an activator for the gellant (Chemoil-Gel) in the Chemoil mud system. Chemoil-Link is a component part of the Chemoil mud system it has no application in other mud systems. PROPERTIES

Physical

Appearance: Specific Gravity: Boiling Point: Melting Point: Flash Point:

Amber liquid 0.93 >100ºC <-35ºC >71ºC

Chemical Type: Solubility: pH: Microtox:

Blend Insoluble (water) Not applicable Not applicable

APPLICATION Chemoil-Link is designed exclusively for use in the Chemoil system. Chemoil-Link and Chemoil-Gel are added in a 1:1 ratio. Concentrations range from 1.5-9.0 L/m3 depending on the type of oil to be gelled. The nominal concentration is 3.0 L/m3. Additions of any Chemoil product will vary depending on the type of base oil being used. MIXING AND HANDLING Chemoil-Link may be added through the hopper or anywhere there is sufficient agitation. Rubber gloves rubber apron, a mask, skin and eye protection should be used when adding Chemoil-Link. Wash any contaminated clothing prior to re-use.



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7.36

CHEMOIL PRODUCTS (General) Return to Table of Contents

BASE OILS:

The types of crude used should be the light green and brown oils. Black crude should be avoided, as it could take up to six times more product to viscosify. Diesel oil and/or distillates can be used if the flash points are acceptable.

GROUPS:

The two basic products are CHEMOIL-GEL and CHEMOIL-LINK. The gellant CHEMOIL-GEL is a metallic silicone derivative and is used in concentrations of 1.5 to 9.0 l/m3. The nominal concentration is about 3.0 l/m3. These concentrations are dependent on the type of oil to be gelled. The activator for the gellant is CHEMOIL-LINK. This is a phosphate ester derivative. It must be used at the same concentration as the CHEMOIL-GEL, for every litre per cubic metre of gellant use a litre of activator. Prior to mixing the gellant and activator, add the buffering agent, CHEMOIL-BUFF, recommended use, 0.75 to 1.5 l/m3. If premixed, in a liquid mud plant, 0.75 L/m3 may be sufficient. After the buffering agent has been added, begin to add the gellant and activator. It will take approximately six to ten (6-10) hours to reach the full yield. If a faster yield time is required add more buffering agent. Again, pilot testing is a must for each crude being used. The product CHEMOIL-pH is a strong acid buffering agent containing phosphoric acid. Use CHEMOIL-pH if encountering alkaline material such as Calcium Carbonates. It is also used prior to weighting up with calcium carbonates. Chemoil-pH may also be used if a rapid boost in the yield point is required. This would be in lieu of adding more gellant and activator. Pilot testing is strongly recommended. CHEMOIL-THIN is a weakly alkaline material capable of gently thinning back the system if no CHEMOIL-pH has been used. If CHEMOIL-pH has been used, it must be neutralized with CHEMOILBREAK prior to adding CHEMOIL-THIN. Since there are minor differences between batches when these products are made, it is always a good idea to titrate the CHEMOIL-pH with the CHEMOILBREAK to determine how much breaker is required to neutralize the CHEMOIL-pH.

Page-268

CHEMOIL-BREAK is used to break the CHEMOIL system back to the base oil. Use the minimum amount to break the system. This will require pilot testing prior to adding the breaker. Once broken the oil can be easily separated from the colloidal drill solids which may be carried in the CHEMOIL system. If the system is NOT over treated with CHEMOIL-BREAK the crude may be re-gelled by adding either CHEMOIL-BUFF to neutralize the breaker or by adding CHEMOILpH. The CHEMOIL-DFM defoamer is a silicone based defoaming agent. It will require a small amount to effectively defoam the CHEMOIL system. CHEMOIL system does not follow the traditional Bingham plastic model. Experience has shown that lower yields in the range of 2.5 to 4.0 Pa. are more than sufficient to clean the hole in horizontal wells. This is a highly elastic fluid and behaves differently than conventional polymer systems. Hole cleaning is a function of the elastic modules than of the traditional yield point. The optimum range for hole cleaning is 3.00 to 6.00 l/m3 of gellant and activator. PRECAUTIONS:

Do not use zinc-based pipe dope, zinc carbonates, or zinc oxide. Use Copper Kote or equivalent for pipe dope. The zinc will kill the viscosifier and the viscosity will not be recoverable. Do NOT drill cement with this system. When drilling out the shoe or doing squeezes use water or a water-based system. Do not add any alkaline material like amines or other scavengers for H2S. Pilot testing is very important. Always pilot test before making any additions or modifications, this eliminates surprises.

WHMIS:

All Chemoil products are controlled (see M.S.D.S.)

TDG:

Chemoil-Break (regulated) Chemoil-Buff (not regulated) Chemoil-DFM (regulated) Chemoil-Gel (not regulated) Chemoil-Link (regulated) Chemoil-pH (regulated) Chemoil-Thin (not regulated)

PACKAGING:

20 litre pails

Page-269

7.37

CHEMUL-I Return to Table of Contents

DESCRIPTION

Chemul-I is a primary oil mud emulsifier and is a blend of stabilized fatty acids in liquid form that reacts with lime to form a soap-based emulsifier. PROPERTIES

Physical


Dark amber diesel odor .90 Not determined 65ºC (PMCC)

Chemical


A blend of stabilized fatty acids Not soluble (water) 7.0-8.0 Not applicable

APPLICATION Chemul-I forms a stable water-in-oil emulsion when it is added to oil and water mixtures in conjunction with lime and proper agitation. 1. Provides suitable emulsion stability. 2. Compatible with other primary and supplemental emulsifiers. 3. Higher concentrations improve filtration control. MIXING AND HANDLING Oil mud systems using Chemul-I are easily prepared using the proper amounts of oil, water, Chemul-I and electrolytes to form a tight emulsion. The standard system uses 25.0-35.0 L/m3 of Chemul-I with equal parts of Hot Lime. The lite system uses 9.0-17.0 L/m3 of Chemul-I with equal parts of Hot Lime. In this system, Chemul-II becomes the supplemental emulsifier. Employ rubber gloves, rubber apron, and skin and eye protection and ensure mixing is done in an area with adequate ventilation.


TDG: Not regulated

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7.38

CHEMUL-II Return to Table of Contents

DESCRIPTION

Chemul-II is a secondary oil mud emulsifier and is a sulfonated amido amine, blended with wetting agents to be used as a co-emulsifier with Chemul-I or other similar primary emulsifiers. The carrier used in this product is non-toxic and non-hazardous. PROPERTIES

Physical


Dark-amber liquid .93 73.3ºC (TCC)

Chemical


Blend of sulfonated amido amine derivatives Dispersible (water) 6.0-8.0 (10% solution) Not applicable

APPLICATION Chemul-II forms a stable water-in-oil emulsion when it is added to oil and water mixtures with proper agitation. Oil mud systems using Chemul-II are easily prepared using the proper amount of oil, water, and electrolytes to form a tight emulsion. The standard system uses 4.0-10.0 L/m3 of Chemul-II. The lite system uses 8.0-16.0 L/m3 of ChemulII. In this system, Chemul-I becomes the supplemental emulsifier. 1. 2. 3. 4. 5.

Provides emulsion stability. Not affected by electrolyte concentrations in water phase. Compatible with other primary and supplemental emulsifiers. Imparts high temperature stability. May be used as an oil-wetting surfactant.

MIXING AND HANDLING Employ rubber gloves, rubber apron, skin and eye protection and ensure mixing is done in an area with adequate ventilation.



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7.39

CHEMWET-OM Return to Table of Contents

DESCRIPTION

Chemwet-OM is a blend of alkanolamides and phospholipids used as an oil wetting agent. This product is designed to be used as an oil-wetting agent in any oil mud system. PROPERTIES

Chemical

Physical Appearance: Specific Gravity: Melting Point: Boiling Point: Flash Point:

Dark amber liquid rancid odour .97 -5ºC Not determined 65ºC (Pensky-Martens)

Type:

Blend of alkanolamides and phospholipids Not soluble-dispersible Not determined Not applicable

Solubility: pH: Microtox:

APPLICATION Chemwet-OM is a surfactant blend, which improves oil wetting properties of oil mud systems. The product efficiently oil wets drill solids and weight material carried in an oil mud system. 1. 2. 3. 4. 5. 6.

Provides emulsion stability. Not affected by electrolyte concentrations in water phase. Compatible with other primary and secondary emulsifiers. Improves rheological properties. Oil-wets water-wet drill solids. May improve filtration properties.

MIXING AND HANDLING

Oil mud systems use 0.3-3.0 L/m3 of Chemwet-OM. The product is used as required for maintaining proper rheological and fluid loss properties when solids tend to become water wet. Employ rubber gloves, rubber apron, skin/eye protection and ensure mixing is done in an area with adequate ventilation.


TDG: Not regulated

Page-272


7.40 CITRIC ACID (Anhydrous) Return to Table of Contents

DESCRIPTION

Anhydrous Citric Acid (C6H807) is a multi-purpose weak organic acid. It is widely used in the food, beverage and detergent industry, and also finds some oilfield applications. Citric acid is relatively non-toxic, non-corrosive and is biodegradable. PROPERTIES

Physical


White powder or granules 1.66 153ºC Not applicable

Chemical


Organic acid Soluble (60% @ 20ºC) 2.2 (1% solution) Not applicable

APPLICATION Anhydrous Citric Acid is widely used in oilfield completion and stimulation operations as an iron sequestrate. It can also aid in reducing water requirements and in retarding of oil well cements. Because of its ease and relative safety of handling, Citric Acid can be used in the pH adjustment of drilling fluids, completion fluids and industrial / oil-well waste fluids. MIXING AND HANDLING Although Citric Acid is of low hazard and toxicity, excess exposure to dust should be avoided to prevent irritation to the eyes, skin and respiratory tract. Use good industrial hygiene practices, wear goggles and a dust mask when handling the material. Ensure that the work area is sufficiently ventilated to avoid dust build-up and wear protective clothing to prevent excess skin contact. Citric acid is non-flammable. As with all organic material, caution is advised when storing or handling near strong oxidizing agents, alkali metals or strong bases.


TDG: Not regulated

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7.41

CMC Return to Table of Contents

DESCRIPTION

Sodium Carboxymethyl Cellulose is a long chain cellulose colloid made in two viscosity ranges, CMC Regular, and CMC HiVis. The chain length has an effect upon fluid loss and viscosity. PROPERTIES

Physical


White powder 1.5 300-900 kg/m3 Not applicable

Chemical


Carboxymethyl Cellulose Soluble (water) 6.0-8.5 (1% solution) Pending

APPLICATION CMC is used primarily as a fluid loss reducer but also has suspension (viscosity) characteristics in all fresh water systems. CMC Regular and CMC HiVis are recommended when some degree of viscosity along with fluid-loss is desired. The fluidloss effectiveness of CMC is reduced significantly in salt concentrations above 30,000 mg/L. CMC may be used in alkaline muds to any pH value and is stable to l50ºC with use of oxygen scavengers. The normal range of addition for CMC is 1.5-3.0 kg/m3 in most water-based mud systems. The quality of water used to build the mud system and its degree of salinity will have an effect on the performance of the product. MIXING AND HANDLING Mix slowly through the mud hopper at approximately thirty to forty minutes per sack to avoid lumping and fish eyes. When wet, CMC becomes very slippery and must be absorbed with an inert material such as sawdust. Store in a dry area as CMC is very hygroscopic. Avoid breathing dust. It is advisable to use a dust mask and eye protection while mixing all powdered products.


TDG: Not regulated

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7.42

CORINOX Return to Table of Contents

DESCRIPTION

Corinox is a neutral to basic solution, which consists of a high performance catalyst, an efficient oxygen-scavenging agent, and selective organic filming substances. PROPERTIES Physical


Pale blue-green liquid 1.25 -15º C >150º (PMCC)

Chemical


Oxygen scavenger Soluble (water 100%) 6.8-7.4 >75% @ (1.0L/m3)

APPLICATION Corinox is a unique dual-purpose corrosion prevention chemical mixture in a liquid form. It has the ability to scavenge dissolved oxygen effectively as well as the capability to adsorb onto active corrosion sites (anodes) on drill pipe, casing and tubing in water based fluids. Because of its filming ability, Corinox can reduce or prevent corrosion from small quantities of carbon dioxide and/or hydrogen sulfide. Unlike organic amines (cationic) that coat on solids, Corinox's organic components (anionic) do not adsorb onto solids in the drilling fluid and have very little effect on the rheology of water base drilling fluids. Under normal conditions, for a program with a corrosion level of ±25 mpy, initially add one pail of Corinox per 16 m3 of fluid to be treated. Severe corrosion rates may require higher concentrations. To assess the requirement of Corinox in any condition, it is best to use a corrosion rate method such as corrosion ring analysis or an instantaneous corrosion monitor. If high corrosion rates persist and are determined to be oxygen related, supplemental additions of an oxygen scavenger such as Sodium Sulfite should be made to the system. MIXING AND HANDLING Corinox does not require any cumbersome equipment such as manual or automatic injection systems; therefore, it eliminates the problems of equipment failure and the cost of equipment rental and maintenance. Avoid contact with eyes, skin and clothing. In case of contact, immediately wash with plenty of water. Flush eyes with flowing water immediately and continuously for twenty minutes. See a physician if necessary. Remove contaminated clothes and shoes and wash before re-use. WHMIS: Controlled (see MSDS)

TDG: Not regulated

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7.43

CORRIN O/S Return to Table of Contents

DESCRIPTION Corrin O/S is an amine blend in a hydrocarbon base. PROPERTIES

Physical


Dark amber liquid .90-.92 204-371ºC 104ºC (PMCC)

Chemical


Filming amines Dispersible (water) Not determined Not applicable

APPLICATION Corrin O/S is an effective oil soluble, brine dispersible corrosion inhibitor for all oil based drilling fluids. It is a tenacious film forming amine that protects the drill string, casing and rig equipment against corrosion caused by Hydrogen Sulfide (H2S), Carbon Dioxide, organic and mineral acids. To film the pipe Corrin O/S can be added directly to the mud system as a batch treatment or by continuous injection. Recommended concentrations are 1.0-5.0 L/m3. Daily maintenance and corrosion monitoring is recommended to optimize protection of tubulars. MIXING AND HANDLING Avoid inhalation of vapours. Do not get on skin, in eyes or on clothing. Keep container closed when not in use. Wear suitable protection for eyes and skin when handling. Use in well ventilated areas. Avoid contact with incompatible materials (see MSDS).


TDG: Not regulated

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7.44

CYPAN Return to Table of Contents

DESCRIPTION Cypan is a synthetic medium molecular weight Sodium Polyacrylate. Cypan is not subject to bacterial decomposition and will tolerate temperatures to 205ºC. PROPERTIES

Physical


Light yellow powder Not available Not available <7.0% Not applicable

Chemical


Polyacrylate Soluble (water) Not determined =63% @ (2.0 kg/m3)

APPLICATION Used in an alkaline environment, Cypan acts as a fluid loss reducing agent by adsorbing onto the clay platelets and cross-linking them to form a thin, tough filter cake. When Cypan is added to a flocculated mud system, deflocculation occurs and it may be difficult to regain viscosity. Cypan should not be used in mud systems containing excess calcium salts in solution. For all mud systems in which it is used, the concentration of Cypan is usually in the range of l.0-3.0 kg/m3. MIXING AND HANDLING Due to the attachment of Cypan to clay particles a viscosity hump may occur when it is first added to a mud system, especially when there is a high solids concentration. To minimize this hump, the Cypan should be added to the mud system through the hopper as rapidly as mixing will permit in order to obtain a concentration of approximately l.5 kg/m3 in the first circulation. (Maximum addition rates are 15-20 minutes per sack). Once the initial addition has been made the Cypan is usually added at thirty to forty minutes per sack. It is advisable to use a dust mask and eye protection while mixing all powdered products.


TDG: Not regulated

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7.45

DEFOAMER SILICONE Return to Table of Contents

DESCRIPTION Defoamer Silicone is a 10% silicone emulsion. PROPERTIES

Physical


Opaque-white liquid .98-1.02 Not applicable Not flammable

Chemical


Silicone emulsion Dispersible (water) Not available >75% @ (0.5 L/m3)

APPLICATION Defoamer Silicone is a versatile liquid defoamer that can be used to combat mild to severe foaming. It may also be premixed as an anti-foaming agent in the preparation of fluids, which require vigorous agitation, or with products that are known to have foaming tendencies. Defoaming is a complex reaction, and pilot testing may be necessary to determine optimum treatment rates and methods. Recommended treatment concentrations will vary depending on the severity of foaming, however 0.15-0.20 kg/m3 should be effective in most cases. MIXING AND HANDLING For maximum effectiveness Defoamer Silicone should be added directly to the fluid system as close to the point of foaming as possible. It can also be mixed through the hopper if necessary.

Avoid contact with eyes, skin and clothing. In case of contact, immediately wash with plenty of water, flush eyes with flowing water immediately and continuously for 15 minutes. See a physician if necessary.


TDG: Not regulated

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7.46

DESCO CF Return to Table of Contents

DESCRIPTION

Desco CF is a tannin-based thinner used in water-based drilling fluids. PROPERTIES

Physical


Fine reddish brown powder with white specks 1.5-1.7 Not applicable

Chemical


Thinner Soluble (water) Not available >100% @ (3.0 kg/m3)

APPLICATION Desco CF is used to control rheological properties in water based drilling fluids. Desco CF is an alkaline material, which is effective in a wide pH range (optimum is suggested at 9.0-11.0) in fresh water and salt-water muds. Desco CF is highly effective at low concentrations and is compatible with all other mud additives. Desco CF scavenges oxygen from the mud system, which assists in reducing corrosion and in extending the thermal stability of mud systems. Normal addition ranges for Desco CF are 0.5-7.0 kg/m3 depending upon the application. Desco CF is a very effective thinner in most systems and only low concentrations are generally required. MIXING AND HANDLING Desco CF can be mixed directly through the mud hopper. It is advisable to use a dust mask and eye protection while mixing all powdered products. Desco CF may cause irritation to the eyes. If contacted with the eyes, flush immediately with running water for at least fifteen minutes. If irritation develops, seek medical attention.


TDG: Not regulated

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7.47

DRIL-DOKTOR Return to Table of Contents

DESCRIPTION

Dril-Doktor is a mixture of micronized organic cellulose fibers. Dril-Doktor is compatible with oil and water based drilling fluids. PROPERTIES

Physical


Light tan .613 Not available Not applicable

Chemical


Organic cellulose Not soluble (water) 7.0-8.5 (Distilled water) Not applicable

APPLICATION Dril-Doktor is generally used for controlling seepage and/or whole mud losses while drilling through depleted or under pressured zones. It may also be added as a fine bridging agent in mixtures of lost circulation pills. Dril-Doktor is most effective for controlling seepage losses in concentrations of 10.03 25.5 kg/m . For applications such as sweeps to plug thief zones, etc. concentrations as high as 85.0 kg/m3 may be required. MIXING AND HANDLING Dril-Doktor can be mixed through the mud hopper or directly into the mud tank at a point of agitation. It is advisable to use a dust mask and eye protection while mixing all powdered products. A dust hazard is present while Dril-Doktor is being mixed.


TDG: Not regulated

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7.48

DRILLING DETERGENT “L” Return to Table of Contents

DESCRIPTION

Drilling Detergent L is an anionic, liquid, surface wetting agent. PROPERTIES

Physical


Medium blue liquid 1.0 -15ºC >80º (CC)

Chemical


Surfactant Soluble (water) 7.0-8.0 >75% @ (0.4 L/m3)

APPLICATION Drilling Detergent L can be added directly to the mud system and is normally used in concentrations of 0.2-0.6 L/m3. Drilling Detergent L is added to water based mud systems to reduce surface tension in order to gain the following advantages: 1. 2. 3. 4. 5. 6. 7.

Promotes solids settling and reduces pump pressure. Improved sampling through cleaner samples and more distinct cuttings. Increased penetration rates. Reduced hole friction and torque. Reduced bit balling, mud rings and cake build-up on drill strings. Reduced wear on surface mud system expendables. Increased bit life.

MIXING AND HANDLING

Drilling Detergent L can be irritating to the skin and eyes. Inhalation may cause nausea, vomiting and dizziness. In case of skin contact wash with water. In case of eye contact flush with water for fifteen minutes and seek medical attention. If ingested induce vomiting immediately and get patient to a physician. This product contains Ethylene Glycol and lack of attention may cause kidney and liver damage.


TDG: Not regulated

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7.49

DRILLING DETERGENT “P” Return to Table of Contents

DESCRIPTION

Drilling Detergent P is an anionic, solid, surface wetting agent (surfactant). PROPERTIES

Physical


White granular beads Not determined Not applicable

Chemical


Powdered surfactant Not determined 11.3 >75% @ (1.0 kg/m3)

APPLICATION Drilling Detergent P can be added directly to the mud system. concentrations of 0.75-1.5 kg/m3.

Normally used in

Drilling Detergent P is added to water based mud systems to reduce surface tension in order to gain the following advantages: 1. 2. 3. 4. 5. 6. 7.


MIXING AND HANDLING Drilling Detergent P can be irritating to the skin and eyes. Inhalation may cause nausea, vomiting and dizziness. In case of skin contact wash with water. In case of eye contact flush with water for fifteen minutes and seek medical attention. It is advisable to use a dust mask and eye protection while mixing all powdered products.


TDG: Not regulated

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PACKAGING: 50 lb. pail

7.50

DRILSTAR HT Return to Table of Contents

DESCRIPTION

Drilstar HT is a premium quality white cornstarch, which provides a rapid reduction of API fluid loss at minimum concentrations. PROPERTIES

Physical


White granular powder Not available 512-560 kg/m3 Not applicable

Chemical


Pregelatinized cornstarch Soluble (water) 5.0-7.0 (4% solution) =47% @ (8.0 kg/m3)

APPLICATION Drilstar HT provides fluid loss control in all water based mud systems. In particular Drilstar HT finds applications in high hardness, high pH, Gypsum muds where bottom hole temperatures are not excessive. Drilstar HT is effective to temperatures of 120ºC. Drilstar HT performs best in an alkaline environment and will not increase the rheological properties of the mud system in which it is used. In the absence of a high pH and/or high salinity a bactericide such as T-352 should be used to prevent bacterial decomposition. Drilstar HT is used in concentrations ranging from 8.0-25.0 kg/m3 depending somewhat on the amount of drilled solids present in the mud system. Oxygen scavengers should be used to reduce thermal degradation. Caution: It has been demonstrated that produced crude oils can contain very persistent bacterial strains that may cause fermentation problems in mud systems with susceptible organic matter such as starch. Much larger treatment doses and/or addition of a secondary biocide may be required when crude oil is added to these drilling fluids. MIXING AND HANDLING Drilstar HT mixes readily. It may be added through the hopper at rates of 5-10 minutes per sack when required. It is advisable to use a dust mask while Drilstar HT is being mixed. WHMIS: Not controlled

TDG: Not regulated

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7.51

DRILSTAR (Yellow) Return to Table of Contents

DESCRIPTION

Drilstar (Yellow) (C6H10O5)n is a pre-gelatinized water-soluble polymer. In its powdered form it is commonly known as "Yellow Starch”. PROPERTIES

Physical


Yellow powder Not available 480-560 kg/m3 Not applicable

Chemical


Starch Soluble (water) 5.0-7.0 (4% solution) =60% @ (17.0 kg/m3)

APPLICATION Starch provides fluid loss control in all water based mud systems. In particular Drilstar finds applications in seawater, salt saturated, and high Calcium content mud systems where bottom hole temperatures are not excessive. Drilstar performs best in an alkaline environment and will not increase the rheological properties of the mud system in which it is used. Drilstar is effective to temperatures of 90º-100ºC. In the absence of a high pH and/or high salinity a bactericide such as T-352 should be used to prevent bacterial decomposition of the starch. Drilstar is used in concentrations ranging from 8.0-40.0 kg/m3 depending somewhat on the amount of drilled solids present in the mud system. Oxygen scavengers should be used to reduce thermal degradation. Caution: It has been demonstrated that produced crude oils can contain very persistent bacterial strains that may cause fermentation problems in mud systems with susceptible organic matter such as starch. Much larger treatment doses and/or addition of a secondary biocide may be required when crude oil is added to these drilling fluids. MIXING AND HANDLING Drilstar mixes readily. It may be added to the mud system through the hopper at rates of 5-10 minutes per sack when required. It is advisable to use a dust mask and eye protection while Drilstar is being mixed.


TDG: Not regulated

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7.52

DRISPAC REGULAR / SUPER LO Return to Table of Contents

DESCRIPTION

Drispac is a high molecular weight, polyanionic cellulose polymer of high purity. It is available in Regular and Superlo grades. PROPERTIES

Physical


Light colored powder 1.6 Not available Not applicable

Chemical


Cellulose fluid loss polymer Soluble (complete in water) 6.5-8.0 >100% @ (3.0 kg/m3)

APPLICATION Drispac is a primary fluid-loss reducer for water-based drilling fluids. Drispac Regular also provides secondary viscosity. When fluid loss control without additional viscosity is required, Drispac Superlo should be used. Both Drispac Regular and Superlo are used in concentrations of 3.0-10.0 kg/m3 in saline water based muds, whereas fresh water based mud systems normally use concentrations of l.0-3.0 kg/m3. Drispac can be used at temperatures up to 150C. MIXING AND HANDLING Drispac should be stored in a dry location. In order to avoid lumping it is added to the mud system through the hopper at 30-40 minutes per sack. It is advisable to use a dust mask and eye protection while mixing all powdered products.


TDG: Not regulated

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7.53

EMUL-BREAK Return to Table of Contents

DESCRIPTION

Emul-Break is a general batching demulsifier for problem emulsions, production, stimulation, and anti-sludge applications. PROPERTIES

Chemical

Physical Appearance: Specific Gravity: Boiling Point: Flash Point:

Aromatic amber liquid .916 83ºC 18ºC (TCC)


Demulsifier Dispersible (water) 8.78 =42% @ (1.0 kg/m3)

APPLICATION For Drilling Fluids: An addition rate of 0.25-1.0 L/m3 of drilling mud is recommended. Higher addition rates may be necessary for difficult situations. The possibility of foaming exits with increased concentrations of Emul-Break. Pretreat the system with 3-5 pails of XL or Silicone Defoamer prior to making increased additions. For Well Stimulation: Emul-Break in a 1.0-5.0% hydrocarbon solvent will stimulate oil production by reducing interfacial tension between oil, water and the producing formation. Emul-Break will remove emulsion blocks and act as a sludge dispersant removing solid particles. Caution: Emul-Break is a surface-active demulsifier. Emul-Break is a respiratory and digestive tract irritant that should be handled with care (See MSDS). MIXING AND HANDLING Emul-Break can be added directly to the mud on surface or through the mixing system. Avoid inhalation of vapors. Do not get on skin, in eyes or on clothing. Keep container closed when not in use. Wear suitable protection for eyes and skin when handling. Use with adequate ventilation. Avoid contact with incompatible materials (See MSDS). Store in cool, dry, well-ventilated area away from sources of heat, ignition and sparks. Use proper grounding techniques if product is classed as flammable or combustible. Avoid using natural rubber, use neoprene.



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7.54

ENKAPSAFLOC Return to Table of Contents

DESCRIPTION Enkapsafloc is a 30% hydrolyzed polyacrylamide in liquid form. PROPERTIES

Physical

Appearance: Specific Gravity: Pour Point Flash Point:

White liquid 1.02-1.04 -30ºC Not available

Chemical


Synthetic polymer Not available 6.5-7.5 (1% solution @ 25ºC) =52% @ (1.4 L/m3) HMW Anionic

APPLICATION Enkapsafloc can be used as a flocculant in conjunction with Ca++ or K+ to promote water clarification while clear-water drilling. It may also be added to K+ based or other shale stabilizing fluids to enhance the inhibition process. As a flocculant, it is added at the flow line at 1.0 L/30 meters of hole drilled to promote solids settlement in the mud pit or at a point just prior to mechanical separation equipment. As a shale inhibitor, the filtrate concentration should range from 0.5 L/m3 for slightly hydratable shales to 1.5 L/m3 for moderately hydratable shales. Gumbo shales may require concentrations as high as 3.0 L/m3. MIXING AND HANDLING As a flocculant Enkapsafloc can be mixed directly into water in the chemical barrel prior to addition at the flow line. In inhibitive muds Enkapsafloc should be added slowly through a chemical barrel at the suction to avoid fluctuations in viscosity. Note: Enkapsafloc becomes very slippery when in contact with water. A spill should be cleaned up immediately with an absorbent material. Wear eye and skin protection when mixing.


TDG: Not regulated

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7.55

ENVIROFLOC (Calcium Nitrate) Return to Table of Contents

DESCRIPTION

Envirofloc (Calcium Nitrate) is the hydrated double salt 5Ca(NO3)2·NH4NO3·10H2O. PROPERTIES

Physical


Off-white powder 1.12 1.06 kg/m3 Not available

Chemical


Salt Soluble (water) 6.0 (5% solution) =52% @ (1.4 kg/m3)

APPLICATION Envirofloc is an excellent source of Calcium for clear-water drilling. In moderate quantities nitrates are a plant nutrient and can ultimately be consumed, actually aiding in the goal of re-vegetation of well sites. Maintain a minimum of 250-400 mg/L of Calcium ion while floc-water drilling. Envirofloc can also be used as a Calcium source in invert oil emulsions and as an accelerator for oil well cement. MIXING AND HANDLING Envirofloc can be added through the hopper or pre-dissolved in water in the chemical barrel prior to being added. Note that in the presence of excess Hydroxide concentration (high pH), Ammonia gas will be liberated. Ammonia gas will irritate the nose, throat and respiratory system and can cause eye injury. It is advisable to use a dust mask and eye protection while mixing all powdered products. Store securely away from combustible materials and reducing agents.


TDG: Not regulated

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7.56

ENVIROPLUG MEDIUM AND #8 Return to Table of Contents

DESCRIPTION

Enviroplug Medium and Enviroplug #8 are granular Wyoming Bentonite chips, which can absorb 5 times their weight in water and swell to 12-16 times their dry bulk size. PROPERTIES

Physical

Appearance: Specific Gravity: Moisture: Flash Point: Grind Size:

Grey to tan granules 2.45-2.55 Not available Not applicable Medium (100% passing 3/8 inch mesh) #8 (97% passing 4 mesh)


Sodium Montmorillonite Not soluble (colloidal suspension) 8.0-10.0 (5% suspension) Not applicable

APPLICATION Enviroplug #8 and Enviroplug Medium are designed to seal surface and upper intermediate hole sections experiencing severe lost circulation. Enviroplug is poured directly down the hole where it rapidly swells and seals areas of severe lost circulation. It is not advisable to attempt to circulate an Enviroplug pill down the hole as rapid hydration will occur when the granules come in contact with water creating the potential of plugging even open-ended drill-pipe. MIXING AND HANDLING Add directly down the annulus. Avoid breathing dust. It is advisable to use a dust mask and eye protection while mixing all powdered products.


TDG: Not regulated

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7.57

EXTRA HIGH YIELD BENTONITE Return to Table of Contents

DESCRIPTION

Extra High Yield Bentonite is a highly concentrated, Polymer enhanced Sodium Montmorillonite. In distilled water, it yields a minimum 220 bbl/ton of 15 cps viscosity mud.

PROPERTIES

Physical


Pale gray to buff powder 2.45-2.55 880 kg/m3 Not applicable

Chemical


Sodium montmorillonite Not Soluble (forms a colloidal suspension) 8.0-10.0 (5% aqueous suspension) Not applicable

APPLICATION Extra High Yield is used for providing quick viscosity when necessary. It is especially advantageous in remote locations where transportation of large quantities of product is prohibitive or where small volumes of high viscosity mud are required. i.e. (seismic drilling, water well drilling, river crossings, etc.). The level of water purity will affect the performance of the Bentonite. Prior to mixing, acidic and/or hard water should be treated with Soda Ash to a pH of 8.5-9.0. MIXING AND HANDLING Mix directly through the hopper at no faster than 4-6 minutes per sack. A mask and goggles should be worn to prevent inhalation of dust and contact with the eyes. Fresh air ventilation should be provided in the mixing area.


TDG: Not regulated

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7.58

GILSONITE HT PULVERIZED Return to Table of Contents

DESCRIPTION

Gilsonite HT Pulverized is a naturally occurring hydrocarbon. It is mined and ground to the desired particle size. PROPERTIES

Physical


Black-brown powder 1.06 Not available 1.0% 316ºC

Chemical


Hydrocarbon resin Soluble (Aromatic/Chlorinated Solvents) Not available Not applicable

APPLICATION Gilsonite HT Pulverized is used to control API and HT-HP fluid loss in oil base drilling fluids. When mixed with Organophilic clays, Gilsonite HT’s particular grind size and softening point are ideal for reducing whole mud losses to the formation. Gilsonite HT Pulverized is only partially soluble in aromatic hydrocarbons. Recommended treatment 10.0-30.0 kg/m3. MIXING AND HANDLING Gilsonite HT Pulverized is relatively stable and of low hazard. However it should not be stored or used near strong oxidizing agents such as Chlorates, Nitrates or Peroxides. Excessive dust is subject to combustion or explosion upon contact with spark or open flame. Use good industrial hygiene practice to avoid eye and excess skin contact. Wear a protective dust mask and goggles when handling and mixing.


TDG: Not regulated

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7.59

GLASS BEADS Return to Table of Contents

DESCRIPTION

Glass Beads are specially sized, solid glass spheres made of high-grade crown glass of the Lime soda type. Glass Beads are chemically inert, free of impurities and nonpolluting. Seventy-five percent of these beads fall in a range between 170-325 mesh, with less than 10.0% retained on a 170 mesh screen. PROPERTIES

Physical

Appearance: Specific Gravity: Bulk Density: Moisture Content: Melting Point:

Clear glass beads 2.5-2.9 Not Available Not Available 600ºC

Chemical


Lime-Soda glass Not soluble Not available Not applicable

APPLICATION Glass Beads can be used in all water and oil based drilling fluids to reduce torque and drag and to aid in the prevention of differential sticking. They should have no measurable effect on the desired properties of the mud system and can be removed by a desilter or centrifuge. Adding and maintaining 8.0-12.0 kg/m3 of Glass Beads can achieve a reduction in torque and drag anywhere from 15.0 to 30.0%. The severity of hole problems and solids content will determine actual concentrations required. MIXING AND HANDLING Glass Beads should be added directly through the mixing hopper. It is advisable to use a dust mask and eye protection while mixing all powdered products. Note: Glass Beads will have the same effect as ball bearings on any hard surface. Post warning signs if spilled and sweep up immediately.


TDG: Not regulated

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7.60

GRAPHITE Return to Table of Contents

DESCRIPTION

Graphite has a greasy feel and very low coefficient of friction. Chemically, Graphite is the pure form of carbon. PROPERTIES

Physical


Black-gray powder 2.25 0.5% Not available

Chemical


Carbon Negligible Not available >75% @ (6.0 kg/m3)

APPLICATION Graphite is used as a torque reducer in directional or crooked holes when a water based mud system is being used. Torque reduction does not become significant until a concentration of 3.0 kg/m3 is exceeded. The optimum concentration is in the range of 6.0-7.0 kg/m3. MIXING AND HANDLING Graphite is added to the mud system through the mud-mixing hopper. Because it is extremely fine, it is recommended that a dust mask and goggles be worn while the graphite is being mixed. Note: Graphite will have the same effect as ball bearings on any hard surface. Post warning signs if spilled and sweep up immediately.


TDG: Not regulated

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7.61

GUAR GUM Return to Table of Contents

DESCRIPTION

Guar gum, chemically classified as a Galactomannan, is a high molecular weight carbohydrate Polymer or Polysaccharide made up of repeating mannose and galactose units. PROPERTIES

Physical


White-beige powder <1.2 Not available 6-12% Not applicable

Chemical


Galactomannan Soluble (water) 5.0-6.5 >75% @ (4.25 kg/m3)

APPLICATION Guar Gum is primarily used as a viscosifier in drilling, completion, workover and fracturing fluids. Guar Gum will provide viscosity in fresh or salty water and is typically used in concentrations of 3.0-6.0 kg/m3. The viscosity will degrade quite rapidly at temperatures in excess of 65º C. Like most organic matter, micro-organisms attack Guar Gum unless protected by high pH, high salinity or a biocide such as T-352. Hydrated Guar Gum can be cross-linked with a Borate ion to produce an extremely viscous suspension at a relatively low gum concentration. To produce the cross-link a pH of 9.0-10.0 is required. The cross-link can be reversed if the pH is lowered to neutral (7.0). The ratio of Guar Gum to sodium Tetraborate should be approximately 5:1. Guar Gum will generally reach maximum viscosity in 60-90 minutes but this will be dependent on factors such as temperature and water quality. MIXING AND HANDLING Guar Gum can be easily mixed through normal equipment such as hoppers or agitating mixers. Although generally recognized as being non-toxic and non-hazardous, care should be taken to have proper ventilation in mixing areas. It is advisable to use a dust mask and eye protection while mixing all powdered products. WHMIS: Not controlled

TDG: Not regulated

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7.62

GYPSUM Return to Table of Contents

DESCRIPTION

Gypsum (CaSO4•2H2O) is a naturally hydrated Calcium Sulfate and is only slightly soluble in water. PROPERTIES

Physical


Light gray powder 2.9 (rock) 1120-1424 kg/m3 Not applicable

Chemical


Inorganic Salt Slight (water) 6.5 Not applicable

APPLICATION Gypsum is used as the source of Calcium in clear-water drilling and in other inhibitive mud systems. In floc water drilling, normal concentrations of Calcium fall in the range of 250-400 mg/L. "Gyp based muds" are used for specific applications i.e. (drilling thick sections of anhydrite or cement). In a Gyp-Gel system, maintain the Ca++ at 400-600 mg/L to ensure the system maintains it “gypped-over” nature. Gypsum can also be added as a contaminant (in low concentrations) to Bentonite-based mud systems or as a source of Calcium for mud systems that are over treated with Soda Ash. MIXING AND HANDLING Gypsum can be added to the mud system through the mud hopper. In lightly treated Bentonite-based systems the mud will flocculate with consequent thickening and an increase in fluid loss.

Gypsum is hygroscopic; therefore it should be stored in a dry environment to avoid lumping and hardening. It is advisable to use a dust mask and eye protection while mixing all powdered products. A dust hazard is present while gypsum is being mixed.


TDG: Not regulated

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7.63

HEC 10 POLYMER Return to Table of Contents

DESCRIPTION HEC 10 polymer is non-ionic, high molecular weight Hydroxyethyl Cellulose designed to viscosify water-based fluids. PROPERTIES

Physical


Off-white powder 1.38-1.40 Not available 400ºC

Chemical

Type: Solubility: pH Microtox:

Hydroxyethyl Cellulose Soluble (water) Not available >91% @ (1.0 kg/m3)

APPLICATION HEC 10 has been surface treated to disperse rapidly and hydrate easily in water. A solution of 15% HCl will effectively break the viscosity of HEC 10. HEC 10 is a cost effective viscosifier/fluid loss control agent widely used in the following applications: - Low Solids Drilling Fluids - Completion and Workover Fluids (including acids) - Fracturing Fluids - Horizontal Drilling - Fluid Loss Control and Friction Reduction in Oilwell Cements and Spacers HEC 10 is compatible with all common drilling and completion fluid additives and will effectively viscosify clear brines ranging from low weight sodium chloride to saturated calcium chloride and bromide mixtures. In the absence of a high pH and/or high salinity, a bactericide such as T-352 should be used to prevent bacterial decomposition.

MIXING AND HANDLING Can be mixed directly through the hopper. When added to brines (in some mixing systems) the agitation may cause foaming to occur. Pre-treatment with appropriate defoamers (XL Defoamer, Foam Buster, Defoamer Silicone) should be considered if pilot tests indicate a potential foaming problem. It is advisable to use a dust mask and eye protection while mixing all powdered products. WHMIS: Not controlled

TDG: Not regulated

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7.64

HME COUPLER Return to Table of Contents

DESCRIPTION HME Coupler is a selective non-ionic surface-active agent. PROPERTIES

Physical


Clear liquid .88 159-205ºC 62ºC (TCC)

Chemical Type: Solubility: pH Microtox:

Surfactant Insoluble (water) 7.0-8.0 =61% @ (0.5 L/m3)

APPLICATION HME Coupler is a liquid emulsifier and homogeniser, used to provide uniform particle separation, a uniform suspension, and prevent the floatation of asphalts and Gilsonite in water based drilling muds. HME Coupler also functions as an effective emulsifier for oil added to water base fluids. The normal treatment ranges between 0.25-1.0 L/m3. MIXING AND HANDLING HME Coupler should be added slowly at the pump suction one to two circulations before adding the initial treatment of oil or asphaltic material. (For the best results, always add the HME Coupler prior to the addition of any oil or asphaltic material on a maintenance basis). Avoid contact with eyes, skin and clothing. In case of contact, immediately wash with plenty of water, flush eyes with flowing water immediately and continuously for 15 minutes. See a physician if necessary.


TDG: Not regulated

Page-297


7.65

HSO-0600G Return to Table of Contents

DESCRIPTION

HSO 0600G is a liquid Hydrogen Sulfide scavenger designed for use in oil-based drilling fluids. PROPERTIES

Chemical

Physical Appearance: Specific Gravity: Bulk Density: Flash Point:

Amber liquid .82 Not available 520ºC (SFCC)


Amine Dispersible (water) Not available Not applicable

APPLICATION HSO 0600G is designed to remove H2S from hydrocarbon based drilling fluids. It may be used as a pre-treatment or more effectively, added in a continuous manner with a positive displacement pump. As a pre-treatment, concentrations vary from 2.0-4.0 L/m3 of whole mud depending upon the severity of the H2S encountered. Approximately 1 L/m3 of HSO 0600G will scavenge 170 mg/L of dissolved H2S. MIXING AND HANDLING HSO 0600G can be added directly to the mud system or metered into the system with a positive displacement pump. HSO 0600G is a combustible liquid, avoids heat, sparks and open flames. Avoid breathing vapour and contact with eyes, skin or clothing. Keep container closed when not in use. Use this product in a well-ventilated area.



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7.66

HYDRATED LIME Return to Table of Contents

DESCRIPTION

Hydrated Lime or Calcium Hydroxide Ca(OH)2 is a source of Ca++ and OH- and is used to raise the pH, or Calcium ion. PROPERTIES

Physical


Grey-white powder 2.3-2.4 2850ºC Not applicable

Chemical


Calcium Hydroxide Soluble (0.185g/100 ml @ 0ºC) 12.0 (saturated solution) Not applicable

APPLICATION In clear water drilling, hydrated Lime is added to the sump water to increase the pH and to provide Calcium ions. In a Gyp-based mud system, hydrated Lime is added at a concentration of 1.0 kg/m3, and then used as needed to maintain a pH of 10.0-11.0 in the drilling fluid. Hydrated Lime is used as a means of adjusting the alkalinity when Bicarbonate/Carbonate contamination exists. Hydrated Lime is used to maintain the alkalinity of oil-based drilling fluids where it enhances the performance of emulsifiers and offers a degree of corrosion protection. MIXING AND HANDLING

Premix in water in the chemical barrel and add slowly to the system. Excess Lime treatment will cause thickening of a Bentonite based mud system. Hydrated Lime gives off heat when mixed with water. Strong solutions have a high pH and may cause skin burns. Avoid contact with skin and eyes and wear protective clothing and goggles when handling and mixing. Store in a dry place.


TDG: Not regulated

Page-299


7.67

HYPERDRILL AD-855 Return to Table of Contents

DESCRIPTION

AD 855 is a 40% active Hydrolyzed Polyacrylamide in liquid form. PROPERTIES

Physical


Milk-white liquid 1.04-1.06 -10ºC >93ºC

Chemical


Polyacrylamide Dispersible-Soluble 6.5-7.5 (1.0% solution) =20% @ (3.0 L/m3) HMW Anionic

APPLICATION Hyperdrill AD-855 can be used as a flocculant to promote water clarification in clear water drilling, a foam stabilizer, or it may be used in conjunction with K+ to stabilize shale. As a flocculant it is normally used in concentrations of 1.0L/30m (3 singles) of hole drilled. (Holes larger than 222 mm will require higher concentrations.) As a shale inhibitor the filtrate concentration ranges from 0.5 L/m3 for slightly hydratable shales to 1.5 L/m3 for moderately hydratable shales. Gumbo shales may require concentrations as high as 3.0 L/m3. MIXING AND HANDLING As a flocculant AD 855 can be added directly to the flow line, or it may be dispersed in water in the chemical barrel prior to adding to the flow line.

AD 855 is very slippery if spilled. A spill should be cleaned up with an absorbent material. (Do not add water to a spill).


TDG: Not regulated

Page-300


7.68

HYPERDRILL AF-204 RD Return to Table of Contents

DESCRIPTION

Hyperdrill AF-204 RD is a water-soluble Acrylamide co-polymer. AF 204 RD disperses readily in water minimizing the formation of "fish eyes". PROPERTIES

Physical


White granules 0.80 @ 25ºC Not available Not available

Chemical


Co-polymer Dispersible-Soluble 6.0-8.0 (0.5% solution) =3.3% @ (3.0 kg/m3) HMW Anionic

APPLICATION AF 204 RD is an effective anionic polymer flocculant used for clear water drilling. AF 204 RD should be added through a chemical barrel at the flow line or injected directly into a centrifuge from a premixed polymer tank, usually in a 0.5% stock solution. It can also be used for fluid clarification when added at the centrifuge in sumpless drilling operations. AF 204 RD will provide shale stabilization and viscosity when used in higher concentrations of 0.3-3.0 kg/m3. MIXING AND HANDLING Mix directly into the hopper at 30 minutes per sack or add (with agitation) to a chemical barrel or polymer-mixing tank. Avoid mixing too rapidly. A mask and goggles should be worn to prevent inhalation of dust and contact with eyes. AF 204 RD becomes very slippery when wet. A spill should be cleaned up with an absorbent material.


TDG: Not regulated

Page-301


7.69


DESCRIPTION Hyperdrill AF-207 RD is readily dispersible Acrylamide-based co-polymer. PROPERTIES

Physical


Off-White powder .65 0.7 kg/m3 Not available

Chemical


Flocculant Dispersible-Soluble 6.0-8.0 (0.5% solution) >91% @ (3.0 kg/m3) HMW Anionic

APPLICATION AF 207 RD has been developed to give enhanced performance in conventional clear water or low solids drilling fluids while maintaining functionality in K+, polymer and high salt systems. With improved dispersibility over conventional PHPA powders, AF 207 RD provides all the benefits normally associated with PHPA type additives. AF 207 RD will provide viscosity, shale stabilization, flocculation, lubrication and foam stabilization. As a viscosifier, AF 207 RD is very efficient and cost effective in low solids, low salinitydrilling fluids. Normal dosage rates are between 0.75-3.0 kg/m3. AF 207 RD can be used alone or in conjunction with clay stabilizers such as K+ to inhibit shale hydration. Sufficient polymer must be maintained in the system to provide a protective coating on the well bore and drill cuttings. Normal addition rates are 0.63.0kg/m3. MIXING AND HANDLING

AF 207 RD is added either at the flow line to promote solids settling in the sump or at a point prior to mechanical separation equipment. A 0.5% stock solution is most commonly prepared using (1) one viscosity cup of polymer per 50 gallons of fresh water. AF 207 RD must be mixed slowly to prevent "humping" and the subsequent loss of polymer at the shaker screen. AF 207 RD becomes very slippery when it comes in contact with water. A spill should be cleaned up with an absorbent material. It is advisable to use a dust mask and eye protection while mixing all powdered products.


TDG: Not regulated

Page-302


7.70


DESCRIPTION

Hyperdrill AF-247 RD is a readily dispersible, Acrylamide-based co-polymer. PROPERTIES Physical

Appearance: Bulk density: Moisture Content: Flash Point:

White granular powder 0.7 kg/m3 Not available Not available

Chemical


Co-polymer Dispersible-Soluble 6.0-8.0 (0.5% solution) >91% @. (3.0 kg/m3) LMW Anionic

APPLICATION

AF 247 RD has been developed to provide improved shale stabilization/inhibition in drilling fluids with minimal effect on rheology. It is suitable for use in fresh water, seawater, K+ polymer, and other inhibitive water-based systems. Its improved rheological properties allow addition of higher concentrations with reduced viscosity humping in solids laden muds. Dosage rates are 2.0-6.0 kg/m3. AF 247 RD exhibits improved dispersibility over conventional PHPAs while providing the following benefits: 1. Shale stabilization/inhibition, minimized viscosity increases, added lubricity, lower fluid loss, improved filter cake quality, and is readily dispersible with no formation of fish eyes. 2. The solid grade form is more cost effective than liquids and is environmentally friendly.

MIXING AND HANDLING Because of its excellent dispersibility and mixing, AF 247 RD can be added directly to the mud system without pre-wetting in a solvent. A small hole should be cut into the bottom of the bag, allowing it to flow at a steady rate into the mud hopper. If necessary AF 247 RD may be pre-hydrated at concentrations of 10.0-15.0 kg/m3 in a separate tank and fed into the main circulating system to maintain concentrations of 2.0-6.0 kg/m3. AF 247 RD becomes very slippery when it comes in contact with water. A spill should be cleaned up with an absorbent material. It is advisable to use a dust mask and eye protection while mixing all powdered products. WHMIS: Not controlled

TDG: Not regulated

Page-303


7.71

“K2” Return to Table of Contents

DESCRIPTION K2 is a chloride free, cationic organic multivalent clay inhibitor, which is 100% soluble in water. PROPERTIES

Chemical

Physical Appearance: Specific Gravity: Pour Point: Flash Point:

Clear liquid 1.07 >-35ºC >100ºC (TCC)


Clay inhibitor 100% Soluble (water) 9.0-10.0 >91% @ (10.0 L/m3)

APPLICATION K2 has been developed as an effective Chloride free clay inhibitor for water sensitive formations. It has a small ionic radius allowing easy substitution on the exchange sites with the Sodium ion, thereby effectively blocking the site for water hydration. K2 finds application for use as a source of inhibition in under-balanced drilling operations. K2 is effective in any pH range, however increased dosage will be required above a pH of 10.5. Some of the added benefits over other clay stabilizers are: 1. Excellent biodegradability (>60% by DOC Method) 2. Chloride free 3. Non-oil wetting 4. Non-foaming 5. Essentially non-toxic 6. Multiple absorption sites The normal concentration used in the field is 3.0-6.0 litres/m3. MIXING AND HANDLING K2 can be added directly to the mud system either on surface or through the mixing system. Avoid eye and skin contact, should contact occur, flush thoroughly with water and seek proper medical attention. WHMIS: Controlled (see MSDS)

TDG: Not regulated

Page-304


7.72

KELZAN XCD POLYMER Return to Table of Contents

DESCRIPTION

Kelzan XCD is a high molecular weight biopolymer of Xanthan Gum. PROPERTIES

Physical


White-tan powder Not available Not available Not applicable

Chemical


Xanthan Gum Soluble (water) 7.0 (1% solution) Pending

APPLICATION Kelzan XCD is used primarily as a viscosifier in fresh water, seawater or saline muds. It also provides a measure of filtration control. Kelzan XCD (in conjunction with an Oxygen scavenger) is temperature stable to l50oC. It is stable in a wide pH range and is used in both weighted and unweighted drilling fluids, completion fluids and work over systems. Kelzan XCD exhibits the rheological property of pseudoplasticity (shear thinning). Small quantities provide high yield points and low plastic viscosities, which provide excellent carrying capacities and high penetration rates. MIXING AND HANDLING Kelzan XCD disperses in water with moderate agitation. Continued mixing provides a smooth viscous fluid. Kelzan XCD should be added slowly to the active system to avoid lumping or fish-eyes, which may occur if the polymer is not allowed to properly disperse.


TDG: Not regulated

Page-305


7.73

LIGNOCAL Return to Table of Contents

DESCRIPTION

Lignocal is a sugar free Calcium Lignosulfonate produced by sulfonation of softwood lignin. PROPERTIES

Physical


Light tan powder 1.53 <7.0% Not applicable

Chemical


Lignin Soluble (water) 7.0-9.0 Pending

APPLICATION Lignocal can be used in water base mud systems as a thinner (dispersant), oil emulsifier and filtration control/stabilization agent. Lignocal will not be as effective as modified Sodium Lignosulfonates in highly contaminated mud systems. Lignocal is readily soluble in water and because of this does not require Hydroxyl ion to function as a thinner. Concentrations vary from 6.0-20.0 kg/m3 depending on solids content of the system. Lignocal is also an effective retarder in cement slurries for temperatures up to ±95ºC (200ºF). Typical treating rates are 0.1-1.5%/wt.of cement. MIXING AND HANDLING Mix directly through the mud hopper or into the dry blended cement via the blend system. Use appropriate protective clothing, e.g. goggles, rubber gloves, and/or dust mask. As with all organic material, caution is advised when storing or handling near strong oxidizing agents. Prolonged and excessive heating of Lignocal could result in decomposition and the release of toxic Sulfur Dioxide fumes.


TDG: Not regulated

Page-306


7.74 LIQUISPERSE Return to Table of Contents

DESCRIPTION

Liquisperse is a powerful non-ionic wetting agent designed to handle severe mud ring problems and bit-balling on surface and upper main hole sections. PROPERTIES

Physical


Clear green liquid, sweet odor 1.07 >100ºC


Surfactant Soluble (water) Not Determined >91% @ (0.1 L/m3) (T.L.)

APPLICATION Liquisperse can be added directly to the mud system and is normally used in concentrations of 0.2 – 0.6 L/m3. 1-2 viscosity cups of Liquisperse may also be added down the drill pipe every connection. Liquisperse is a highly active liquid wetting agent. It is designed to provide uniform particle separation thereby preventing bit balling and the formation of mud rings in areas where extremely reactive clays are encountered. Liquisperse should be added as required to control the formation of mud rings. 1. 2. 3. 4. 5. 6. 7.


MIXING AND HANDLING Liquisperse may be added at the mud pump suction or added directly down the drill-pipe on connections. In areas where the encountering of highly reactive clays is certain, begin adding Liquisperse at the suction just prior to penetrating the problem zone. When handling Liquisperse use rubber gloves and eye protection.


TDG: Not regulated

Page-307


7.75

MAGMA FIBER Return to Table of Contents

DESCRIPTION

Magma Fiber is a specially formulated acid soluble, extrusion spun mineral fiber for lost circulation problems. Magma Fiber is 97.3% soluble in a 7.5% HCL acid. PROPERTIES

Physical


Grey to buff granules or powder 2.6 1315ºC Not applicable

Chemical


LCM Soluble (acid) 7.0-8.0 Not applicable

APPLICATION Magma Fiber is a spun mineral fiber, which acts as a plugging and bridging agent to plug voids, fractures, and all types of permeable formations. Magma Fiber can be used in many fluids, water-based, oil-based, completion and work-over fluids. Magma Fiber can be added on a continuous basis or pumped in sweeps depending upon the severity of the losses encountered. Magma Fiber performs best in concentrations of up to 75.0 kg/m3 mixed in a pill or slug. MIXING AND HANDLING Magma Fiber can be mixed through the hopper or added directly to the mud tanks wherever there is adequate agitation. It is advisable to use a dust mask and eye protection while mixing all powdered products.


TDG: Not regulated

Page-308


7.76

MAGNESIUM OXIDE Return to Table of Contents

DESCRIPTION

Magnesium Oxide (MgO) is a non-corrosive inorganic oxide used as a pH-buffering agent and for neutralizing acid. PROPERTIES

Physical

Appearance: Specific Gravity: Bulk Density: Melting Point:

Light colored powder 3.6 400 kg/m3 2800ºC

Chemical


Inorganic salt Not soluble (water) 10.7 Maximum Not applicable

APPLICATION Magnesium Oxide can be used as a substitute for Lime as a coagulant in clear water drilling, and for alkalinity control in polymer systems where a high pH (above 11.0) is undesirable. Any undissolved excess Magnesium Oxide will continue to dissolve at a slow rate to maintain a constant pH level of 10.7. MIXING AND HANDLING Magnesium Oxide can be added through the hopper or mixed directly to the system at a point of agitation. It is advisable to use a dust mask and eye protection while mixing Magnesium Oxide or any other powdered material.


TDG: Not regulated

Page-309


7.77

MICA Return to Table of Contents

DESCRIPTION

Mica or Muscovite is a lost circulation material supplied in three grind sizes; fine, medium, and coarse. PROPERTIES

Physical

Appearance: Specific Gravity: Molecular Wt: Flash Point:

Amber thin flake 2.9 417 kg/m3 None

Chemical


Phlogopite Mica Not soluble (water, oil) 7.0-8.0 Not applicable

APPLICATION Mica is used in both water based and oil based muds either as part of a blend of lost circulation materials to control losses or as a pre-treatment to control seepage losses. MIXING AND HANDLING Mica is chemically inert and has no fibrous material. Mix through mud hopper. It is advisable to use a dust mask and eye protection while mixing all powdered products.


TDG: Not regulated

Page-310


7.78

MUD-FLOC II D Return to Table of Contents

DESCRIPTION

Mud-Floc II D is a polymer based, selective or total flocculant. PROPERTIES

Physical


Chemical

Off white powder .65 900 kg/m3 Not available


Polymeric flocculant Dispersible-Soluble 6.0 (1% solution) =47% @ (0.05 kg/m3) HMW Anionic

APPLICATION Mud-Floc II D is used as a flocculant to promote water clarification in clear water drilling. Mud Floc II D is ideal for use in situations where clear water drilling is immediately followed by mud-up to a Bentonite based mud system. Mud Floc II D is used in concentrations of l.0 kg/30 meters (1-2 viscosity cups every 3 singles) of drilled hole. (Holes larger than 222 mm will require higher rates of addition). MIXING AND HANDLING Mud-Floc II D can be mixed directly into water in the chemical barrel and added to the mud system at the flow line. It is advisable to use a dust mask and eye protection while mixing all powdered products. Mud-Floc II D can become very slippery when coming in contact with water. A spill should be cleaned up with an absorbent material.


TDG: Not regulated

Page-311

PACKAGING: 50 lb carton (25x2 lb plastic bottles)

7.79

NATURAL GEL Return to Table of Contents

DESCRIPTION

Natural Gel is an untreated Bentonite (Sodium Montmorillonite), which meets the API specification for Non-treated Bentonite (API Spec 13A, Section 5, Fourteenth Ed. Aug. 1991). Generally the wet yield of untreated Bentonite is 80-90 bbl/ton of 15 cps viscosity mud. PROPERTIES

Physical

Appearance: Specific Gravity: Bulk Density Flash Point:

Tan to gray powder 2.45-2.55 880 kg/m3 Not flammable

Chemical


Sodium Montmorillonite Not soluble (forms colloidal suspension) 8.0-10.0 (5% suspension) Not applicable

APPLICATION Natural Gel is used commonly in mud systems for which Bentonite is prehydrated and then flocculated with a salt such as K+. In such instances the lower wet yield is not significant since the viscosity is obtained by flocculation. Natural Gel can also be used in extended systems where the yield is enhanced by the extending polymers. Natural Gel is also a component of lightweight oilwell cement. Additions up to 25% wt./cement are used to reduce slurry weight and increase cement volume. Natural Gel can be dry blended in the cement or can be prehydrated in water. MIXING AND HANDLING Natural Gel is added to the system through the mixing hopper. It should be added no faster than 5 minutes per sack. It is advisable to use a dust mask and eye protection while mixing all powdered products.


TDG: Not regulated

Page-312


7.80

NUTSHELL Return to Table of Contents

DESCRIPTION

A lost circulation material of ground Nutshell is available in three grades, Fine, Medium, and Coarse, ranging in size from 100 mesh to 6 mesh. PROPERTIES

Physical


Brown granular 1.2-1.4 Not available Not available Not available

Chemical


Wood by-product Not soluble (water) Not determined Not applicable

APPLICATION Nutshell is used as a lost circulation material and bridging agent due to its granular nature. Nutshell is chemically inert and may be added to any mud system. Nutshell is also used as a drag reducer in deviated holes. Circulated through the tight hole section immediately prior to a trip the irregular particles are embedded in the filter cake and act similar to ball bearings to reduce hole drag. Mix into the mud or lost circulation pill in concentrations of 10.0-30.0 kg/m3. When used as a torque and drag reducer for trips, displace a pill containing 20.0-30.0 kg/m3 so that the pill is spotted across the tight section of the hole. MIXING AND HANDLING It is advisable to use a dust mask and eye protection while mixing all ground and powdered products.


TDG: Not regulated

Page-313


7.81

OILGEL 3000 Return to Table of Contents

DESCRIPTION

Oilgel 3000 is a modified Bentonite clay, capable of producing high YP/PV ratios and Gel Strengths in diesel oil, crude oil and mineral oils with, or without a polar activator. PROPERTIES

Physical


Cream colored powder 1.7 Not available Not available Not available

Chemical


Modified Bentonite Insoluble (water, oil) Not available Not applicable

APPLICATION Oilgel 3000 is an effective viscosifier in oil and invert emulsion systems. As a viscosifier in oil, Oilgel 3000 eliminates the need for a water or brine phase resulting in a rheological profile closer to a water based polymer system than a typical invert. In invert emulsion systems, Oilgel 3000 can provide immediate yield point and gel strengths for hole cleaning or Barite suspension. MIXING AND HANDLING Mix directly into mud hopper. Avoid mixing too rapidly. A mask and goggles should be worn to prevent inhalation of dust and contact with the eyes. Fresh air ventilation should be provided in the mixing area.


TDG: Not regulated

Page-314


7.82

OMV-100 Return to Table of Contents

DESCRIPTION

An organophilic clay used to develop gel strength and adjust rheological properties of an oil based drilling fluid. PROPERTIES

Physical


Tan colored powder 1.7 Not available Not available Not available

Chemical


Organophilic clay Not soluble (water, oil) Not available Not applicable

APPLICATION The concentration of OMV-100 required depends on the oil/water ratio and density of the mud system. A fluid with a higher oil/water ratio (90/10) will require more OMV-100 than a fluid with a lower oil/water ratio (70/30). A higher density fluid will generally require less product than low-density fluids. In water-free oil base systems, small amounts of polar additive, such as methanol, will be required to produce full yield. Generally, concentrations will be in the range of 2.8514.25 kg/m3 depending on requirements. MIXING AND HANDLING Mix directly through the mud hopper. Avoid mixing too rapidly. A mask and goggles must be worn to prevent inhalation of dust and contact with the eyes. Fresh air ventilation should be provided in the mixing area.


TDG: Not regulated

Page-315


7.83

PERCOL 338 RD (ALCOMER 338 RD) Return to Table of Contents

DESCRIPTION Alcomer 338 RD (formerly Percol 338 RD) is an anionic Polyacrylamide flocculant. PROPERTIES

Physical


White granular powder .75 700-800 kg/m3 Not applicable

Chemical


Polyacrylamide Dispersible-Soluble 6.5-7.5 (1% solution) Pending HMW Anionic

APPLICATION Alcomer 338 RD is an effective anionic flocculant used for clear water drilling and fluid clarification in closed systems. It should be added through a chemical barrel at the flow line or injected directly into a centrifuge from a premixed polymer tank usually in a 0.5% stock solution. Alcomer 338 RD can also be used for fluid clarification when added at the centrifuge in sumpless drilling operations. Alcomer 338 RD will provide shale stabilization and viscosity when used in concentrations of 0.3-3.0 kg/m3. MIXING AND HANDLING Mix slowly into a chemical barrel or polymer mixing tank and allow product to hydrate. Avoid mixing too rapidly. A mask and goggles should be worn to prevent inhalation of dust and contact with eyes. Alcomer 338 RD becomes very slippery when it comes in contact with water. A spill should be cleaned up with an absorbent material.


TDG: Not regulated

Page-316


7.84

PERCOL 351 (MAGNAFLOC 351) Return to Table of Contents

DESCRIPTION

Percol 351 is a Polyacrylamide flocculant, which has many industrial applications. PROPERTIES

Physical


White granular powder 0.80 750 kg/m3 Not Applicable

Chemical


Polyacrylamide Dispersible-Soluble 6.5 (1% solution) Pending HMW Non-ionic

APPLICATION Percol 351 is an effective non-ionic polymer flocculant used for clear-water drilling and fluid clarification in closed systems. It should be added through a chemical barrel at the flowline or injected directly into a centrifuge from a premixed polymer tank usually in a 0.5% stock solution. Percol 351 can also be used for fluid clarification when added at the centrifuge during sumpless drilling operations. It is especially effective in situations where high levels of clay are present. Percol 351 should be preceded by the appropriate organic or inorganic coagulant additions. MIXING AND HANDLING Mix slowly into a chemical barrel or polymer mixing tank and allow the product to hydrate. Avoid mixing too rapidly. A mask and goggles should be worn to prevent inhalation of dust and contact with eyes. Percol 351 can become very slippery when in contact with water. A spill should be cleaned up with an absorbent material.


TDG: Not regulated

Page-317


7.85

PERCOL 728 (ZETAG 7692) Return to Table of Contents

DESCRIPTION

Percol 728 is a polyelectrolyte capable of creating high viscosity. PROPERTIES

Physical


White powder .8-1.0 640 kg/m3 Not available Not applicable

Chemical


Polyelectrolyte Dispersible-Soluble 3.5-4.5 (1% solution) >100% @ (1.0 kg/m3) HMW Cationic

APPLICATION Percol 728 is an effective cationic polymer flocculant used for clear-water drilling and fluid clarification in closed systems. It is very effective in dewatering water-based systems especially those containing significant amounts of biopolymers and PACs. Percol 728 should be added through a chemical barrel at the flowline or injected directly into a centrifuge from a premixed polymer tank, usually in a 0.5% stock solution. Additions of Percol 728 should be preceded by the appropriate organic or inorganic coagulant additions. MIXING AND HANDLING Mix slowly into a chemical barrel or polymer mixing tank and allow product to hydrate. Avoid mixing too rapidly. A mask and goggles should be worn to prevent inhalation of dust and contact with eyes. Percol 728 can become very slippery when in contact with water. A spill should be cleaned up with an absorbent material.


TDG: Not regulated

Page-318


7.86


DESCRIPTION Percol 757 is a cationic polyelectrolyte flocculant. PROPERTIES

Physical


White micro-bead .75 800-810 kg/m3 Not applicable

Chemical


Polyelectrolyte Dispersible-Soluble 3.5-4.5 (1% solution) Pending HMW Cationic

APPLICATION Percol 757 is an effective cationic flocculant used for clear water drilling and fluid clarification in closed systems. It should be added through a chemical barrel at the flow line or injected directly into a centrifuge from a premixed polymer tank usually in a 0.5% stock solution. Percol 757 can also be used for fluid clarification when added at the centrifuge in sumpless drilling operations. MIXING AND HANDLING Mix slowly into a chemical barrel or polymer mixing tank and allow product to hydrate. Avoid mixing too rapidly. A mask and goggles should be worn to prevent inhalation of dust and contact with eyes. Percol 757 becomes very slippery when it comes in contact with water. A spill should be cleaned up with an absorbent material.


TDG: Not regulated

Page-319


7.87


DESCRIPTION Percol 787 is a cationic polyelectrolyte flocculant. PROPERTIES

Physical


White micro-bead .75 800-810 kg/m3 Not applicable

Chemical


Polyelectrolyte Dispersible-Soluble 3.5-4.5 (1% solution) Pending HMW Cationic

APPLICATION Percol 787 is an effective cationic flocculant used for clear water drilling and fluid clarification in closed systems. It should be added through a chemical barrel at the flow line or injected directly into a centrifuge from a premixed polymer tank usually in a 0.5% stock solution. Percol 787 can also be used for fluid clarification when added at the centrifuge in sumpless drilling operations. MIXING AND HANDLING Mix slowly into a chemical barrel or polymer mixing tank and allow product to hydrate. Avoid mixing too rapidly. A mask and goggles should be worn to prevent inhalation of dust and contact with eyes. Percol 787 becomes very slippery when it comes in contact with water. A spill should be cleaned up with an absorbent material.

WHMIS: Not Controlled

TDG: Not regulated

Page-320


7.88

POL-E-FLAKE Return to Table of Contents

DESCRIPTION

Pol-E-Flake is a 3/8 inch flake LCM additive made from a polyester film, which provides maximum mat sealing at the face of the well bore. PROPERTIES

Physical


Clear to hazy plastic film Not available Not available Not available Not applicable

Chemical


Polyester flakes Not soluble (water) Not available Not applicable

APPLICATION Pol-E-Flake is inert and may be used in any common drilling fluid or cement system as a loss of circulation additive. Pol-E-Flake may be added to a mud system as a preventative measure when a known loss zone is to be drilled. It may also be used in conjunction with other lost circulation materials to achieve as wide as possible particle distribution. MIXING AND HANDLING Pol-E-Flake can be mixed through the hopper or added directly to the mud tanks wherever there is adequate agitation. Mix into a viscous mud with good agitation. PolE-Flake will not pass through the shaker screen. In order to maintain the Pol-EFlake concentration in the mud the shale shaker must be by-passed. Note: Bypassing the shaker could result in plugged jets. It is advisable to use a dust mask and eye protection while mixing all products.


TDG: Not regulated

Page-321


7.89

POLYDRILL Return to Table of Contents

DESCRIPTION

Polydrill is a sulfonated polymer fluid loss control additive, which stabilizes rheology in a wide range of drilling and completion fluid systems. PROPERTIES Physical


Red/brown powder 0.75 600 kg/m3 Not available

Chemical


Synthetic sulfonated polymer Soluble (water) 7.0-9.0 (150 g/L @ 20ºC) >91% @ (11.4 kg/m3)

APPLICATION Formulated on a new chemistry Polydrill belongs to the group of 100% synthetic polymers such as Polyacrylamides and vinylsulfonate/vinylamide co-polymers. The polymer has a molecular weight of 200,000, which gives it the advantage of not increasing rheology. Polydrill achieves fluid loss control by reducing the pore size of a filter cake and plugging these pores. The polymer has an enormous water-binding capability, which ties up much of the free water. Polydrill works best in highly contaminated and high temperature environments at concentrations of 2.8-8.5 kg/m3. Pilot testing is recommended prior to addition to the mud system. Features: -

- Temperature stability exceeding 200ºC Calcium tolerance to 75,000 ppm Magnesium tolerance to 100,000 ppm Complete tolerance to Sodium and Potassium Chloride Stabilization of rheological properties Minimal effect on viscosity Improved filter cake quality Thermal stabilization of PAC and CMC to at least (145º C) Non-damaging to the formation Low replacement levels Environmentally safe

MIXING AND HANDLING Polydrill can be added directly into the mud system through the mixing hopper. It is advisable to use a dust mask and eye protection while mixing all powdered products. WHMIS: Not controlled

TDG: Not regulated

Page-322


7.90

POLYTHIN Return to Table of Contents

DESCRIPTION

Polythin is a chrome-free, highly soluble, highly anionic drilling fluid deflocculant and fluid conditioner. PROPERTIES

Physical

Appearance: Bulk Density: Flash Point:

Brown powder Not available Not available


Synthetic polymer Highly soluble (water) 6.0-7.0 Pending

APPLICATION Polythin works particularly well in high solids water-based muds, where temperatures exceed 200ºC. Polythin adsorbs onto the surface of clay platelets preventing the flocculation of Bentonite in the presence of high temperature, contamination by salt (up to 50,000 ppm) and CO2. Polythin will also help to augment fluid loss additives where high temperature and severe contamination is a problem. Concentration ranges from 1.4-11.5 kg/m3 depending upon the degree of contamination. Features: -

- Temperature stability exceeding 200ºC Calcium tolerance to 50,000 ppm Stabilization of rheological properties Improved filter cake quality Works at any pH above 7.0 Non-damaging to the formation Low replacement levels Environmentally safe

MIXING AND HANDLING Polythin can be added directly into the mud system through the mixing hopper. It is advisable to use a dust mask and eye protection while mixing all powdered products.


TDG: Not regulated

Page-323


7.91

POLY-VIS II Return to Table of Contents

DESCRIPTION

Poly-Vis II is a second generation Mixed Metal Hydroxide (MMH) viscosifier for water based fluids. Poly-Vis II provides exceptional shear-thinning properties in Natural Gel based drilling muds with excellent dynamic and static carrying capacity. PROPERTIES

Physical


Fine white powder 2.7-2.9 640 kg/m3 Not available Not available

Chemical


Mixed Metal Hydroxide Not soluble Not available Pending

APPLICATION Poly-Vis II can be used to formulate fresh, seawater or high salt (KCl, NaCl) muds. For normal applications dosages range from 2.1 kg/m3 to 2.85 kg/m3 in a 1:10 ratio with Natural Gel. Poly-Vis II Natural Gel systems are ideal for: - horizontal & high angle drilling - drill-in fluids - top-hole drilling - milling fluids - coiled tubing drilling - seepage loss control - drilling in unconsolidated formations MIXING AND HANDLING Poly-Vis II works best with untreated Natural Gel in a pH range of 10.0-10.5. A typical mud contains 26 kg/m3 pre-hydrated Natural Gel and 2.1 kg/m3 Poly-Vis II. Poly-Vis II can be added at the mixing hopper. Always wear gloves, safety goggles and a dust mask when mixing. The use of highly anionic chemicals such as Lignosulfonate, PACs (Drispac, Staflo), treated Bentonite etc. will reduce the viscosity of Poly-Vis II muds. Pilot testing is recommended prior to any additions being made to the mud system. WHMIS: Controlled (see MSDS)

TDG: Not regulated

Page-324


7.92

POLY-XAN POLYMER Return to Table of Contents

DESCRIPTION Poly-Xan a high molecular weight biopolymer of Xanthan Gum. PROPERTIES

Physical


White-tan powder Not available Not available Not applicable

Chemical


Xanthan Gum Soluble (water) 7.0 (1% solution) Pending

APPLICATION Poly-Xan is used primarily as a viscosifier in fresh water, seawater or saline muds. It also provides a measure of filtration control. Poly-Xan (in conjunction with an Oxygen scavenger) is temperature stable to l50oC. It is stable in a wide pH range and is used in both weighted and unweighted drilling fluids, completion fluids and work over systems. Poly-Xan is designed to provide viscosity on shallow and medium depth wells where economics demand high performance at a reasonable cost. Poly-Xan exhibits the rheological property of pseudoplasticity (shear thinning). Small quantities provide high yield points and low plastic viscosities, which provide excellent carrying capacities and high penetration rates. MIXING AND HANDLING Poly-Xan disperses in water with moderate agitation. Continued mixing provides a smooth viscous fluid. Poly-Xan should be added slowly to the active system to avoid lumping or fish-eyes, which may occur if the polymer is not allowed to properly disperse.


TDG: Not regulated

Page-325


7.93

POTASSIUM CHLORIDE Return to Table of Contents

DESCRIPTION

Potassium Chloride (KCl) is an odorless white crystal, which forms a neutral salt solution with water. Potash purity is expressed as percent K2O. 63% K2O = 100% KCl PROPERTIES

Physical


White crystalline powder 1.98 Varies with grade Not flammable

Chemical


Salt Soluble (water) 5.4-8.6 (5% solution) Not applicable

APPLICATION Generally used to provide Potassium (K+) ions in shale inhibiting drilling muds. The K+ ion provides a strong bonding ion between the clay platelets thus inhibiting the swelling of shales. Normal concentrations in Western Canada is 30.0-40.0 kg/m3. The K+ ion is absorbed onto the clay and is thus depleted from the system. The rate of absorption is related to the reactivity of the shale. 10 kg/m3 KCl = approx. 5250 mg/l K+ MIXING AND HANDLING Potash mixes readily in water and can be mixed directly through the hopper. Avoid breathing dust while mixing. It is advisable to use a dust mask and eye protection while mixing all powdered products.


TDG: Not regulated

Page-326


7.94

POTASSIUM FORMATE Return to Table of Contents

DESCRIPTION

Potassium Formate is high-density brine delivered as a 70.7% w/w (S.G. 1.53) solution for winter use, and as a 75.0% w/w (S.G. 1.57) solution for summer use.

PROPERTIES

Physical


Clear to amber liquid 1.53-1.57 Not applicable

Chemical


Potassium formate Highly soluble (water) 10.5-11.5 Not applicable

APPLICATION Potassium Formate readily exchanges its potassium ions with clays and shales to inhibit their reactivity and contribute to improved hole stability. Polymers and Starches should generally be pre-hydrated prior to addition to the Potassium Formate system. At higher concentrations Potassium Formate will provide temperature and bio-stability to Starches, PACs and polymers. Recommended Concentration (%)

Application Floc-water Drilling Drilling Fluid Drill-in Fluid Drill-in/Workover/Completion Fluid

5.0% 5.0% 5.0-100% * 5.0-100% *

*Barite (Barium Sulfate) will become soluble if the Potassium Formate concentration is 40% or higher. In these circumstances CaCO3 can be used to increase density. MIXING AND HANDLING

Potassium Formate is available in 1m3 totes. The Potassium Formate may be added directly to the mud system to achieve both the desired initial concentration and for maintenance of the potassium ion as depletion occurs. Avoid contact with skin and eyes (see MSDS). Potassium Formate should be stored in a cool dry place out of the sunlight and protected from freezing. WHMIS: Not controlled

TDG: Not regulated

Page-327

PACKAGING: 1m3 totes

7.95

POTASSIUM SULFATE Return to Table of Contents

DESCRIPTION

Potassium Sulfate (K2S04) forms a neutral salt solution with water. Potassium Sulfate is available in a crystalline form with its purity expressed as percent K20. 54% K20 = 100% K2S04 PROPERTIES

Physical


White/beige powder 2.66 1074ºC Not available

Chemical


Salt Soluble (11.11g/100ml H2O @ 20ºC) 8.7 (1% by weight) Not applicable

APPLICATION Potassium Sulfate is used to provide potassium (K+) ions in shale inhibiting muds. The K+ ion provides a strong bond between the clay platelets inhibiting swelling. The K+ ion is absorbed onto the clay platelets and through this process is depleted from the system. The rate of absorption is related to the reactivity of the shale. Use in concentrations normally of 30-40 kg/m3. 10 kg/m3 K2S04 = 4490 mg/l K+ MIXING AND HANDLING Potassium Sulphate mixes readily in water and can be mixed directly through the hopper. Avoid breathing dust while mixing. . It is advisable to use a dust mask and eye protection while mixing all powdered products.


TDG: Not regulated

Page-328


7.96

PRIMA-SEAL Return to Table of Contents

DESCRIPTION

Prima-Seal is a blend of lost circulation materials specifically formulated to cover a wide range of situations common in the occurrence of lost circulation. The two grades, Medium and Coarse, contain a blend of granules and fibers, which act as bridging and sealing agents. PROPERTIES

Physical


Yellow/brown particles slight odor 0.9-1.2 Not flammable

Chemical


Blend Insoluble (water) 6.8-8.5 Not applicable

APPLICATION Prima-Seal is a lost circulation material, which may be used by itself or in conjunction with other lost circulation additives. Generally, its use may be based on the following criteria: Coarse - seals large fractures, requires large jets (16 mm or larger) or an open watercourse. Medium - seals fine fractures and porous zones, should be used with jets larger than 10.3 mm. Depending on the severity, the total lost circulation material concentration may be as high as 75.0 kg/m3 of whole mud. MIXING AND HANDLING

Prima-Seal can be mixed directly into a viscous mud with good agitation. Larger sizes will plug shale shaker screens. If re-circulation is necessary, the shale shaker should be by-passed. However, bypassing the shaker could result in plugged jets. It is advisable to use a dust mask and eye protection while mixing all powdered products.


TDG: Not regulated

Page-329

PACKAGING: 1.45 cubic ft sack

7.97

PROCESSED LIME (Hot Lime, Quick Lime) Return to Table of Contents

DESCRIPTION

Processed Calcium Oxide (CaO) is commonly known as Quick Lime, Hot Lime or Slaked Lime. PROPERTIES

Physical


Gray/white powder 3.2-3.4 2850º C Not flammable

Chemical


Calcium Oxide Moderate (water) <12.0 Not applicable

APPLICATION The principal use for Processed Lime is in oil base systems for fluid property control. Hot Lime changes the fatty acid soaps to Calcium base emulsifiers. In water free oil base muds, Processed Lime is added to “tie up” any water that may enter into the mud system. MIXING AND HANDLING Mix directly into system slowly through mud hopper or at point of agitation. Avoid contact with water and store in a cool, dry place. When mixing full clothing, eye and face protection, rubber gloves and a rubber apron should be worn.

Caution: Contact with water/moisture generates a large amount of heat and the resulting solution has a high pH and may cause burns. In the event of a spill do not mix Processed Lime with any flammable materials such as paper, floor-dry or Sawdust.


TDG: Not regulated

Page-330


7.98

SAF-KOTE Return to Table of Contents

DESCRIPTION Saf-Kote is a cationic amine blend in a mineral spirit base. PROPERTIES

Physical


Dark amber liquid 0.91-0.92 -29ºC 43ºC (PMCC)


Filming amine Soluble (Oil) Not available =50% @ (0.5 L/m3)

APPLICATION Saf-Kote adsorbs onto metal surfaces. It is effective in all water-based, oil based and foam drilling fluids. Saf-Kote protects the drill string, casing and rig equipment against Hydrogen Sulfide (H2S), Carbon Dioxide or Oxygen corrosion by physically adsorbing to metal surfaces. NOTE: Due to Saf-Kote’s cationic nature, it may cause flocculation in high solids/high density drilling fluids. The addition of a thinner may then be required. Saf-Kote should not be used in conjunction with Corinox. To film the pipe Saf-Kote should be added directly to the mud system as a batch treatment. For added protection, it can also be diluted 50/50 in diesel or kerosene and sprayed on the drill pipe. Initially, Saf-Kote should be added at 1.0 L/m3 for every 125 mg/l of H2S present in the mud. Once the initial treatment has been made, normal daily maintenance of 5.0-20.0 liters/circulation is recommended and corrosion rates should be monitored with corrosion rings to ensure treatment rates are adequate. MIXING AND HANDLING Avoid inhalation of vapours. Do not get on skin, in eyes or on clothing. Keep container closed when not in use. Wear suitable protection for eyes and skin when handling. Use with adequate ventilation. Avoid contact with incompatible materials (see M.S.D.S.). Store in a cool, dry, well-ventilated area.


TDG: Not regulated

Page-331

PACKAGING: 20 litre pail

7.99

SALT GEL Return to Table of Contents

DESCRIPTION

Salt Gel is a Hydrous Magnesium Silicate (Sepiolite), which meets the specifications as set down in the API Standards Specification l3A, Sec. 4. PROPERTIES

Physical

Appearance: Specific Gravity: Moisture Content:

Tan colored powder 1.9-2.4 11.6%

Chemical

Type: Solubility: pH: Mictrotox:

Magnesium silicate Insoluble (water) 7.0-8.3 Not applicable

APPLICATION Salt Gel can be used as a viscosifier in saline mud systems or in mud systems exposed to a high temperature environment. In a high temperature environment it may be used by itself or in conjunction with Bentonite. In comparison with Bentonite, Salt Gel is slightly less effective in its viscosifying ability and its ability to reduce the fluid loss of mud systems. It is more temperature stable, more inert to thinning in the presence of conventional thinners and more tolerant to mud contaminants. MIXING AND HANDLING Salt Gel is mixed through the mud hopper and requires more shear (than Bentonite) in order to attain its maximum yield. It is not uncommon to observe an increase in viscosity as a result of the high shear rate experienced by the drilling mud as it passes through the bit nozzles. Consequently, although Salt Gel may be mixed as rapidly as 5 minutes per sack, allowance must be made for the increased viscosity arising from circulation through the bit.

It is advisable to use a dust mask and eye protection while mixing all powdered products.

WHMIS: Controlled (see MSDS.)

TDG: Not regulated

Page-332


7.100 SALT Return to Table of Contents

DESCRIPTION

Common salt of >99% purity and whose chemical composition is Sodium Chloride, NaCl. PROPERTIES

Physical


White crystalline 2.2 1200-1280 kg/m3 <0.1% Not available

Chemical


Inorganic salt 100% (water) Not available Not applicable

APPLICATION Salt finds application in salt saturated mud systems, invert oil emulsions, work over and completion fluids. For drilling thick salt sections the mud is usually "saturated" with Sodium Chloride and or other salts to prevent washout. Complete saturation is dependent upon temperatures and usually occurs at a concentration of about 320.0 kg/m3 at room temperature. In the absence of other Chloride salts, the Sodium Chloride concentration can be approximated from the calculation: mg/l NaCl = l.65 x mg/L Cl In Invert oil emulsions sodium chloride is sometimes used as a salinity source to provide an activity balance between the mud's water phase and the formation water. MIXING AND HANDLING Salt mixes and dissolves readily in water. It is added to the mud system through the mud hopper. It is advisable to use a dust mask and eye protection while mixing all powdered products.


TDG: Not regulated

Page-333


7.101 SAPP Return to Table of Contents

DESCRIPTION

Sodium Acid Pyrophosphate (Na2H2P2O7) is widely used in industrial processes as a cleaner and dispersant. PROPERTIES

Physical

Appearance: Specific Gravity: Bulk Density: Melting Point:

Fine white powder 1.862 800 kg/m3 650ºC

Chemical


Acid Soluble (13gm/100ml water @ 25ºC) 4.0 (1% solution) >91 @ (0.25 kg/m3)

APPLICATION SAPP is used as a strong deflocculant (thinner) in fresh water mud systems. The main application is dispersion of mud rings when water drilling, and as a rapid thinner prior to cementing casing. In water drilling applications normally add 1-2 viscosity cups full of SAPP directly into the drill pipe at each connection. In areas with very reactive clays increased treatments will be required. When using to thin the mud prior to cementing, mix as required to the circulating mud system. MIXING AND HANDLING It is advisable to use a dust mask and eye protection while mixing all powdered products Avoid skin contact and do not inhale dust or allow contact with eyes. Do not ingest.


TDG: Not regulated

Page-334


7.102 SAWDUST Return to Table of Contents

DESCRIPTION

Finely processed wood chips, which swell when added to the mud system. PROPERTIES

Physical


Wheat color/wood odor Variable Variable Not available

Chemical


Wood by-product Not soluble (water) Not available Not applicable

APPLICATION Sawdust is used as a lost circulation material in water based muds. MIXING AND HANDLING Mix into mud with good agitation. No special handling or health hazards exist in using sawdust. However, it is advisable to use a dust mask and eye protection while mixing all products.


TDG: Not regulated

Page-335


7.103 SODA ASH Return to Table of Contents

DESCRIPTION

Sodium Carbonate anhydrous (Na2CO3) commonly known as Soda Ash, is a chemical compound of 99.7% purity. PROPERTIES

Physical


White odorless powder 2.53 1073 kg/m3 0.04% Not available

Chemical


Chemical Compound Soluble (18% @ 21ºC) Not determined Not applicable

APPLICATION Soda Ash is used to precipitate Calcium in make-up water or while drilling anhydrite stringers. Provided the saturation level of the Calcium salt has not been exceeded, the amount of Soda Ash required to treat out the Calcium can be approximated by: 350 mg/l Calcium ions require l.0 kg/m3 of Soda Ash. Over-treatment with Soda Ash can result in Carbonate alkalinity and consequent excessive Gel Strengths and problems due to increased fluid loss. MIXING AND HANDLING Soda Ash is added directly through the mud mixing hopper. It should be stored in a cool, dry place. Avoid contact with strong acids in confined areas.

Avoid inhalation of dust or contact with the eyes. If contact is made, rinse thoroughly with water for l5 minutes and seek medical attention if necessary. It is advisable to use a dust mask and eye protection while mixing all powdered products.


TDG: Not regulated

Page-336

PACKAGING: 25-40 kg sack

7.104 SODIUM BICARBONATE Return to Table of Contents

DESCRIPTION

Sodium Bicarbonate (NaHC03) is commonly known as Bi-Carb, Baking Soda or Bicarbonate of Soda. PROPERTIES

Physical

Appearance: Specific Gravity: Bulk Density: Moisture Content: Melting Point:

White crystalline powder 2.22 1040 kg/m3 0.25% 270ºC

Chemical


Chemical Compound Soluble (9.5% w/w @ 20ºC) 8.5 Not applicable

APPLICATION Sodium Bicarbonate is most commonly used for treating cement contamination by precipitating the Calcium as Calcium Carbonate and reducing the pH. The available H+ ion can reduce the pH in any drilling fluid with a pH above 8.5. As a pre-treatment for drilling hard cement, 22.6 kg of Sodium Bicarbonate will treat approximately 1 cubic foot of cement. If green cement is anticipated, 2-3 times as much Sodium Bicarbonate will be required. MIXING AND HANDLING Sodium Bicarbonate can be added directly through the hopper. Avoid inhaling and minimize skin contact. Sodium Bicarbonate absorbs moisture and dries the skin. Keep stored in a cool dry place to prevent caking and deterioration. Store away from acids. It is advisable to use a dust mask and eye protection while mixing all powdered products.


TDG: Not regulated

Page-337


7.105 SODIUM SULFITE CATALYZED Return to Table of Contents

DESCRIPTION

Sodium Sulfite (Na2SO3) is an Oxygen scavenger. It is soluble in water and catalyzed using a cobaltous compound. PROPERTIES

Physical

Appearance: Specific Gravity: Melting Point: Moisture Content: Flash Point:

White crystalline powder 2.63 Not available Not available Not flammable

Chemical


Oxygen scavenger Soluble (17% at 10ºC) Not available >91% @ (1.0 kg/m3)

APPLICATION Sodium Sulfite is used as an Oxygen scavenger in water based mud systems. It may also be used as an anti-oxidant to prevent polymer degradation. As an Oxygen scavenger it is added continually until the residual sulfite (SO3) concentration in the mud filtrate reaches or exceeds 300 mg/l. Thereafter this residual is maintained with daily treatments in the order of 20.0-60.0 kg depending on the severity of the dissolved oxygen content in the drilling mud. MIXING AND HANDLING Sodium Sulphite readily decomposes. It is usually added at a concentration of one to two sacks to a barrel of water. After mixing, the mixture is covered with a 10.0-15.0 cm blanket of mineral oil to minimize absorption of oxygen from the air. It is then slowly pumped into the central stream of the mud pump suction with an injection pump. Wear suitable protection for eyes and skin when handling. Use in areas with adequate ventilation.


TDG: Not regulated

Page-338


7.106 STAFLO REGULAR / EXLO SUPREME Return to Table of Contents

DESCRIPTION

Staflo Regular is a high molecular weight, Polyanionic Cellulose (polymer). It is also available in the lower molecular weight Staflo Exlo Supreme grade. PROPERTIES

Physical


Off-white free-flowing 1.5 300-900 kg/m3 Not applicable

Chemical


Fluid-loss Soluble (water @ 20º C) 6.0-8.5 (1% solution) Pending

APPLICATION Staflo is designed primarily as a fluid loss reducer in water-based drilling fluids. Staflo Regular also provides secondary viscosity. (Staflo Regular has approximately twice the viscosifying power in fresh water mud systems when compared to equal concentrations in saline water based mud systems). When fluid loss control without additional viscosity is required, Staflo Exlo Supreme should be used. Both Staflo Regular and Staflo Exlo Supreme are used in concentrations of 1.0-3.0 kg/m3 in fresh water based fluids. Salt-water based mud systems normally use concentrations of 3.0-10.0 kg/m3. Staflo Regular and Staflo Exlo Supreme can be used at temperatures up to 150º C. MIXING AND HANDLING Staflo should be stored in a dry location. In order to avoid lumping it is added to the mud system through the hopper at 30-40 minutes per sack. It is advisable to use a dust mask and eye protection while mixing all powdered products.


TDG: Not regulated

Page-339


7.107 STARLOSE Return to Table of Contents

DESCRIPTION

Starlose is a high performance pregelatinized non-fermenting, corn or potato Starch with a Biocide added. PROPERTIES

Physical

Appearance: Bulk Density: Moisture Content:

White granular 600 kg/m3 6-10%

Chemical


Pre-gelatinized corn or potato starch Soluble (water) 6.0-7.0 =3.0% @ (17.0 kg/m3)

APPLICATION Starlose provides fluid loss control and functions as a protective colloid in all water based mud systems. In particular Starlose finds applications in seawater, salt saturated and high calcium content systems where bottom hole temperatures exceed 85ºC. Starlose performs best in alkaline environments and will not increase the rheological properties of the mud system. Starlose is used in concentrations ranging from 8.0-40.0 kg/m3 depending somewhat on the amount of drilled solids present in the system. Oxygen scavengers can be used to reduce thermal degradation when required. MIXING AND HANDLING Starlose mixes readily and may be added to a mud system, through the hopper, at rates as high as five to ten minutes per sack if required. It is advisable to use a dust mask and eye protection while powdered products are being mixed.


TDG: Not regulated

Page-340


7.108 STARPAK DP Return to Table of Contents

DESCRIPTION

Starpak DP is a double derivatized Starch fluid loss control agent capable of enhancing rheology and providing lubricity when used in conjunction with various shear-thinning polymers. PROPERTIES

Physical

Appearance: Bulk Density: Moisture Content:

Off-white granular powder 480-640 kg/m3 5%

Chemical


Complexed starch Soluble (100% water) 5.0-7.0 (4% solution) =68% @ (16.0 kg/m3)

APPLICATION Starpak DP exhibits fluid loss control efficiencies closer to the celluloses and better than regular starches. The synergistic behavior of Starpak DP with Bentonite and other polymers enhances the shear thinning properties of a drilling fluid thus providing excellent hole cleaning at low shear rates. The ability of Starpak DP to coat clay and shale particles aids in controlling dispersion and the eventual destabilization of the well bore. Its ability to encapsulate drilled solids facilitates removal on surface. With the addition of an oxygen scavenger, Starpak DP can be temperature stable up to 150ºC. It is non-fermenting and requires no Biocide under normal conditions. It is also stable against drilling fluid enzyme contamination resulting in less viscosity breakdown than typical stabilized fluid loss polymers. Starpak DP is used in concentrations ranging from 5.0-25.0 kg/m3 depending on fluid loss requirements and the amount of solids in the system. MIXING AND HANDLING

Starpak DP mixes readily and may be added to a mud system through the hopper at 10-15 minutes per sack. It is advisable to use a dust mask and eye protection while mixing all powdered products.


TDG: Not regulated

Page-341


7.109 SULPHAMIC ACID Return to Table of Contents

DESCRIPTION

Sulphamic Acid is a dry, non-volatile, non-hygroscopic, stable solid. It is soluble in water and forms a strongly acidic aqueous solution that is comparable in acidity to the common strong mineral acids, but it can be safely handled and stored in the dry form. PROPERTIES

Physical

Appearance: Specific Gravity: Moisture Content:

White crystalline odorless 2.126 0.05%

Chemical


Acid Soluble (22g/100g water @ 20ºC) 1.18 (1% solution) Not applicable

APPLICATION Sulphamic Acid is used to reduce the pH of fluids requiring adjustment prior to disposal. Sulphamic Acid has many advantages over its alternatives, such as ease of handling, solubility and low corrosiveness. MIXING AND HANDLING As with most highly reactive products dry Sulphamic Acid should always be added to water, rather than the opposite, to prevent a violent reaction from occurring. At room temperature, dilute aqueous Sulphamic Acid is stable for a long period of time but hydrolysis occurs at elevated temperatures. Rubber gloves, full clothing, rubber apron and eye and face protection are recommended when mixing to avoid contact with unprotected skin. Contaminated clothing should be laundered before reuse.



Page-342


7.110 SUPER-LIG Return to Table of Contents

DESCRIPTION

Super-Lig is a naturally oxidized coal known as Leonardite. The name applies to all forms of highly weathered humic acid. PROPERTIES

Physical


Dark brown/black powder 1.5 16-24% >200ºC

Chemical

Mineral: Solubility: pH: Microtox:

Leonardite Soluble (pH dependant) 1.45 (1% solution) Pending

APPLICATION Super-Lig is used in water-based muds as a thinner (dispersant), oil emulsifier and a secondary filtration control agent. Concentrations vary from 6.0-60.0 kg/m3 depending upon the solids content of the system. Super-Lig is also a much more stable thinner and filtration control additive at high temperatures than are the Lignosulfonates. Super-Lig requires the presence of hydroxyl ions (OH-) for maximum effectiveness. MIXING AND HANDLING Mix directly through the mud hopper. Caustic Soda additions will be required to maintain the pH at 9.5 or higher. It is advisable to use a dust mask and eye protection while mixing all powdered products.



Page-343


7.111 T-352 BIOCIDE Return to Table of Contents

DESCRIPTION

This product is a registered Biocide under Agriculture Canada's "Pest Control Products Act". (Registration # 22698). T-352 is a non-ionic, glutaraldehyde-based Biocide in a clear liquid form. PROPERTIES

Chemical

Physical Appearance: Specific Gravity: Freeze Point:

Clear liquid 1.0634 @ 15º C -6º C


Bactericide Soluble (100% in water) 3.2 >100% @ (0.1-0.5 L/m3)

APPLICATION T-352 is effective in controlling both aerobic and anaerobic (sulfate reducing) bacteria. It is compatible with all water based drilling fluids and can be neutralized prior to disposal (see below). The recommended treatment is dependent on the severity of the bacterial contamination. As a pre-treatment, add 0.1-0.5 L/m3 to the mud system and monitor with microbial dip slides. For already contaminated fluids, add 0.5-2.0 L/m3 treatments until bacterial control is achieved. Microtox Analysis: A series of microtox tests have determined the following procedure will deactivate T-352 and should provide a non-toxic response in drilling muds. 1.Increase the pH of the mud to 12.0 and hold for four hours. 2.Neutralize mud back to pH 7.0 with an appropriate acid. MIXING AND HANDLING

T-352 should be added at a point of low agitation. Do not mix through the hopper or at a point of high agitation as splashing may occur. T-352 is corrosive and will cause irreversible eye damage. Wear suitable protection for eyes and skin and ensure there is adequate ventilation in the mixing area.

WHMIS: See MSDS (Registration #22698 Pest Control Products Act)

TDG: Not regulated

Page-344


7.112 THIN-TEX Return to Table of Contents

DESCRIPTION

Thin-Tex is a chrome free, deflocculant and general fluid conditioner. Thin-Tex does not require the addition of Caustic Soda or other alkaline material for activation and functions best in the pH range of 7.0 to 9.0. Thin-Tex is a modified organic lignin coupled with a synthetic co-polymer that will function within a broad range of drilling fluids. PROPERTIES

Physical

Appearance: Bulk Density: Moisture Content: Flash Point:

Brown powder freeflowing Not determined Not determined Not determined

Chemical


Modified Lignin and salt of Acrylic Co-Polymer Soluble (water) Not available >91 @ (2.85 kg/m3)

APPLICATION Thin-Tex functions effectively at low concentrations to control rheology and Gel Strengths in water base systems. Thin-Tex works particular well in high solids muds, Bicarbonate, Sulfate and Calcium contaminated muds and high temperature environments exceeding 125ºC. Time and temperature will continue to improve the performance of Thin-Tex. Alkalinity beyond the range of 7.0 to 9.0 is not required. The concentration range for the use of Thin-Tex will vary from 0.75 kg/m3 to 6.0 kg/m3 depending on the fluid make up, solids content, temperature and degree of contamination. MIXING AND HANDLING Thin-Tex can be added through the mud hopper or a chemical barrel. When adding Thin-Tex to a system it is not necessary to add Caustic Soda. Avoid breathing dust when mixing and avoid prolonged contact with skin. Use protective clothing, e.g.: gloves, goggles, dust mask, etc. Store in a dry place as this product will absorb moisture.


TDG: Not regulated

Page-345


7.113 TORQ-2000 Return to Table of Contents

DESCRIPTION

TORQ-2000 is a non-foaming liquid blend of special non-polluting oils and surfactants. It is non-flammable and biodegradable. PROPERTIES

Chemical

Physical Appearance: Specific Gravity: Flash Point:

Dark amber oily odor 0.946 @ 20ºC >130ºC


Blend of Anionic Surfactants Insoluble, Dispersible 6.0-7.5 =10 @ (5.0 L/m3)

APPLICATION TORQ-2000 may be used in fresh-water muds, and salt-based systems. TORQ-2000 is recommended to improve the lubricity of drilling and completion fluids. It reduces friction between the drill string and walls of the hole. Torque and drag common in crooked and directional holes can be minimized by the addition of TORQ-2000 in the range of 1.0-3.0% by volume (10.0-30.0 litres/m3). Soft shales have fewer tendencies to adhere to bits and drill collars when TORQ-2000 is present in the drilling fluid in a concentration of 15.0-20.0 L/m3. To free stuck pipe add TORQ-2000 in a concentrated pill of drilling mud at a concentration of 60.0-80.0 liters in 8.0-10.0 m3of spotting fluid. Corrosion in drilling and completion fluids is reduced when TORQ-2000 is present in the system. General Purpose Lubrication: TORQ-2000 can be sprayed on moving parts or exposed steel surfaces to lubricate and protect metal from corrosive attack. It is an excellent penetrating lubricant. MIXING AND HANDLING TORQ-2000 can be added directly at the pump suction. Wear skin and eye protection when mixing.


TDG: Not regulated

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7.114 TORQ-GLIDE Return to Table of Contents

DESCRIPTION

Torq-Glide is a non-foaming, highly effective ester based lubricant designed to reduce torque and drag in deviated hole sections where oil and water based drilling fluids are being utilized. PROPERTIES

Physical

Appearance: Specific Gravity: Boiling Point: Pour Point: Flash Point:

Amber liquid 1.08 Not determined -15C >100ºC

Chemical


Ester Not soluble (water) Not available >91% @ (0.17 L/m3)

APPLICATION Torq-Glide is used as a lubricant in brine, fresh-water and oil based drilling fluids to reduce torque and drag in horizontal or highly deviated hole sections. Torq-Glide reduces friction in areas where the drill string comes into contact with formation or casing. Torq-Glide may be added as a percentage (1.0-3.0% by volume) of the fluid system where torque and drag are a continuous problem (10.0-30.0 litres/m3). Soft shale will have fewer tendencies to adhere to bits and drill collars when Torq-Glide is present in the drilling fluid. To minimize bit balling add 6.0-12.0 L/m3 Torq-Glide and maintain this concentration with additions at the pump suction. To help prevent differential sticking maintain 15-25.0 L/m3 of Torq-Glide in the mud system. When used at higher concentrations and spotted in pill form, Torq-Glide will contribute to the freeing of stuck pipe. For use as a spotting fluid add 60.0 – 80.0 L/m3 of Torq-Glide to 10 m3 of diesel or crude oil and spot across the stuck zone. Drilling and completion fluids treated with Torq-Glide are less corrosive. MIXING AND HANDLING Add Torq-Glide at the pump suction for reduction of torque and drag. Torq-Glide can be added as required to improve the sliding of the drill string when building or maintaining hole angle. Skin and eye protection should be observed. (See Material Safety Data Sheet for further information).


TDG: Not regulated

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PACKAGING: 210 liter drum

7.115 TORQ-TROL II Return to Table of Contents

DESCRIPTION

Torq-Trol II is principally composed of a Sodium Salt of sulfated vegetable oil. Trol II is both oil and water-soluble.

Torq-

PROPERTIES

Physical


Clear/amber, fatty odor 1.03 >93ºC (PMCC)

Chemical


Sulfated Oil Sodium Salts Soluble (oil, water) 6.8 (2% solution) =12% @ (5.0 L/m3)

APPLICATION Torq-Trol II may be used in fresh-water muds, salt-based muds and oil based systems. Torq-Trol II is recommended to improve the lubricity of drilling and completion fluids. It reduces friction between the drill string and walls of the hole. Torque and drag common in crooked and directional holes can be minimized by the addition of Torq-Trol II in the range of 1.0-3.0% by volume (10.0-30.0 litres/m3). Soft shales have fewer tendencies to adhere to bits and drill collars when Torq-Trol II is present in the drilling fluid in a concentration of 15.0-20.0 L/m3. To free stuck pipe add Torq-Trol II in a concentrated pill of drilling mud at a concentration of 60.0-80.0 liters in 8.0-10.0m3of spotting fluid. Corrosion in drilling and completion fluids is reduced when Torq-Trol II is present in the system. General Purpose Lubrication: Torq-Trol II can be sprayed on moving parts or exposed steel surfaces to lubricate and protect metal from corrosive attack. It is an excellent penetrating lubricant. MIXING AND HANDLING Torq-Trol II should be added slowly to the mud system through the mixing hopper or wherever there is good agitation. Wear suitable protection for eyes, skin and clothing (see Material Safety Data Sheet for further information). NOTE: The addition of Torq-Trol II will cause foaming in some mud systems. A pre-treatment of 3-5 pails of a Defoamer is recommended prior to any additions of Torq-Trol II. WHMIS: Controlled (see MSDS)

TDG: Not regulated

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7.116 ULTRA SEAL (XP, C, PLUS) Return to Table of Contents

DESCRIPTION

Ultra Seal is a blend of specific micro-sized cellulose fibers, combined with a blend of organic polymers and lubricity enhancers. It is a light tan powder that is insoluble in water. PROPERTIES

Physical


Light tan fibrous powder .613 Not available Not available Not available

Chemical


Organic cellulose fibers Not soluble Not available Not applicable

APPLICATION Ultra Seal-XP is the fine grind material that is most effective for controlling seepage and providing protection against differential sticking. It can be added evenly throughout the system in concentrations of 10.0-25.0 kg/m3. For applications such as sweeps or pills, concentrations as high as 85 kg/m3 may be required. Ultra Seal-C is a coarser grind material effective in situations where whole mud losses are prevalent. Recommended usages are the same as Ultra Seal-XP and a combination of Ultra Seal-XP and Ultra Seal-C may be necessary to provide a broader particle size distribution. Ultra Seal-Plus is a combination of Ultra Seal-XP and Ultra Seal-C in addition to a larger proprietary sealing agent for total loss circulation. Concentrations of 55.0-170.0 kg/m3 mixed in 15 m3 pills are recommended for spotting across the loss zone. MIXING AND HANDLING

Ultra Seal can be mixed through the mud hopper or directly into the mud system at a point of agitation. Note: A dust hazard is present while Ultra Seal is being mixed. It is advisable to use a dust mask and eye protection while mixing all powdered products.


TDG: Not regulated

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PACKAGING: 25-40 lb sack

7.117 WALNUT Return to Table of Contents

DESCRIPTION

A lost circulation material of ground Walnut available in three grades, fine, medium, and coarse, ranging in size from 100 mesh to 6 mesh. PROPERTIES

Physical


Tan granular to flour-like Not available Not available Not available Not available

Chemical


Nut shells Not soluble (water, oil) Not applicable =43% (7.0 kg/m3)

APPLICATION Used as a lost circulation material or bridging agent due to its granular nature. Walnut is chemically inert and may be added to any mud system. Walnut is also used as a drag reducer in deviated holes. When circulated past the tight hole section immediately prior to a trip the irregular particles are embedded in the filter cake and act as bearings to reduce the hole drag. MIXING AND HANDLING As a cure for lost circulation, mix Walnut into the mud or in a lost circulation pill in concentrations of 10.0-30.0 kg/m3. It is advisable to use a dust mask and eye protection while mixing all powdered products.


TDG: Not regulated

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7.118 WYOMING GEL Return to Table of Contents

DESCRIPTION

Sodium Montmorillonite (Wyoming Gel) is sold under various trade names. In fresh water it yields 92-100 bbl/ton of 15 cps viscosity mud. Wyoming Gel conforms to the following API specifications (API Spec 13A, Section 4 Fourteenth Ed. Aug. 1991). Suspension of 22.5 grams in 350 ml of distilled water. PROPERTIES

Physical

Appearance: Specific Gravity: Bulk Density: Moisture Content:

Tan powder 2.45-2.55 881 kg/m3 10% Maximum

Chemical

Mineral: Solubility: pH: Microtox:

Sodium Montmorillonite Not soluble (forms colloidal suspension) 9.1 (5% suspension) Not applicable

APPLICATION Wyoming Gel is used for viscosity and filtration control in fresh water mud systems. In muds with a salinity of 3500 mg/L or higher, the Bentonite should first be prehydrated in fresh water. MIXING AND HANDLING Mix directly through the mud hopper at no faster than 4-6 minutes per sack. Avoid breathing dust. It is advisable to use a dust mask and eye protection while mixing all powdered products.


TDG: Not regulated

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7.119 XANVIS POLYMER Return to Table of Contents

DESCRIPTION

Xanvis Polymer is a clarified, completion grade, Xanthan Biopolymer to be used as a premium viscosifier particularly for use in production zones. PROPERTIES

Physical

Appearance: Specific Gravity: Moisture Content: Bulk Density:

Cream to tan powder Not available 13.3% 640-961 kg/m3

Chemical


Xanthan Biopolymer Complete (water) 7.0 (1% solution) >100% @ (6.0 kg/m3)

APPLICATION Horizontal well bore simulations show that when flow is initiated, settled solids tend to move along the bottom of the hole as waves or dunes. This solids build up can result in increased torque, drag and the inability to transfer weight to the bit. Xanvis provides optimum cleaning characteristics in horizontal hole sections. In addition to providing excellent rheology for hole cleaning while drilling, Xanvis provides for exceptional suspension of solids during non-circulating periods. These properties cannot be properly described using conventional Fann viscometers. The optimum concentration of Xanvis is 2.8-8.5 kg/m3 depending upon the application. MIXING AND HANDLING Xanvis can be easily mixed through the mud hopper. Care should be taken, as with most polymers, to avoid mixing too quickly to prevent any potential for lumping. It is advisable to use a dust mask and eye protection while mixing all powdered products.


TDG: Not regulated

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7.120 XL-DEFOAMER Return to Table of Contents

DESCRIPTION

XL-Defoamer is an anionic, high molecular weight surfactant defoamer. PROPERTIES

Physical


Clear liquid sweet odor 0.89 >80ºC (PMCC)

Chemical


Surfactant Insoluble-Dispersible (water) 7.0-8.0 >75% @ (0.5 L/m3)

APPLICATION XL-Defoamer is a powerful defoamer intended for use in oilfield applications where mild to severe foaming of aqueous based fluids has occurred. It is effective at all pH ranges, at high temperatures and over a wide salinity range. Normal treatment for light foam is 0.3-0.9 L/m3 and with more difficult foams, 0.9-1.8 L/m3 may be required. MIXING AND HANDLING For maximum effectiveness XL-Defoamer should be added directly to the fluid system as close to the point of foaming (e.g. shale shaker) as possible. It may also be sprayed over the fluid through a wash gun diluted in a mineral oil mixture if necessary (e.g. over mud tanks). XL-Defoamer may cause irritation to the skin and eyes. Use rubber gloves, rubber apron, mask and eye protection when using this and other liquid mud additives. In case of skin contact, wash with water as required. In case of eye contact, wash with water for at least fifteen minutes and seek medical attention if necessary. Although stable, do not store XL-Defoamer near strong oxidizing agents.


TDG: Not regulated

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7.121 ZINC CARBONATE Return to Table of Contents

DESCRIPTION

Zinc Carbonate (ZnCO3) is used as a scavenger of Hydrogen Sulfide. PROPERTIES

Physical


White crystalline powder 4.4 Not available Not available Not flammable

Chemical


Chemical Compound Soluble >0.1% (water) Not available =36% @ (14.0 kg/m3)

APPLICATION Zinc Carbonate is used as an H2S scavenger in water based drilling muds. As a pre-treatment, concentrations vary from 6.0-14.0 kg/m3 depending on the severity of the expected sour gas. To effectively control the carbonate added, add approximately 0.25 kg of Lime to the mud system for every kilogram of Zinc Carbonate added to the mud. Approximately 1.0 kg/m3 of Zinc Carbonate is required to remove 256 mg/L of dissolved H2S. Zinc Carbonate can cause rheological and alkalinity problems in Bentonite based mud systems and on wells where there are elevated mud temperatures. MIXING AND HANDLING Zinc Carbonate can be added directly to the mud hopper. It is advisable to use a dust mask and eye protection while mixing all powdered products.


TDG: Regulated: (see MSDS)

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TABLE OF CONTENTS – CHAPTER 8 Chapter 8 Hydraulics Return to Glossary TOPICS

8.1 8.2 8.3

8.4

8.5 8.6 8.7 8.8 8.9 8.10

PAGE

INTRODUCTION VISCOSITY FLUID MODELS 8.3.1 BINGHAM PLASTIC FLUID MODEL 8.3.2 POWER LAW FLUID MODEL LAMINAR / TURBULENT FLOW 8.4.1 CRITICAL ANNULAR VELOCITY 8.4.2 REYNOLDS NUMBER PRESSURE LOSS JET NOZZLE VELOCITY JET IMPACT FORCE – HYDRAULIC POWER SURGE AND SWAB PRESSURES SLIP / TRANSPORT VELOCITY HYDRAULIC FORMULAS 8.10.1 LOW SHEAR RATE RANGE: “n” AND “K” VALUES (Annulus Equations) 8.10.2 PLASTIC VISCOSITY AND YIELD POINT 8.10.3 PUMP OUTPUT (m3/min) – 100% EFFICIENCY 8.10.4 ANNULAR VELOCITY 8.10.5 VELOCITY (m/min) – PIPE FLOW 8.10.6 CRITICAL VELOCITY (m/min) – ANNULUS 8.10.7 SHEAR RATE (sec-1) – ANNULUS 8.10.8 SHEAR STRESS (Pa) 8.10.9 EQUIVALENT VISCOSITY (mPa.s) 8.10.10 REYNOLDS NUMBER – ANNULUS (See Section 9.4.2) 8.10.11 PRESSURE LOSS (kPa) – ANNULUS 8.10.12PRESSURE LOSS (kPa) – PIPE FLOW 8.10.13 PRESSURE LOSS (kPa) – SURFACE EQUIPMENT 8.10.14 PRESSURE AVAILABLE FOR NOZZLE SELECTION (kPa) 8.10.15 BIT PRESSURE LOSS (kPa) 8.10.16 BIT NOZZLE VELOCITY (m/sec 8.10.17 HYDRAULIC POWER AT THE BIT (Kilowatts – KW) 8.10.18 JET IMPACT FORCE (N) 8.10.19 EQUIVALENT CIRCULATING DENSITY (kg/m3) 8.10.20 SLIP VELOCITY (m/min) 8.10.21 TRANSPORT VELOCITY (m/min) 8.10.22 ANNULAR VELOCITY (m/min) – TRIPPING 8.10.23 SURGE OR SWAB PRESSURE (kPa 8.10.24 MUD DENSITY CHANGE DUE TO SURGE OR SWAB PRESSURES (kg/m 3

Page-355

2 2 2 2 3 4 5 5 5 6 6 7 7 7 7 8 8 8 9 9 9 10 10 10 11 11 12 12 12 13 13 13 13 14 14 15 15 16

CHAPTER 8 HYDRAULICS 8.1

INTRODUCTION


The primary function of a drilling fluid is to remove drilled cuttings from the well bore. This is accomplished by flowing the fluid upward in the annulus faster than the rate at which the cuttings would otherwise fall. The flow rate or annular velocity is limited by the output of the pump as well as pressure and formation considerations. However, the rate at which cuttings fall in a fluid can be reduced by increasing the viscosity and thixotropy of the fluid. The fluid properties must be designed to work with the available system hydraulics to optimize hole cleaning, penetration rate and minimize well bore damage.

8.2

VISCOSITY

The viscosity of a fluid is the ratio of shear stress to shear rate. Shear stress () is the resistance of a fluid to an applied rate of shear, and can be related to pump pressure. The amount of force applied to a fluid determines the shear rate (), which is related to the velocity of the fluid through a particular geometric configuration (well bore, viscometer). Shear stress is expressed in Pascal’s (Pa), and shear rate in reciprocal seconds (sec-1) or rpm. Viscosity ()

8.3

= Shear Stress () Shear Rate () = (Viscometer Deflection X 0.511) (rpm X 1.7034) = Pa sec-1 = Pa.s

FLUID MODELS

Most drilling fluids are considered non-Newtonian in that their viscosities change with varying rates of shear. They also exhibit similar flow characteristics to 2 non-Newtonian fluid models used to predict and evaluate their behavior; Bingham Plastic and Power Law (Pseudoplastic).

8.3.1

BINGHAM PLASTIC FLUID MODEL


The flow curve for the Bingham Plastic model is a straight line passing through the 300 and 600 rpm measurement and projected to the shear stress axis. Plastic viscosity is proportional to the slope of this line, and is a measure of the fluids' internal resistance to flow produced by interparticle friction. The Yield Point is the intercept on the shear stress axis and is defined as the shear stress required to initiate flow. It can also be described as the resistance to flow produced by the attractive forces between fluid particles. The main advantage of the Bingham model is the simplicity in calculating PV/YP. Its disadvantage is it only describes fluid flow behavior over the higher shear rate range of 511 to 1022 sec-1 (300 to 600 rpm Viscometer).

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PV (mPa.s) = 600 - 300  = viscometer dial reading YP = 300 - PV 2

BINGHAM PLASTIC FLUID MODEL CURVE

VISCOMETER RPM

8.3.2

POWER LAW FLUID MODEL


The Power Law model for pseudoplastic fluids more accurately describes fluid flow behavior in the lower shear rate ranges normally encountered in the annulus, and is defined by the equation:  = Kn  = Shear Stress (Pa) K = Consistency Index (Pa.s)  = Shear Rate (sec-1) n = Power Law “n” Index (dimensionless) The Power Law Index "n" is an indication of the degree of non-Newtonian behavior that a fluid shows over a defined shear rate range. Newtonian fluids, such as water and oil, have an "n" value of 1.0. As the fluid becomes more non-Newtonian or shear thinning, the "n" value decreases from the Newtonian value of 1.0. This means that the viscosity of the drilling fluid will decrease with increasing shear rate, and increase with a decrease in shear rate.

Page-357

Lowering the "n" value improves the hole cleaning capabilities of the drilling fluid by • Increasing the effective annular viscosity. • Flattening the annular velocity profile which promotes laminar flow. For lowering the “n” value, the following basic guidelines may be followed: • Additions of Kelzan XCD Polymer. • Additions of prehydrated Bentonite - (in K2SO4 or KCI / prehydrated Bentonite systems) • Extending Bentonite in fresh water systems. • Removing high "n" value materials such as drilled solids and dispersed Bentonite. The Consistency Index "K" is the shear stress of the drilling fluid at I sec -1. Increasing the "K" value will normally indicate an increase in hole cleaning capability. With an increase in the "K" value, there should be a corresponding decrease in the "n" value. This can be accomplished with the following additions: • Additions of Kelzan XCD Polymer • Prehydrated Bentonite is semi-flocculated mud systems ( K2SO4 or KCl / prehydrated systems. • Normal drilling fluid viscosifiers One can also raise the "K" value without changing the "n" value with the following additions: • Barite • Inert solids • Bentonite For maximum drilling performance, the "K" value should be increased while lowering the "n" value. Raising the "K" value by raising the solids concentration is usually not desirable or economical. The low shear range "n" and "K" factors can be determined with a two speed viscometer by plotting the 300 rpm reading and the initial Gel Strength. If a multi-speed viscometer is available, plot the 6 and 100 rpm readings. The "n" value is determined as the slope of the line drawn through these two points, and the "K" value is the shear stress intercept at 1 sec-1. The low shear range "n" and "K" values should be used in laminar annular flow equations,

8.4

LAMINAR / TURBULENT FLOW


Drilling fluids are assumed to be in either laminar or turbulent flow dependent on the flow rate, flow channel dimensions, and the rheological properties of the fluid. Laminar flow, which generally exists at the low shear rates encountered in the annulus, is the uniform movement of fluid elements parallel to the walls of the flow channel. Turbulent flow exists when the flow velocity exceeds a certain critical value. This flow regime is characterized by erratic fluid particle movement. Borehole erosion and greater degradation of drilled cuttings result from turbulent annular flow. With the proper PV/YP or n/K ratios, the lifting advantages of turbulent flow can be obtained in laminar flow.

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8.4.1

CRITICAL ANNULAR VELOCITY

The calculated critical annular velocity is the flow rate above which turbulence occurs. Below this value the fluid may be in laminar flow or in transition flow.

8.4.2

REYNOLDS NUMBER


Another way of assessing whether flow is in laminar or turbulent flow, is by determining the Reynolds Number (Re). Re = Diameter X Velocity X Density Viscosity

With Newtonian fluids (water), "n" = 1. The transition to turbulent flow begins at approximately 2100. Above 3000 flow is fully turbulent. With non-Newtonian drilling fluids, the laminar flow limit may be increased by reducing the "n" value. Reynolds Number at Upper Laminar Limit vs. "n"

8.5

Re

“n”

±2100 ±2400 ±2600 ±2900 ±4000

1.0 0.8 0.6 0.4 0.2

PRESSURE LOSS


When a drilling fluid is pumped through a pipe, the pressure exerted on the drilling fluid will decrease along the direction of flow. The amount of pressure required is in direct relation to the length of the circulating system, fluid properties and the size of the flow channel. For constant drilling fluid velocity, the pressure loss increases with an increase in pipe diameter. For a constant drill pipe diameter the pressure loss will increase with an increase in the drilling fluid velocity. Pressure losses are calculated for the following: • Surface equipment • Drill pipe bore • Drill collar bore • Annulus by drill pipe • Annulus by drill collars • Through bit nozzles

Page-359

Only a small percentage of the circulating pressure is lost in the annulus. The largest percentage of the circulating pressure is lost through the pipe and bit nozzles. Total pressure loss in a mud system is affected by the drilling fluid properties, such as mud density, Plastic Viscosity, and Yield Point. Pressure loss values also differ for turbulent and laminar flow. Turbulent flow generally exists in the surface equipment, inside the drill string and through the bit nozzles. In the annulus, the drilling fluid can be either in turbulent flow or laminar flow.

8.6

JET NOZZLE VELOCITY


Bit nozzle velocity is closely related to the cleaning action taking place at the bit. The higher the nozzle velocity, the better the cleaning action and penetration rates. It is possible to have nozzle velocities which are too high for the formations being drilled. When this is the case, severe hole enlargement may take place at the bit. As a portion of the jet nozzle stream impinges on the hole wall, high jet velocities may actually weaken the formation walls which may, at some later time, create a sloughing problem. The following chart is a guideline for nozzle velocities in different formations.

FORAMTION CHARACTERISTICS Hard, Competent Medium Hard Fractured, Faulted Soft, gummy, stick, fairly competent and gauge hole not important Soft, gummy, stick, gauge hole important

8.7

NOZZLE VELOCITY (metres/sec) 115-120 105-115 95-105 95-120 85-95

JET IMPACT FORCE – HYDRAULIC POWER

Two factors considered important for cleaning the hole beneath the bit are jet impact force and hydraulic power. Jet impact force is based on theory that formation is best removed from beneath the bit when the force of the jets striking the bottom of the hole is at its maximum. This condition can be obtained when circulation rates and bit nozzle sizes are used which cause 48% of the available pump pressure to be used to force the drilling mud through the bit nozzles. For example, if the maximum standpipe pressure is 15,000 kPa, then 0.48 x 15,000 = 7200 kPa would be used to force the fluid through the bit nozzles to obtain maximum impact force. Maximum hydraulic horsepower is based on the theory that the hole is best cleaned beneath the bit by delivering the most power to the bottom of the hole. Maximum hydraulic power below the bit can best be obtained when circulation rates and bit nozzle sizes are used which cause 65% of the available pump pressure to be used to force the drilling mud through the bit nozzles. For example, if the maximum standpipe pressure is 15,000 kPa, then O.65 x 15,000 = 9,75O kPa would be used to force the drilling mud through the bit nozzles to obtain maximum power at the bit.

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8.8

SURGE AND SWAB PRESSURES


Swab pressures occur when pulling pipe and result in a hydrostatic head reduction, which in some cases, could be sufficient to cause a blowout. Swab pressures also develop when pipe decelerates while running in the hole. Surge pressures occur when running in the hole and may induce fracturing with a consequent loss of circulation. Surge pressures are also created when breaking circulation. The two main factors affecting surge and swab pressures are: • The rate at which pipe is tripped. • The drilling fluid properties. Exact determination of these pressures requires extensive calculations. The formulas presented for field usage calculate a single effective annular velocity using an average mud clinging constant of 0.45. Turbulent flow is assumed with pipe velocities in excess of 60 m/min.

8.9

SLIP / TRANSPORT VELOCITY


The rate at which a drilling fluid will carry solid particles to the surface (transport velocity), depends on the velocity of the fluid as well as the rate at which the particle will fall through the liquid under the influence of gravity (slip velocity). If a hole cleaning problem exists, calculating the slip and transport velocity is beneficial in determining what changes can be made to the fluid properties or annular velocity to assist the removal of cuttings.

8.10

HYDRAULIC FORMULAS

8.10.1 LOW SHEAR RATE RANGE: “n” AND “K” VALUES (Annulus Equations) Plot 300 and 3 rpm readings “n” value = log10 300 - log10 3 log10 511 – log10 5.1 or “n” value = 0.5 log10 [ 300 ] 3 “K” value = Shear Stress at 1 sec-1 or “K” value = 0.511 X 300 511n

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Plot 100 and 6 rpm readings (multispeed viscometer) “n” value = log10 100 - log10 6 log10 170 – log10 10 “K” value = Shear Stress at 1 sec-1 n = Low Shear Rate Range, “n” Value K = Low Shear Rate Range, “K” Value  = viscometer dial reading

8.10.2 PLASTIC VISCOSITY AND YIELD POINT


PV = 600 - 300 YP = 300 - PV 2 Where: PV = Plastic Viscosity, mPa.s YP = Yield Point, Pa  = viscometer dial reading

8.10.3 PUMP OUTPUT (m3/min) – 100% EFFICIENCY Duplex Pump: Q = S X 1.57 X 10-9 X Ls (2Ld2 – Rd2) Triplex Pump: Q = S X 2.356 X 10-9 X Ls X Ld2 Where: Q = Pump Output, m 3/min Ls = Stroke Length, mm Ld = Liner Diameter, mm Rd = Rod Diameter, mm

8.10.4 ANNULAR VELOCITY


Va = 1.273 X 106 X Q D 12 – D 22 Where: Va = Annular Velocity, m/min Q = Pump Output, m 3/min D1 = Hole Diameter, mm D2 = Pipe OD, mm

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8.10.5 VELOCITY (m/min) – PIPE FLOW


Vp = Q X 106  X di2/4 Where: Vp = Pipe Flow Velocity, m/min Q = Pump Output, m 3/min di = Inside Diameter of Pipe, mm

8.10.6 CRITICAL VELOCITY (m/min) – ANNULUS 1_

105

Vc = [ 9.02 X 

XK]

2-n

n_

[(

200__) (2n + 1) ] ( D1–D2) (3n)

Where: Vc = Critical Velocity Annulus, m/min K = “K” Value  = Fluid Density, kg/m3 n = “n” Value D1 = Hole Diameter, mm D2 = Pipe OD, mm

8.10.7 SHEAR RATE (sec-1) – ANNULUS  = 200 X Va D1 – D2

( 2n+1) 3n

Where:  = Shear Rate – Annulus, sec-1 Va = Annular Velocity, m/min n = “n” Value D1 = Hole Diameter, mm D2 = Pipe OD, mm

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2-n

8.10.8 SHEAR STRESS (Pa) Determine shear stress () at calculated shear rate () from graph or  = Kn Where:  = Shear Stress Annulus, Pa K = “K” Value  = Shear Rate – Annulus, sec-1 n = “n” Value

8.10.9 EQUIVALENT VISCOSITY (mPa.s)


 = ( ) X 1000  Where:  = Equivalent Viscosity – Annulus, mPa.s  = Shear Stress – Annulus, Pa  = Shear Rate – Annulus, sec-1

8.10.10 REYNOLDS NUMBER – ANNULUS (See Section 9.4.2) Re = (D1 – D2) X Va X  (60)  Where: D1 = Hole Diameter, mm D2 = Pipe OD, mm Va = Annular Velocity, m/min  = Fluid Density, kg/m3  = Equivalent Viscosity – Annulus, mPa.s

Page-364

8.10.11 PRESSURE LOSS (kPa) – ANNULUS


Turbulent Flow: PL = 6.357 X 106 X 0.87 X Q1.87 X PV0.13 X L (D1 – D2)3 X (D1 + D2)1.87 Where: PL = Pressure Loss – Annulus, kPa  = Fluid Density, kg/m3 Q = Pump Output, m 3/min PV = Plastic Viscosity, mPa.s L = Pipe Length, m D1 = Hole Diameter, mm D2 = Pipe OD, mm Laminar Flow: n

PL = [ (200 Va) (2n +1) ] (D1 – D2) (3n)

4 (K) (L) (D1 – D2)

Where: PL = Pressure Loss – Annulus, kPa Va = Annular Velocity, m/min n = “n” Value K = “K” Value L = Pipe Length, m D1 = Hole Diameter, mm D2 = Pipe OD. mm

8.10.12 PRESSURE LOSS (kPa) – PIPE FLOW Turbulent Flow: PL = 5.22 X 106 X 0.85 X Q1.85 X PV0.15 X L Di4.85 Where: PL = Pressure Loss – Pipe Flow, kPa  = Fluid Density , kg/m3 Q = Pump Output, m 3/min PV = Plastic Viscosity, mPa.s L = Pipe Length, m Di = Pipe ID, mm

Page-365


8.10.13 PRESSURE LOSS (kPa) – SURFACE EQUIPMENT PL = 0.35 X SF X  X Q


Where: PL = Pressure Loss – Surface Equipment, kPa SF = Surface Factor (from table)  = Mud Density, kg/m3 Q = Pump Output, m 3/min

TYPE 1 2 3 4

STANDPIPE Length I.D. (mm) (mm) 12.2 76 12.2 89 13.7 102 13.7 102

HOSE Length I.D. (mm) (mm) 13.7 51 16.8 64 16.8 76 16.8 76

SWIVEL Length I.D. (mm) (mm) 1.2 51 1.5 57 1.5 57 1.8 76

KELLY Length I.D. (mm) (mm) 12.2 57 12.2 83 12.2 83 12.2 102

8.10.14 PRESSURE AVAILABLE FOR NOZZLE SELECTION (kPa) P = Operating Pressure – System Pressure Loss (9.9.11 / 9.9.12 / 9.9.13) Where: P = Pump Pressure, kPa

8.10.15 BIT PRESSURE LOSS (kPa) BPL = 24.8 X 104 X  X Q2 (Nd12 + Nd22 + Nd32)2 Where: BPL = Bit Pressure Loss, kPa  = Fluid Density, kg/m3 Q = Pump Output, m 3/min Nd1 = Bit nozzle Diameter, mm Nd2 = Bit nozzle Diameter, mm Nd3 = Bit nozzle Diameter, mm

Page-366


FACTOR SF 1.0 0.36 0.22 0.15

8.10.16 BIT NOZZLE VELOCITY (m/sec) Vn = ( X Nd1

2/4)


1.66 X 104 X Q___________ + ( X Nd22/4) + ( X Nd32/4)

Where: Vn = Bit Nozzle Velocity, m/sec Q = Pump Output, m 3/min  = Pi (3.14285) Nd1 = Bit nozzle Diameter, mm Nd2 = Bit nozzle Diameter, mm Nd3 = Bit nozzle Diameter, mm

8.10.17 HYDRAULIC POWER AT THE BIT (Kilowatts – KW) (Where BPL = Bit Pressure Loss) HP = BPL X Q 60 Where: HP = Hydraulic Power at the Bit, KW BPL = Bit Pressure Loss, kPa Q = Pump Output, m 3/min

8.10.18 JET IMPACT FORCE (N) Return to Table of Contents Jf =  X Q X Vn 60 Where: Jf = Jet Impact Force, N  = Fluid Density, kg/m3 Q = Pump Output, m 3/min Vn = Bit Nozzle Velocity, m/sec

8.10.19 EQUIVALENT CIRCULATING DENSITY (kg/m3) (Where PL = Annular Pressure Loss) ECD =  +

PL_____ 0.00981 + L

Where: ECD = Equivalent Mud Density, kg/m3  = Fluid Density ( kg/m3) PL = Annular Pressure Loss, kPa L = Pipe Length, m

Page-367

8.10.20 SLIP VELOCITY (m/min)


Laminar Flow: Vs =

Dp ( Pd - )0.667__ (2.36) (0.333) (0.333)

Where: Vs = Slip Velocity, m/min Dp = Particle Diameter, mm Pd = Particle Density, 2600 kg/m 3  = Fluid Density kg/m3  = Equivalent Viscosity – Annulus, mPa.s

Turbulent Flow: 0.5

Vs = 6.86 [ Dp (Pd - ) ] 1.5 X  Where: Vs = Slip Velocity, m/min Dp = Particle Diameter, mm Pd = Particle Density, 2600 kg/m 3  = Fluid Density kg/m3

8.10.21 TRANSPORT VELOCITY (m/min) Vt = Va – Vs Where: Vt = Transport Velocity, m/min Va = Annular Velocity, m/min Vs = Slip Velocity, m/min

Page-368


8.10.22 ANNULAR VELOCITY (m/min) – TRIPPING


(Where V = Pipe Running Speed, m/min) Float in String: Va = [ 0.45 +

(D22)__ ] (1.5 X V) (D1 – D22) 2

Where: Va = Annular Velocity – Tripping, m/min D2 = Pipe OD, mm V = Pipe Trip Velocity, m/min D1 = Hole Diameter, mm Open – No Float: Va = [ 0.45 +

(D22 – Di2)__ ] (1.5 X V) (D12 – D22 + Di2)

Where: Va = Annular Velocity – Tripping, m/min D2 = Pipe OD, mm Di = Pipe ID, mm V = Pipe Trip Velocity, m/min D1 = Hole Diameter, mm

8.10.23 SURGE OR SWAB PRESSURE (kPa) (Va – Annular Velocity Tripping Taken From 9.9.22) Laminar Flow: n

P = [ (200 Va) (2n +1) ] (D1 – D2) (3n)

4 (K) (L) (D1 – D2)

Where: P = Surge or Swab Pressure , kPa Va = Annular Velocity Tripping, m/min n = “n” Value K = “K” Value L = Pipe Length, m D1 = Hole Diameter, mm D2 = Pipe OD. mm

Page-369


Turbulent Flow: P = 4.59 (10-5) X 0.8 X Va1.8 X PV0.2 X L (D1 – D2)1.2 Where: P = Surge or Swab Pressure, kPa  = Fluid Density, kg/m3 Va = Annular Velocity Tripping, m/min PV = Plastic Viscosity, mPa.s L = Pipe Length, m D1 = Hole Diameter, mm D2 = Pipe OD. mm

8.10.24 MUD DENSITY CHANGE DUE TO SURGE OR SWAB PRESSURES (kg/m3)  =

P____ 0.00981 X L

Where:  = Mud Density Change due to Surge or Swab Pressure, kg/m 3 P = Surge or Swab Pressure, kPa L = Pipe Length, m Return to Table of Contents

Page-370

Page-371

Chapter 10 TOPICS

9.1 9.2 9.3 9.4 9.5 9.6 9.7 9.8 9.9 9.10 9.11 9.12 9.13 9.14 9.15 9.16 9.17 9.18 9.19 9.20 9.21 9.22 9.23 9.24 9.25 9.26 9.27 9.28 9.29 9.30 9.31 9.32 9.33 9.34

TABLE OF CONTENTS – CHAPTER 9 Engineering Data Return to Table of Contents to Table o Return to Glossary

PAGE

Conversion Factors Duplex Pump Output Triplex Pump Output Capacity of Hole Volumes Capacity and Displacement of Casing Capacity and Displacement of “Drill Pipe” Capacity and Displacement of “Drill Collars” Annular Volume Between “Drill Pipe” and Open Hole or Casing Annular Volume Between “Drill Collars” and Open Hole or Casing Dimensions and Strengths of “Drill Pipe” Hole Volume ( With Pipe in Hole) Annular Velocity Multipliers Storage Tank Volumes Buoyancy Factors Density Adjustment with Barite or Water Pilot Testing – Guidelines for Measuring Products Brine Density Table Properties of Sodium Chloride Solutions (Salt) Properties of Potassium Chloride Solutions (KCl) Properties of Potassium Sulfate Solutions (K2SO4) Properties of 94% Pure Calcium Chloride Solutions (CaCL2) Properties of Envirofloc (Calcium Nitrate) Solutions Properties of Sodium – Calcium Chloride Blends Properties of Ammonium Chloride Solutions Properties of Magnesium Chloride Solutions Properties of Potassium Acetate Solutions Common Chemical Formulas and Names Common Drilling Mud Cations (+ ions) Common Drilling Mud Anions (- ions) Specific Gravity of Common Materials Recommended Solids Content of Water Base Muds Suggested Ranges of Plastic Viscosity Suggested Ranges of Yield Point General Formulas

Page-372

1 4 5 6 7 9 10 11 13 15 16 16 17 19 20 21 22 22 23 23 24 25 26 26 27 27 28 29 29 30 31 31 32 32

CHAPTER 9 ENGINEERING DATA Return to Table of Contents

9.1 CONVERSION FACTORS

QUANTITY or PROPERTY

PREVIOUS UNITS (API)

“SI” or METRIC UNIT

SYMBOL

TO CONVERT TO “SI” UNITS, MULTIPLY BY:

Annular Velocity Apparent & Plastic Viscosity Area Bentonite Yield Bit Size Casing Capacity / Displacement Casing Weight Corrosion Rate

ft/min

metres/min

m/min

0.3048

centipoise

millipascal second

mPa.s

1.0

acre bbl’s/ton inches bbl/ft

hectares cubic metres/tonne millimeters cubic metres/metre

ha m3/tonne mm m3/m

0.4047 0.175 25.4 0.5216

lbs/ft lbs/ft2/day

kg/m g/m2/day

0.188 13.377

mils per year feet

kilograms/metres grams/square metre/day milligrams/day metres

mm/a m

0.254 0.3048

miles miles inches yards feet feet/hour 32’nds inch

metres kilometres metres metres metres metres/hour millimeters

m km m m m m/h mm

1609.35 1.6093 39.37 1.0936 3.2808 0.3048 0.794

US gallons/min bbl/min

cubic metres/min cubic metres/min

m3/min m3/min

0.003785 0.159

millilitres or cc’s sec/quart

millilitres or cc’s seconds/litre

ml or cm3 s/L

1.0 1.057

thousands of pounds Horsepower Hp/in2

decanewtons

daN

0.444

watts meagawatts /square metre milligram/litre

W mw/m2

745.7 1.15

mg/L

1.0

millimeters

mm

25.4

Depth Hole & Pipe Diameter Distance

Drill Rate Filter Cake Thickness Flow Rate Fluid Loss Funnel Viscosity Hook Load Horsepower Horsepower /sq.inch Ionic Concentration in Water Liner Length & Diameter

parts per million (ppm) inches


Page-373

CONVERSION FACTORS (Continued) Return to Table of Contents QUANTITY or PROPERTY Material Concentration MBT (Bentonite Equivalent) Mud Density

PREVIOUS UNITS (API)

“SI” or METRIC UNIT

SYMBOL

TO CONVERT TO “SI” UNITS, MULTIPLY BY:

lb/bbl

kilogram/cubic metre moles/cubic metre kilograms/cubic metre

kg/m3

2.85

mol/m3 kg/m3

1.0 2.85

kg/m3

119.83

kPa/m mm m N kPa mPa m3/stroke

equivalents lb/bbl

lbs/gal

Pump Data

bbl/stroke

Pump Output/Stroke Rotary Speed

bbl/stroke

litres/stroke

l/stroke

22.621 0.794 1.0 4.448 6.895 0.006895 An oilfield barrel is exactly 0.1589873 m3 159.0

revolutions/min (rpm) reciprocal second  Fahrenheit  Celsius ft/lbs barrels US gallons/stroke

revolutions/min (rpm) reciprocal second  Celsius  Fahrenheit newton.metre cubic metres cubic metres/stroke litres/stroke litre litre cubic metre cubic metre cubic metre

rpm

1.0

sec-1 C F N.m m3 m3/stroke

1.0 (F-32) / 1.8 (CX1.8) + 32 1.3558 0.159 0.003785

litres/stroke L L m3 m3 m3

3.785 3.785 4.546 0.003785 0.004546 0.1589

cubic metres decanewtons pascal

m3 daN Pa

0.7646 0.445 0.4788 (round off to 0.5 for field use)

Mud Gradient Nozzle Size Particle Size Pounds Force Pressure

Shear Rate Temperature Torque Volume

Volumes

Weight on Bit Yield Point, Gel Strength, Shear Stress

psi/foot 32’nds inch microns pounds psi

kilograms/cubic metres kilopascals/metre millimeters micrometres newton kilopascals megapascals cubic metres/stroke

US gallons/stroke US gallon Imperial Gallon US gallon Imperial Gallon Oilfield barrel (42 US gallons) Cubic yards pounds lb/100 ft3


Page-374

9.2 DUPLEX PUMP OUTPUT Return to Table of Contents Litres/Stroke @ 90% Efficiency (2” Rod Diameter)

133

140

146

152

159

165

170

178

184

197

203

6.19

6.99

7.78

8.73

6.69

10.6

11.5

12.7

13.8

15.0

16.2

17.4

18.9

6.67

7.62

8.58

6.69

10.8

12.0

13.3

14.6

15.9

17.3

18.7

20.0

21.9

23.6

7.78

9.90

10.1

11.4

12.9

14.3

15.9

17.3

19.1

20.7

22.6

24.3

26.2

28.3

30.4

14.6

16.4

18.0

19.9

21.8

23.8

25.9

28.0

30.2

32.4

35.0

37.4

39.9

15.6

17.3

19.2

21.1

23.2

25.3

27.5

29.7

32.3

34.7

37.4

39.9

42.8

16.7

18.6

20.5

22.6

24.8

27.0

29.4

32.3

34.5

37.0

39.7

42.8

45.6

48.6

18.4

20.7

22.7

25.3

27.8

30.2

32.7

35.6

38.5

41.3

44.5

47.7

51.1

54.4

20.3

22.7

25.1

28.0

30.5

33.4

36.4

39.4

46.2

45.9

49.4

53.1

56.8

60.4

49.8

53.5

57.3

61.1

65.1

69.2

73.5

71.1

75.6

80.2

DUPLEX MUD PUMPS


The pistons on a duplex mud pump work in both directions, so that the rear cylinder has the pump rod moving through its swept volume and occupying some volume. The difference in calculations for a duplex vs. a triplex pump is that the displacement volume of this pump rod must be subtracted from the volume in one of the cylinders, plus the difference in number of pumping cylinders; 4 for a duplex and 3 for a triplex. Duplex pumps generally have longer strokes (in the 10 to 18 in. range) and operate at lower rate; in the 40 to 80 stroke/min range. The general equation to calculate output of a duplex pump is:

Pump output (litres/stroke) = [ 2 X ID2 (mm) – OD2 (mm) ] X L (mm) X Eff (decimal) 636,500 Where: ID = OD = L= Eff =

ID of the liner OD of the rod Length of the pump stroke Pump efficiency (decimal)

Page-375

216

127

5.40

Note: For pump output in m3/stroke, move the decimal point 3 places to the left.

209

121

190

114

203 254 305 356 381 406 457 508 559 610

108

Stroke Length (mm)

101

LINER DIAMETER (mm)

9.3 TRIPLEX PUMP OUTPUT Litres/Stroke @ 100% Efficiency Return to Table of Contents

127

133

140

146

152

170

178

184

190

197

203

165

121

159

114

102 114 127 140 152 165 178 190 203 216 229 241 254 267 279 292 305

108

Stroke Length (mm)

102

LINER DIAMETER (mm)

2.5

2.8

3.1

3.5

3.9

4.3

2.8

3.1

3.5

3.9

4.3

4.8

5.3

5.7

6.3

3.0

3.5

3.9

4.4

4.8

5.3

5.8

6.4

6.9

7.5

3.4

3.8

4.3

4.8

5.3

5.8

6.5

7.0

7.6

8.3

3.7

4.2

4.7

5.2

5.8

6.4

7.0

7.7

8.3

9.0

9.7

4.0

4.5

5.1

5.7

6.3

6.9

7.6

8.3

9.0

9.8

10.6

4.3

4.9

5.5

6.1

6.8

7.4

8.2

8.9

9.7

10.6

11.4

12.3

13.2

4.6

5.2

5.9

6.5

7.2

8.0

8.8

9.6

10.4

11.3

12.2

13.1

14.2

15.2

16.1

4.9

5.6

6.2

6.9

7.7

8.5

9.3

10.2

11.1

12.0

13.0

14.0

15.1

16.2

17.3

18.5

19.7

5.2

5.9

6.6

7.4

8.2

9.0

9.9

10.8

11.8

12.8

13.8

14.9

16.3

17.2

18.5

19.7

21.0

5.6

6.3

7.0

7.8

8.7

9.6

10.5

11.5

12.5

13.6

14.7

15.8

17.0

18.3

19.5

20.9

22.2

5.9

6.6

7.4

8.3

9.2

10.1

11.1

12.1

13.2

14.3

15.5

16.7

18.0

19.3

20.6

22.0

23.3

6.2

7.0

7.8

8.7

9.6

10.6

11.7

12.8

13.9

15.1

16.3

17.6

18.9

20.3

21.7

23.2

24.7

6.5

7.3

8.2

9.1

10.1

11.2

12.3

13.4

14.6

15.8

17.2

18.5

19.9

21.3

22.8

24.3

25.9

6.8

7.7

8.6

9.6

10.6

11.7

12.8

14.0

15.3

16.6

17.9

19.3

20.8

22.3

23.9

25.5

27.2

7.1

8.0

9.0

10.0

11.1

12.2

13.4

14.7

16.0

17.3

18.7

20.2

21.8

23.3

25.0

26.7

28.4

7.4

8.4

9.4

10.4

11.6

12.8

13.8

15.3

16.7

18.1

19.6

21.1

22.2

24.3

26.0

27.8

29.6

Note: For pump output in m3/stroke, move the decimal point 3 places to the left.

TRIPLEX MUD PUMPS


The pistons on a triplex mud pump work only on the forward stroke, and generally have short strokes (in the 6-12 inch range) and operate at rates in the 60-120 stroke/min. range. The general equation to calculate output of a triplex pump is: Pump output (litres/stroke) = ID2 (mm) X L (mm) X Eff (decimal) 424,333 Where: ID = L= Eff =

ID of the liner Length of the pump stroke Pump efficiency (decimal)

Page-376

9.4 CAPACITY OF HOLE SIZES Return to Table of Contents DIAMETER (mm) 95.2 98.4 104.8 120.6 142.9 149.2 152.4 155.6 158.8 165.1 171.4 177.8 200.0 212.7 215.9 219.1 222.2 228.6 241.3 250.8 269.9 279.4 311.2 349.2 374.6 377.8 381.0 444.5 508.0 546.1 609.6 660.4

CAPACITY (m3/metre) 0.0071 0.0076 0.0086 0.0114 0.0160 0.0175 0.0182 0.0190 0.0198 0.0214 0.0231 0.0248 0.0314 0.0355 0.0366 0.0377 0.0388 0.0410 0.0457 0.0494 0.0572 0.0613 0.0760 0.0958 0.1102 0.1121 0.1140 0.1552 0.2027 0.2342 0.2919 0.3425 Return to Table of Contents

Page-377

9.5 CAPACITY AND DISPLACEMENT OF CASING Return to Table of Contents O.D. (mm) 114.3 (4.5”)

127.0 (5.0”)

139.7 (5.5”)

168.3 (6.625”)

177.8 (7.0”)

193.7 (7.625”)

219.1 (8.625”)

244.5 (9.625”)

273.0 (10.75”)

MASS (kg/m) 14.14 15.62 17.26 20.09 17.11 19.34 22.32 26.78 20.83 23.06 25.30 29.76 34.22 29.76 35.71 41.66 47.62 25.30 29.76 34.22 38.69 43.15 47.62 52.08 56.54 35.71 39.28 44.19 50.15 58.03 35.71 41.66 47.62 53.57 59.52 65.47 72.91 48.06 53.57 59.52 64.73 69.94 79.61 48.73 60.26 67.70 75.89 82.58

I.D. (mm) 103.89 102.92 101.60 99.57 115.82 114.15 111.96 108.61 127.31 125.73 124.26 121.36 118.62 153.65 150.39 147.09 144.15 166.07 163.98 161.70 159.41 157.07 154.79 152.50 150.37 178.44 177.01 174.63 171.83 168.28 205.66 203.63 201.19 198.76 196.22 193.68 190.78 228.63 226.59 224.41 222.38 220.50 216.79 258.88 255.27 252.73 250.19 247.90

Page-378

CAPACITY (m3/metre) 0.0085 0.0083 0.0081 0.0078 0.0105 0.0102 0.0098 0.0093 0.0129 0.0124 0.0121 0.0116 0.0111 0.0185 0.0178 0.0170 0.0163 0.0217 0.0211 0.0205 0.0200 0.0194 0.0188 0.0183 0.0178 0.0250 0.0246 0.0239 0.0232 0.0222 0.0332 0.0326 0.0318 0.0310 0.0302 0.0295 0.0286 0.0411 0.0403 0.0396 0.0388 0.0382 0.0369 0.0526 0.0512 0.0502 0.0492 0.0483

DISPLACEMENT (m3/metre) 0.0018 0.0019 0.0022 0.0025 0.0021 0.0024 0.0028 0.0034 0.0026 0.0029 0.0032 0.0038 0.0043 0.0037 0.0045 0.0053 0.0059 0.0032 0.0037 0.0043 0.0049 0.0054 0.0060 0.0066 0.0071 0.0045 0.0049 0.0055 0.0063 0.0072 0.0045 0.0051 0.0059 0.0068 0.0075 0.0082 0.0091 0.0059 0.0066 0.0074 0.0081 0.0088 0.0100 0.0059 0.0074 0.0084 0.0092 0.0103

CAPACITY AND DISPLACEMENT OF CASING (Continued) O.D. (mm) 298.4 (11.75”)

339.7 (13.375”)

406.4 (16”) 508.0 (20”) 762 (30”)

MASS (kg/m) 62.50 69.94 80.35 89.28 71.42 81.10 90.77 101.18 107.14 96.72 111.60 124.99 140.19 158.83 198.35 234.64 349.41 462.29

I.D. (mm) 281.53 279.40 276.35 273.61 322.96 320.42 317.88 315.34 313.61 387.35 384.18 381.25 485.75 482.60 475.74 736.60 723.90 711.20

Return to Table of Contents CAPACITY DISPLACEMENT (m3/metre) (m3/metre) 0.0623 0.0077 0.0613 0.0086 0.0600 0.0099 0.0588 0.0111 0.0819 0.0087 0.0802 0.0100 0.0794 0.0113 0.0781 0.0125 0.0772 0.0134 0.1178 0.0119 0.1159 0.0138 0.1142 0.0156 0.1854 0.0178 0.1830 0.0202 0.1778 0.0253 0.4263 .0299 0.4117 .0445 0.3972 .0589

The formula for calculating the capacity of a hole or a pipe is: Capacity (liters/metre) = (Inside diameter in millimeters, mm)2 X 0.0007854

The annular or displacement volume can be calculated using a similar formula: Capacity (litres/metre) = (OD in millimeters, mm)2 - (ID in millimeters, mm)2 X 0.0007854 Return to Table of Contents

Page-379

9.6 CAPACITY AND DISPLACEMENT OF “DRILL PIPE” Return to Table of Contents O.D. (mm) 60.3 (2 3/8”) 73.0 (2 7/8”)

88.9 (3 ½”)

101.6 (4”) 114.3 (4 ½”)

127 (5”) 139.7 (5 ½”)

MASS (kg/m) 7.2 9.9 9.6 10.2 12.4 15.5 12.7 14.1 16.7 19.8 23.1 17.6 20.8 23.4 19.0 20.5 24.7 29.8 24.2 29.0 30.5 32.6 36.8

I.D. (mm) 50.7 46.1 62.7 62.0 59.0 54.6 77.8 76.0 73.7 70.2 66.1 88.3 84.8 82.3 101.6 100.5 97.2 92.5 112.0 108.6 107.0 121.4 11.6

CAPACITY (m3/metre) 0.0020 0.0017 0.0031 0.0030 0.0027 0.0023 0.0048 0.0045 0.0043 0.0039 0.0034 0.0061 0.0057 0.0053 0.0081 0.0079 0.0074 0.0067 0.0098 0.0093 0.0090 0.0116 0.0111


Page-380

DISPLACEMENT (m3/metre) 0.00092 0.00126 0.00122 0.00130 0.00159 0.00197 0.00161 0.00180 0.00213 0.00252 0.00294 0.00225 0.00266 0.00298 0.00242 0.00261 0.00315 0.00380 0.00309 0.00370 0.00389 0.00416 0.00469

97 CAPACITY AND DISPLACEMENT OF “DRILL COLLARS” Return to Table of Contents O.D. (mm) 79.4 (3.125”) 88.9 (3.5”) 104.8 (4.125”) 120.7 (4.75”) 152.4 (6”) 158.8 (6.25”) 165.1 (6.5”) 171.5 (6.75”) 177.8 (7”) 184.2 (7.25”) 196.9 (7.75”) 203.2 (8”) 209.6 (8.25”) 228.6 (9”) 241.3 (9.5”) 247.7 (9.75”) 254.0 (10”) 279.4 (11”)

I.D. (mm) 31.8

MASS (kg/m) 29.8

CAPACITY (m3/metre) 0.008

DISPLACEMENT (m3/metre) 0.0042

38.1

40.2

0.0011

0.0051

50.8

52.1

0.0020

0.0066

57.2

78.9

0.0026

0.0101

57.2 71.4 57.2 71.4 57.2 71.4 57.2

123.5 111.6 135.4 123.5 147.3 135.4 160.7

0.0026 0.0040 0.0026 0.0040 0.0026 0.0040 0.0026

0.0157 0.0142 0.0172 0.0158 0.0188 0.0174 0.0205

57.2 71.4 71.4

174.1 163.7 177.1

0.0026 0.0040 0.0040

0.0223 0.0208 0.0226

71.4

206.9

0.0040

0.0264

71.4

223.2

0.0040

0.0284

71.4

238.1

0.0040

0.0305

71.4

290.2

0.0040

0.0370

76.2

327.4

0.0046

0.0411

76.2

345.3

0.0046

0.0436

76.2

366.1

0.0046

0.0461

76.2

449.4

0.0046

0.0567


Page-381

9.8 ANNULAR VOLUME BETWEEN “DRILL PIPE” AND OPEN HOLE OR CASING DRILL PIPE SIZE O.D. (mm) 60 (2 3/8”)

73 (2 7/8”)

89 (3 ½”)

102 (4”)

114 (4 ½”)

HOLE or CASING SIZE (mm) 89 95 102 105 114 105 114 117 121 127 140 149 127 140 146 152 159 165 175 178 200 140 146 149 159 165 175 178 187 200 203 222 200 210 213 216 219 222 235 241 244 248 267 311 375 381

Page-382

Return to Table of Contents ANNULAR VOLUME (m3/metre) 0.0033 0.0042 0.0052 0.0057 0.0074 0.0044 0.0060 0.0066 0.0072 0.0085 0.0112 0.0133 0.0064 0.0091 0.0105 0.0120 0.0136 0.0152 0.0177 0.0186 0.0252 0.0071 0.0086 0.0093 0.0117 0.0113 0.0159 0.0167 0.0195 0.0233 0.0243 0.0252 0.0212 0.0243 0.0253 0.0261 0.0274 0.0285 0.0319 0.0355 0.0367 0.0379 0.0456 0.0658 0.1000 0.1038

ANNULAR VOLUME BETWEEN “DRILL PIPE” AND OPEN HOLE OR CASING (Continued) PIPE SIZE O.D. (mm) 127 (5”)

140 (5 ½”)

HOLE or CASING SIZE (mm) 200 210 213 216 219 222 235 241 244 248 267 311 375 381 222 235 248 267 311 375 381

Page-383

ANNULAR VOLUME (m3/metre) 0.0188 0.0218 0.0229 0.0239 0.0250 0.0261 0.0307 0.0331 0.0343 0.0355 0.0432 0.0634 0.0976 0.1014 0.0235 0.0280 0.0329 0.0405 0.0607 0.0949 0.0987

9.9 ANNULAR VOLUME BETWEEN DRILL COLLARS AND OPEN HOLE OR CASING

DRILL COLLAR SIZE O.D. (mm) 114 (4 ½”)

121 (4 ¾”)

127 (5”)

140 ( 5 ½”)

146 (5 ¾”)

152 (6”)

HOLE or CASING SIZE (mm) 127 140 149 152 165 140 149 152 159 165 175 178 149 152 156 159 165 171 194 200 165 171 194 200 213 216 222 241 251 165 171 194 200 213 216 222 241 171 194 200 213 216 222 241 251

Page-384

Return to Table of Contents ANNULAR VOLUME (m3/metre) 0.0024 0.0050 0.0072 0.0079 0.0112 0.0039 0.0060 0.0068 0.0083 0.0099 0.0125 0.0134 0.0048 0.0055 0.0063 0.0071 0.0087 0.0104 0.0168 0.0188 0.0061 0.0077 0.0141 0.0161 0.0202 0.0213 0.0235 0.0304 0.0341 0.0046 0.0063 0.0127 0.0147 0.0188 0.0199 0.0221 0.0290 0.0327 0.0048 0.0112 0.0132 0.0173 0.0184 0.0206 0.0275 0.0312

ANNULAR VOLUME BETWEEN DRILL COLLARS AND OPEN HOLE OR CASING (Continued) DRILL COLLAR SIZE O.D. (mm) 171 (6 ¾”)

178 (7”)

197 (7 ¾”)

229 (9”)

HOLE or CASING SIZE (mm) 200 216 222 311 200 213 216 222 241 251 270 279 311 375 381 222 241 251 270 279 311 368 322 438 Return to Table of Contents

Page-385

ANNULAR VOLUME (m3/metre) 0.0083 0.0135 0.0230 0.0529 0.0065 0.0107 0.0118 0.0140 0.0209 0.0246 0.0324 0.0365 0.0512 0.0854 0.0892 0.0083 0.0153 0.0190 0.0268 0.0309 0.0456 0.0761 0.0350 0.1097

9.10 DIMENSIONS AND STRENGTHS OF “DRILL PIPE” Return to Table of Contents O.D. (in)

Weight (lb/ft)

O.D. (mm)

Mass (kg/m)

Grade

Wall Thickness (mm)

I.D. (mm)

Collapse Resistance (mPa)

2 3/8

6.65 4.85 6.65 10.40 6.85 10.40 13.30 15.50 9.50 13.30 15.50 14.00 11.85 14.00 16.60 20.00 13.75 16.60 20.00 19.50 16.25 19.50 21.90 24.70 21.90 24.70 25.20 25.20

60.3

9.90 7.72 9.90 15.48 10.19 15.48 19.79 23.07 14.14 19.79 23.07 20.83 17.83 20.83 24.70 29.76 20.46 24.70 29.76 29.02 24.18 29.02 32.59 36.76 32.59 36.76 37.50 37.50

D E E D E E D D E E E D E E D D E E E D E E D D E E D E

7.1 4.8 7.1 9.2 5.5 9.2 9.3 11.4 6.5 9.3 11.4 8.4 6.7 8.4 8.6 10.9 6.9 8.6 10.9 9.2 7.5 9.2 9.2 10.5 9.2 10.5 8.4 8.4

46.1 50.7 46.1 54.6 62.0 54.6 70.2 66.1 76.0 70.2 66.1 84.8 88.3 84.8 97.2 92.5 100.5 97.2 92.5 108.6 112.0 108.6 121.4 118.6 121.4 118.6 151.5 151.5

78.880 76.120 107.560 83.500 72.190 113.970 71.360 84.810 60.220 97.290 115.630 57.430 57.980 78.260 52.540 65.570 46.640 71.640 89.360 50.950 48.060 68.950 45.570 52.880 58.190 72.120 27.650 33.160

2 7/8

3½

4

4½

5

5 ½”

6 5/8

73.0

88.9

101.6

114.3

127.0

139.7

168.3


Page-386

Internal Yield Pressure (mPa) 78.260 72.400 106.660 83.560 68.330 113.970 69.770 85.150 65.640 95.150 116.110 54.740 59.290 74.670 49.710 63.430 54.470 67.780 86.460 48.060 53.570 65.500 43.570 50.080 59.360 68.260 33.030 45.090

Pipe Body Yield Strength (mPa) 698.850 674.450 952.990 1063.720 937.000 1477.820 1373.090 1631.990 1339.380 1872.410 2225.490 1442.800 1590.970 1967.490 1671.360 2084.970 1861.860 2279.130 2843.120 2000.170 2261.960 2727.570 2310.110 2514.040 3013.840 3428.210 2474.800 3374.710

9.11 HOLE VOLUME ( With Pipe in Hole) Return to Table of Contents Cubic Metres Per 100 Metres Hole Diameter (mm) Pipe Size (mm)

143

152

156

159

171

194

200

219

222

229

251

279

311

349

381

0 89 102 114 127

1.61 1.36 1.35 1.30 1.24

1.81 1.56 1.53 1.50 1.44

1.91 1.66 1.61 1.60 1.54

1.99 1.74 1.69 1.68 1.62

2.30 2.05 2.02 1.99 1.93

2.94 2.71 2.66 2.65 2.59

3.14 2.89 2.85 2.83 2.77

3.77 3.52 3.48 3.46 3.40

3.87 3.62 3.59 3.56 3.50

4.12 3.87 3.82 3.81 3.75

4.95 4.70 4.65 4.60 4.58

6.11 5.85 5.83 5.80 5.74

7.60 7.35 7.31 7.29 7.23

9.57 9.32 9.30 9.26 9.20

11.40 11.15 11.11 11.09 11.03

9.12 ANNULAR VELOCITY MULTIPLIERS Return to Table of Contents Bit Size, mm Pipe Size (mm)

136

143

152

156

159

171

194

200

219

222

229

251

279

311

349

381

445

73 76 89 102 114 127 140 152 165

84.7 87.0

77.9 82.0

71.1 73.4

67.5 68.6

64.2 65.3

52.5 54.3

39.7 40.0

36.8 37.2

29.9 30.2

29.0 29.3

27.2 27.4

22.3

120.4

101.6

83.9

77.6

73.3

59.7

42.8

39.7

31.8

30.8

28.6

157.3

125.7

99.6

90.9

85.1

67.3

46.5

42.9

33.8

32.7

30.2

23.1

18.2

14.3

24.2

18.9

103.6

78.4

51.7

47.2

36.4

35.1

32.3

25.5

19.6

14.7

11.4

9.4

6.8

15.2

11.7

9.6

39.9

38.4 42.8

35.1 38.9

27.2 29.3

6.9

20.6 21.9

15.8 16.5

12.0 12.5

9.6 10.2

7.0 7.1

48.5

43.4

57.7

50.5

31.9

23.3

17.3

12.9

10.4

7.3

35.6

25.2

18.3

13.5

10.8

7.2

To obtain the annular velocity in metres per min. (m/min), multiply the appropriate number from the bit and pipe size combination, by the pump output in cubic metres per min (m3/min). Formula: Annular Velocity (m/min) = Pump Output (m3/min) X (1.273 X 106) (Dh)2 - (Dp)2 Where: Dh = Hole Diameter, mm Dp = Pipe Diameter, mm

Page-387

9.13 STORAGE TANK VOLUMES Tank Volume, m3/metre (Rectangular Tanks Only) Return to Table of Contents Length, metres Width (m)

3.05

3.66

4.27

4.88

5.49

6.10

7.62

9.15

10.67

12.19

13.72

15.24

16.76

18.29

19.81

21.23

1.83 2.13 2.44 2.74 3.05

5.58

6.70

6.50

7.80

7.81

8.93

10.05

11.16

13.94

16.73

19.53

22.31

25.11

27.89

30.67

33.47

36.25

38.85

9.10

10.39

11.69

12.99

16.23

19.47

22.73

25.96

29.22

32.46

35.70

38.96

42.2

7.44

45.22

8.93

10.42

11.91

13.40

14.88

18.59

22.30

26.03

29.74

33.48

37.19

40.89

44.63

48.34

51.80

8.36

10.03

11.70

13.37

15.04

16.71

20.88

25.04

29.24

33.40

37.59

41.76

45.92

50.11

54.28

58.17

9.30

11.16

13.05

14.88

17.74

18.61

23.24

27.88

32.54

37.18

41.85

46.48

51.12

55.78

60.42

64.75

Tank Volume Formulas: Capacity, volume and displacement calculations use simple volumetric relationships for rectangles, cylinders, concentric cylinders and other shapes with the appropriate unit conversion factors. Tanks on rigs can be a variety of shapes, but most are either rectangular or cylindrical. Three shapes of tanks are covered here: 1. rectangular 2. cylindrical, vertical 3. cylindrical, horizontal

Volume Rectangular Tank: Mud tanks are usually rectangular with parallel sides and ends that are perpendicular to the bottom. For a typical rectangular tank, the capacity can be calculated from the height, width and length. Where: Vtank L W H

= = = =

Tank Capacity Tank Length Tank Width Tank Height

The general equation to calculate the capacity of a rectangular vessel is: Volume = Length x Width x Height


This formula is valid for both English and Metric units. Therefore, the capacity of a rectangular pit, using metres, is calculated by: Vtank (m3) = L (m) X W (m) X H (m)

Page-388

Volume Vertical Cylindrical Tank:


Cylindrical tanks mounted in a vertical position are normally used for liquid mud and/or dry bulk Barite storage. Where: VCyl D H M 

= = = = =

Capacity of the Cylindrical Tank Diameter of Cylinder Height of Cylinder Material Level Height 3.1416

If the diameter is not known, measure the circumference and divide by 3.1416. D = Tank Circumference = Tank Circumference  3.1416 The general formula to calculate the capacity for a vertical cylinder tank is: VCyl (m3) =  X D2 (m) X H (m) = 3.1416 X D2 (m) X H (m) = D2(m) X H (m) 4 4 1.273 The actual mud volume (Vmud) of a vertical cylinder tank is calculated using the mud/material level height (M) by: Vmud (m3) =  X D2 X M = D2 X M 4 1.273

Volume Horizontal Cylindrical Tank:


Cylindrical tanks mounted in a horizontal position are normally used primarily for storage of diesel fuel, other liquids and/or Barite. The vertical capacity and volume of a horizontal cylindrical tank varies with the horizontal cross-section area, and is not a linear function of height. Charts and tabular methods are available to calculate the capacity and volume of horizontal cylindrical tanks. VCyl D L M 

= = = = =

Capacity of the Cylindrical Tank Diameter of Cylinder Length of Cylinder Mud or Material Height 3.1416 _____

Vcyl = L [ (2M – D) MD-M2 + D2 sin–1 (2M – 1) +  D2 ] 2 2 D 4 The result from sin-1 must be in radians before being added to the other parts of the equation (2 radians = 360). To convert from degrees, divide by 57.3 (degree/radian) to obtain radians.

Page-389

9.14 BUOYANCY FACTORS Return to Table of Contents DENSITY (kg/m3) 1000 1020 1040 1060 1080 1100 1120 1140 1160 1180 1200 1220 1240 1260 1280 1300 1320 1340 1360 1380 1400 1420 1440 1460 1480 1500 1520 1540 1560 1580 1600 1620 1640 1660 1680 1700 1720 1740 1760 1780 1800 1820 1840 1860 1880 1900 1920 1940 1960 1980

GRADIENT (kPa/m) 9.81 10.00 10.20 10.40 10.60 10.80 10.99 11.18 11.38 11.58 11.77 11.97 12.16 12.36 12.55 12.75 12.94 13.14 13.34 13.53 13.73 13.93 14.12 14.32 14.51 14.71 14.91 15.10 15.30 15.50 15.69 15.89 16.08 16.28 16.48 16.67 16.87 17.06 17.26 17.46 17.65 17.85 18.04 18.24 18.44 18.63 18.83 19.03 19.22 19.42

Actual Hook Load (daN) = Pipe Mass (kg) X Buoyancy Factor

Page-390

BUOYANCY FACTOR 0.873 0.869 0.867 0.864 0.862 0.859 0.857 0.854 0.852 0.849 0.847 0.844 0.842 0.839 0.837 0.834 0.832 0.829 0.827 0.824 0.822 0.819 0.817 0.814 0.811 0.809 0.806 0.804 0.801 0.799 0.796 0.794 0.791 0.789 0.786 0.783 0.781 0.778 0.776 0.773 0.771 0.768 0.766 0.763 0.761 0.758 0.755 0.753 0.750 0.748

9.15 DENSITY ADJUSTMENT WITH BARITE OR WATER Return to Table of Contents Top half of table: Number of 40 kg. sacks of Barite to raise 10 m3 of fluid to a desired density Bottom half of table: Approximate m3 of water to lower 10 m3 of fluid to a desired density

1200

1250

1300

1350

1400

1450

1500

1550

1600

1650

1700

1750

1800

1850

1900

1950

2000

1050 1100 1150 1200 1250 1300 1350 1400 1450 1500 1550 1600 1650 1700 1750 1800 1850 1900 1950 2000

1150

Initial Density (kg/m3)

1100

DESIRED DENSITY (kg/m3)

10

34

52

71

90

110

131

153

175

198

222

247

273

300

328

357

388

420

453

17

35

53

72

92

112

134

156

178

202

226

252

279

306

335

365

397

429

17

36

54

74

94

114

136

158

182

206

231

257

284

313

342

373

406

18

36

55

75

95

117

139

161

185

210

236

262

290

320

350

382

18

37

56

76

97

119

141

165

189

214

241

268

297

327

358

19

37

57

78

99

121

144

168

193

219

246

274

303

334

19

38

58

79

101

123

147

171

197

223

251

280

310

19

39

59

81

103

126

150

175

201

228

256

286

19

39

61

82

105

129

153

179

205

233

262

20

40

62

84

107

131

156

183

210

239

20

41

63

86

109

134

160

187

215

20

42

64

87

112

137

163

191

21

43

65

89

114

140

167

21

44

67

91

117

143

22

45

68

93

119

22

46

70

95

23

47

72

23

48

5 10

3.3

15

6.7

2.5

20

10

5

2

15

13

7.5

4

1.7

30

17

10

6

3.3

1.4

35

20

13

8

5

2.9

1.3

40

23

15

10

6.7

4.3

2.5

45

27

18

12

8.3

5.7

3.8

2

1

50

30

20

14

10

7.1

5

3.3

2

0.9

55

33

23

16

12

8.6

6.3

4.4

3

1.8

0.8

60

37

25

18

13

10

7.5

5.6

4

2.7

1.7

0.8

65

40

28

20

15

11

8.5

6.7

5

3.6

2.5

1.5

0.7

70

43

30

22

17

13

10

7.8

6

4.5

3.3

2.3

1.4

0.7

75

47

33

24

18

14

11

8.9

7

5.4

4.2

3.1

2.1

1.3

0.6

80

50

35

26

20

16

13

10

8

6.4

5.0

3.8

2.9

2

1.3

0.6

85

53

38

28

22

17

14

11

9

7.3

5.8

4.6

3.6

2.7

1.9

1.2

0.6

90

57

40

30

23

19

15

12

10

8.2

6.7

5.4

4.3

3.3

2.5

1.8

1.1

1.1


Page-391

24 0.5

9.16 PILOT TESTING – GUIDELINES FOR MEASURING PRODUCTS Return to Table of Contents Using the following procedure may use small measuring spoons as a substitute for a weighing balance for “approximate” weights. Use the conversion table to determine the number of grams per spoonful. 1. Procedure: Powdered materials:

Fill the measuring spoon to overflowing. Tap lightly, and level with a straight edge.

Liquid material:

Use a syringe

2. Example: 1 gram is equivalent to 1 kilogram 1 litre is equivalent to 1 m3 Adding 33.5 grams (5 tablespoons) of Bentonite to 1 litre of freshwater, would be equivalent to a concentration of 33.5 kg/m3.

PRODUCT Barite Bentonite Calcium Carbonate Canex Caustic Potash Caustic Soda CMC Cypan Desco CF Diaseal M Drispac Gypsum Ironite Sponge Kelzan XCD Lignite Lime Mica Mud Floc II Pelthinz Potassium Chloride Salt Salt Gel Soda Ash Sodium Bicarbonate Soltex Starch

SPECIFIC GRAVITY 4.20 2.30-2.60 2.8

¼ Teaspoon (grams) 2.08 0.98 1.00

½ Teaspoon (grams) 4.17 1.95 2.25

1 Teaspoon (grams) 8.33 2.90 4.50

1 Tablespoon (grams) 25.00 6.70 13.00

1.2 2.04

0.90 1.00

1.80 2.50

3.60 5.00

10.80 15.00

2.13 1.60 1.05 1.60 >2.0 1.50-1.60 2.32 4.30

1.25 0.50 0.75 0.75 0.80 0.60 1.30 1.50

2.50 1.10 1.50 1.50 1.60 1.20 2.30 3.50

5.00 2.30 3.00 3.00 3.20 2.40 4.90 8.00

15.00 6.60 10.00 9.60 12.60 7.60 12.60 25.00

1.5 1.60 2.20 2.75 1.4 1.20 1.98

1.00 0.85 0.60 0.50 0.40 0.50 1.90

1.90 1.70 1.30 0.80 1.00 1.00 3.10

3.60 3.40 2.40 2.00 2.00 2.00 6.10

10.70 10.20 7.70 5.80 6.50 6.00 19.10

2.16 2.20-2.40 2.51 2.16

1.50 0.70 1.60 0.72

3.00 1.50 3.00 1.45

6.00 3.00 6.00 2.90

18.00 8.80 17.80 8.70

1.2-1.5 1.45

0.50 0.63

1.00 1.25

2.00 2.50

6.00 7.50

Page-392

Page-393

9.17 BRINE DENSITY TABLE Return to Table of Contents It becomes more and more common to use low solids or completely solids-free systems to drill certain sections of a well. The main application of these systems is to drill the reservoir section where a minimized solids content provides exceptionally low formation damage. The density of those systems is not adjusted with solids, but instead with heavy brines, and normally only a small amount of soluble solids (Calcium Carbonate or sized Salts) is added to build a thin filter cake for fluid loss control. BRINE KCl (Potassium Chloride) NaCl (Sodium Chloride) NaCOOH (Sodium Formate) CaCl2 (Calcium Chloride) NaBr (Sodium Bromide) KCOOH (Potassium Formate) CaBr2 (Calcium Bromide) CaCl2 / CaBr2 ZnBr2 (Zinc Bromide) CsCOOH (Cesium Formate)

MAXIMUM DENSITY (kg/m3) 1160 1200 1340 1390 1510 1560

MAXIMUM DENSITY (lb/gal) 9.6 10.0 11.2 11.6 12.6 13.0

1810 1870 2300 2340

15.1 15.6 19.2 19.5

Note: Do not use the above mentioned densities without referencing the Brine tables for freeze and crystallization points

9.18 PROPERTIES OF SODIUM CHLORIDE SOLUTIONS (Salt) % Salt

Density (kg/m3)

1 3 4 6 7 9 11 12 14 15 17 18 20 21 23 24 26

1006 1018 1030 1042 1054 1066 1078 1090 1102 1114 1126 1138 1150 1162 1174 1186 1198

Salt Content (kg/m3) 8.56 25.68 45.65 62.77 79.89 99.86 116.98 134.10 154.07 174.04 194.02 211.14 231.11 251.08 271.05 291.03 311.00

Salt NaCl (mg/L) 10050 30660 41070 62480 73500 95760 118700 130300 153100 165800 190600 202700 229600 242800 269700 283300 311300

Properties based on 20C and 100% purity

mg/L Salt (NaCl) = mg/L Chlorides X 1.65

Page-394

Chlorides Cl(mg/L) 6100 18600 24920 37910 44600 57500 71950 79070 92900 100500 115500 123000 139320 147200 163500 171900 188900

Return to Table of Contents Water Freezing Volume Point (m3) (C) 0.998 -0.6 0.996 -1.8 0.993 -2.4 0.981 -3.7 0.976 -4.4 0.969 -5.8 0.952 -7.4 0.952 -8.2 0.948 -9.9 0.940 -10.9 0.933 -12.9 0.926 -14.0 0.919 -16.5 0.909 -18.6 0.902 -20.7 0.895 -15.0 0.888 -3.9

mg/L Chlorides = mg/L Salt (NaCl) X 0.0606

Page-395

9.19 PROPERTIES OF POTASSIUM CHLORIDE SOLUTIONS (KCl) Return to Table of Contents

% KCl

Density (kg/m3)

KCl (kg/m3)

KCl (mg/L)

K+ (mg/L)

Cl(mg/L)

1 2 4 6 8 10 12 14 16 18 20 22 24

1006 1013 1026 1039 1052 1065 1079 1093 1106 1120 1135 1149 1160

11.4 20.0 39.9 62.8 82.8 105.6 128.4 154.1 176.9 202.6 225.4 251.1 279.6

10050 20220 40960 62210 84000 106300 129200 152700 176700 201300 226600 252400 279000

5271 10605 21482 32627 44056 55752 67762 80087 92674 105576 118845 132376 146327

4779 9615 19478 29583 39945 50548 61439 72613 84026 95724 107755 120024 132673

Final Volume Factor 1.004 1.008 1.016 1.024 1.033 1.043 1.053 1.064 1.076 1.088 1.102 1.115 1.028

Freezing Point ( C) 0 -1 -2 -3 -4 -5 -6 -7 -8 -9 -10 1 13


9.20 PROPERTIES OF POTASSIUM SULFATE SOLUTIONS (K 2SO4) Return to Table of Contents % K2SO4

Density (kg/m3)

K2SO4 (kg/m3)

K+ (mg/L)

SO4-2 (mg/L)

1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0 5.5 6.0 6.5 7.0 7.5 8.0 8.5 9.0 9.5 10.0

1008 1012 1016 1020 1024 1028 1032 1037 1041 1045 1049 1053 1057 1061 1066 1070 1074 1078 1083

10.0 15.1 20.2 25.4 30.5 36.0 41.5 46.5 52.0 57.3 62.7 68.1 73.8 79.2 84.9 90.6 96.3 102.0 107.8

4532 6821 9110 11443 13776 16110 18488 20911 23920 25758 28181 30649 33162 35675 381888 40746 43304 45907 48509

5568 8379 11190 14057 16924 19790 22712 25689 28610 31642 34619 37651 40738 43825 46912 50054 53196 56393 59591


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Final Volume Factor 1.004 1.005 1.006 1.007 1.008 1.009 1.011 1.012 1.013 1.014 1.016 1.017 1.019 1.020 1.021 1.023 1.024 1.026 1.027

Freezing Point ( C) -0.28 -0.06 -0.05 -0.06 -0.06 -0.11 -0.11 -1.06 -1.17 -

9.21 PROPERTIES OF 94% PURE CALCIUM CHLORIDE SOLUTIONS (CaCL2) Return to Table of Contents WEIGHT (%)

DENSITY (kg/m3)

CaCl2 (kg/m3)

CaCl2 (mg/L)

Ca+2 (mg/L)

Cl(mg/L)

Volume Final Solution

Freezing Point (C)

Water Activity

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 22 24 26 28 30 32 34 36 38 40

1007 1015 1023 1032 1040 1049 1057 1066 1075 1084 1092 1101 1111 1120 1129 1139 1148 1158 1168 1178 1198 1218 1239 1260 1282 1304 1326 1349 1372 1396

10.0 20.0 30.5 41.3 51.9 62.7 73.8 85.2 96.3 108.0 120.0 132.0 143.9 156.5 169.0 181.8 194.6 207.8 221.4 234.8 262.7 291.5 321.2 352.0 383.6 416.1 449.7 484.5 520.1 556.9

10084 20337 30763 41363 52142 63101 74245 85574 97094 108805 120712 132816 145121 157630 170346 183270 196407 209759 223329 237120 265375 294159 324659 354734 387795 420864 454964 490118 526349 554243

3647 7331 11087 14915 18779 22715 26723 30804 34921 39110 43407 47741 52147 56625 61175 65797 70492 75259 80134 85045 95157 105557 116319 127405 138853 150626 162796 175363 188291 201617

6453 12969 19613 26385 33221 40185 47277 54496 61779 69190 76793 84459 92253 100175 108225 116403 124708 133141 141766 150455 168343 186743 205781 225395 245647 266474 288004 310237 333109 356683

1.003 1.005 1.007 1.009 1.013 1.016 1.019 1.022 1.025 1.028 1.031 1.035 1.038 1.042 1.046 1.050 1.156 1.166 1.176 1.186 1.207 1.227 1.249 1.271 1.293 1.316 1.152 1.168 1.187 1.203

0 -1 -1 -2 -3 -4 -4 -5 -6 -6 -7 -8 -9 -10 -11 -12 -13 -14 -16 -18 -23 -25 -30 -41 -44 -33 -20 -6 +3 +12

0.994 0.989 0.985 0.980 0.975 0.971 0.965 0.960 0.954 0.948 0.940 0.932 0.924 0.914 0.904 0.892 0.880 0.867 0.852 0.837 0.804 0.767 0.726 0.683 0.637 0.590 0.541 0.492 0.443 0.395



Milligrams/litre (mg/L) may be converted to parts per million (ppm) by dividing mg/L by the specific gravity. Specific Gravity = Density (kg/m3) 1000

  

mg/L CaCl2 = mg/L Chlorides X 1.5652 mg/L Chlorides = mg/L CaCl2 X 0.6389 ppm CaCl2 = % CaCl2 by weight X 10000

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9.22 PROPERTIES OF ENVIROFLOC (Calcium Nitrate) SOLUTIONS Return to Table of Contents Weight (%)

Density (kg/m3)

Envirofloc (kg/m3)

Calcium (kg/m3)

Nitrate (kg/m3)

Volume Final Solution

Water Activity

1 2 3 4 5 6 7 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36 38 40 42 44 46 48 50 52 54 56 58 60 62 64 66 68 70

1005 1011 1017 1024 1030 1036 1043 1049 1062 1075 1090 1104 1119 1133 1148 1163 1178 1193 1208 1224 1239 1255 1272 1288 1305 1322 1340 1358 1377 1395 1416 1436 1457 1478 1498 1519 1539 1560 1581

10.05 20.22 30.51 40.96 51.50 62.16 73.01 83.92 106.2 129.0 152.6 176.6 201.4 226.6 252.6 279.1 306.3 334.0 362.4 391.7 421.3 451.8 483.4 515.2 548.1 581.7 616.4 651.8 688.5 725.4 764.6 804.2 845.1 886.8 928.8 972.2 1016 1061 1107

1.864 3.750 5.658 7.596 9.550 11.53 13.54 15.56 19.69 23.92 28.30 32.76 37.35 42.02 46.83 51.76 56.80 61.94 67.20 72.63 78.12 83.78 89.63 95.54 101.6 107.9 114.3 120.9 127.7 134.5 141.8 149.1 156.7 164.4 172.2 180.3 188.4 196.7 205.2

6.343 12.76 19.26 25.85 32.50 39.23 46.08 52.97 67.03 81.42 96.32 111.5 127.1 143.0 159.4 176.2 193.3 210.8 228.7 247.2 265.9 285.2 305.1 325.2 345.9 367.1 389.0 411.4 434.6 457.8 482.6 507.6 533.4 559.7 586.2 613.6 641.1 669.5 698.5

1.005 1.009 1.013 1.017 1.021 1.026 1.030 1.035 1.044 1.054 1.063 1.073 1.082 1.094 1.105 1.116 1.128 1.141 1.154 1.168 1.182 1.197 1.211 1.227 1.243 1.259 1.276 1.293 1.311 1.330 1.348 1.368 1.388 1.408 1.431 1.453 1.476 1.501 1.525

1.00 0.99 0.99 0.99 0.98 0.98 0.97 0.97 0.96 0.95 0.94 0.93 0.92 0.91 0.90 0.89 0.88 0.87 0.86 0.85 0.84 0.82 0.81 0.80 0.79 0.77 0.76 0.74 0.73 0.71 0.70 0.68 0.67 0.65 0.63 0.61 0.60 0.58 0.56

Envirofloc = 5.393 X Calcium Calcium = 0.1854 X Envirofloc Nitrate = 0.6312 X Envirofloc Ammonium = 0.0167 X Envirofloc Nitrate = 3.404 X Calcium mg/L = 1000 (kg/m3)

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9.23 PROPERTIES OF SODIUM – CALCIUM CHLORIDE BLENDS Return to Table of Contents

(kg/m3 @ 15.5C)

DENSITY

WATER (m3)

100% NaCl (kg/m3)

94-97% CaCl2 (kg/m3)

1210 1222 1234 1246 1258 1270 1282 1294 1306 1318 1330

0.887 0.875 0.875 0.876 0.871 0.868 0.866 0.864 0.862 0.859 0.854

251 199 154 117 91 71 57 46 37 29 23

83 148 205 253 296 330 359 385 410 430 453

Crystallization Point (C) -20 -23 -26 -29 -32 -36 -39 -41 -31 -24 -18

9.24 PROPERTIES OF AMMONIUM CHLORIDE SOLUTIONS Return to Table of Contents WEIGHT (%)

DENSITY (kg/m3)

Cl(mg/L)

NH4+ (mg/L)

1 1001 6066 3934 2 1005 12193 7907 3 1008 18320 11880 4 1011 24508 15892 5 1014 30756 19944 6 1017 37004 23996 7 1020 43313 28087 8 1023 49622 32178 9 1026 55992 36308 10 1029 62422 40478 11 1032 68852 44648 12 1034 75282 48818 13 1037 81773 53027 14 1040 88325 57275 15 1043 94877 61523 16 1046 101489 65811 17 1049 108101 70099 18 1051 114774 74426 19 1054 121508 78792 20 1057 128180 83120 22 1062 141769 91931 24 1067 155418 100782 Properties based on 20C and 100% purity

Page-399

NH4Cl (kg/m3)

Water (m3)

10.0 20.0 30.2 40.2 50.4 60.9 71.2 81.5 92.1 102.6 113.1 123.7 134.5 145.3 155.9 167.0 177.8 188.7 199.8 210.9 233.1 255.6

0.991 0.984 0.977 0.970 0.963 0.956 0.948 0.941 0.933 0.926 0.918 0.910 0.902 0.895 0.887 0.878 0.870 0.862 0.854 0.845 0.828 0.811

Crystallization Point (C) -0.6 -1.3 -1.9 -2.5 -3.2 -3.9 -4.7 -5.4 -6.2 -6.9 -7.8 -8.6 -9.4 -11.7 -0.5

9.25 PROPERTIES OF MAGNESIUM CHLORIDE SOLUTIONS Return to Table of Contents WEIGHT (%)

DENSITY (kg/m3)

Cl(mg/L)

Mg+2 (mg/L)

MgCl2 (kg/m3)

Water (m3)

1 2 3 4 5 6 7 8 9 10 12 14 16 18 20 22 24 26 28 30

1006 1014 1023 1031 1039 1048 1056 1065 1074 1083 1101 1119 1137 1155 1174 1194 1214 1235 1256 1276

7492 1506 22842 30703 38696 46814 55060 63444 71957 80608 98329 116635 135477 154838 174856 195553 216940 239006 261748 285091

2568 5178 7830 10524 13264 16047 18873 21747 24665 27631 33705 39980 46439 53075 59937 67031 74362 81926 89722 97723

10.1 20.5 31.3 42.4 53.9 65.7 80.0 90.5 10.5 116.9 145.0 174.8 206.4 239.7 275.1 312.8 352.9 395.4 440.3 487.6

0.9962 0.9941 0.9919 0.9897 0.9874 0.9850 0.9825 0.9799 0.9772 0.9744 0.9685 0.9623 0.9552 0.9474 0.9394 0.9312 0.9226 0.9136 0.9039 0.8934

Crystallization Point (C) -0.5 -1.1 -1.7 -2.3 -3.0 -4.3 -5.4 -5.8 -6.8 -7.7 -9.7 -14.5 -18.8 -25.0 -33.2 -28.1 -24.3 -20.5 -17.1 -16.4

Water Activity 0.995 0.990 0.984 0.978 0.972 0.964 0.957 0.948 0.939 0.929 0.906 0.879 0.848 0.812 0.772 0.727 0.677 0.624 0.567 0.507

9.26 PROPERTIES OF POTASSIUM ACETATE SOLUTIONS Return to Table of Contents WEIGHT (%)

DENSITY (kg/m3)

K+ (mg/L)

C2H3O2(mg/L)

KC2H3O2 (mg/L)

Water (m3)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25

1004 1009 1014 1019 1024 1029 1034 1040 1045 1050 1055 1060 1065 1070 1076 1081 1086 1091 1097 1102 1086 1113 1119 1124 1129

3984 7967 11951 15935 19918 25040 29593 34146 39837 44390 48943 54634 59186 64877 70568 76259 81950 87641 93332 100162 105853 112682 119511 126340 133169

6016 12033 18049 24065 30082 37817 44693 51568 60163 67039 73915 82509 89385 97980 106574 115169 123764 132359 140953 151267 159862 170175 180489 190803 201116

10.0 20.0 29.9 40.0 49.9 62.7 74.1 85.5 99.8 111.1 122.5 136.8 148.2 162.4 176.7 191.1 205.2 219.4 233.7 250.8 265.0 282.1 299.2 316.3 333.4

0.994 0.989 0.984 0.979 0.974 0.966 0.960 0.954 0.945 0.938 0.932 0.923 0.917 0.907 0.898 0.889 0.880 0.871 0.863 0.851 0.820 0.830 0.819 0.807 0.795

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Crystallization Point (C) 0.0 -0.3 -0.5 -17.2 -

Water Activity 0.99 0.98 0.97 0.96 0.95 0.94 0.93 0.92 0.91 0.90 0.89 0.88 0.87 0.86 0.85 0.84 0.83 0.82 0.81 0.80 0.79 0.78 0.77 0.76 0.75

9.27 COMMON CHEMICAL FORMULAS AND NAMES Return to Table of Contents COMMON NAME Aluminum Sterate Ammonium Bisulfite Anhydrite Barite Barium Carbonate Bicarb (Baking Soda) Calcium Carbonate Calcium Chloride Caustic Potash Caustic Soda DAP Dolomite Envirofloc Galena Gypsum H 2S Hematite Hot or Quick Lime Ironite Sponge Lime Limestone Potash Potassium Sulfate Salt SAPP Silica Soda Ash Sodium Sulfite Zinc Carbonate

CHEMICAL NAME Aluminum Sterate Ammonium Bisulfite Calcium Sulfate Barium Sulfate Barium Carbonate Sodium Bicarbonate Calcium Carbonate Calcium Chloride Potassium Hydroxide Sodium Hydroxide Diammonium Phosphate Calcium Magnesium Carbonate Calcium Ammonium Decahydrate Lead Sulfide Calcium Sulfate Hydrogen Sulfide Ferric Oxide Calcium Oxide Iron Oxide Calcium Hydroxide Calcium Carbonate Potassium Chloride Potassium Sulfate Sodium Chloride Sodium Acid Pyrophosphate Silicon Dioxide Sodium Carbonate Sodium Sulfite Zinc Carbonate


Page-401

CHEMICAL FORMULA Al(C18H3O2)3 (NH4)HSO3 CaSO4 BaSO4 BaCO3 NaHCO3 CaCO3 CaCl2 KOH NaOH (NH4)2HPO4 CaMg(CO3)2 5Ca(NO3)2.NH4NO3.10H2O PbS CaSO4.2H20 H 2S Fe2O3 CaO Fe2O4 Ca(OH)2 CaCO3 KCl K2SO4 NaCl Na2H2P2O7 SiO2 Na2CO3 Na2SO3 ZnCO3

9.28 COMMON DRILLING MUD CATIONS (+ ions) ION NAME Aluminum Ammonium Barium Calcium Carbon Cesium Chromium (Chromic) Chromium (Chromus) Copper (Cuprium) Hydrogen Iron (Ferric) Iron (Ferrous) Lead (Plumbic) Lead (Plumbus) Magnesium Manganese Nickel Phosphorus Potassium Silicon Silver Sodium Zinc

9.29 ION NAME Bicarbonate Bisulfate Bisulfide Bisulfite Bromate Bromide Carbonate Chloride Chromate Dichromate Fluoride Hydroxide Hypochlorite Nitrate Nitrite Perchlorate Phosphate Sulfate Sulfide Sulfite

SYMBOL Al NH4 Ba Ca C Cs Cr Cr Cu H Fe Fe Pb Pb Mg Mn Ni P K Si Ag Na Zn

Return to Table of Contents VALENCE +3 +1 +2 +2 +4 +1 +3 +2 +2 +1 +3 +2 +4 +2 +2 +2 +2 +5 +1 +4 +1 +1 +2

COMMON DRILLING MUD ANIONS (- ions) SYMBOL HCO3 HSO4 HS HSO3 BrO3 Br CO3 Cl CrO4 Cr2O7 F OH ClO NO3 NO2 ClO4 PO4 SO4 S SO3

Page-402

Return to Table of Contents VALENCE -1 -1 -1 -1 -1 -1 -2 -1 -2 -2 -1 -1 -1 -1 -1 -1 -3 -2 -2 -2

9.30 SPECIFIC GRAVITY OF COMMON MATERIALS Return to Table of Contents SPECIFIC GRAVITY 4.2-4.3 2.3-2.4 1.08 2.7 2.2 1.85 1.53 3.4 2.96 2.044 3.0-3.2 1.665 2.5-2.7 1.59 0.84 2.8-3.0 1.12 2.4-2.7 1.0 6.5-6.7 2.9 1.38-1.40 5.26 7.8 4.9-5.3 11.3 1.5 2.34 3.2-3.4 2.7-2.9 1.99 5.02 2.65 2.165 2.55 2.4-2.8 1.862 1.2 2.53 2.16 2.63 1.5 7.8 1.06 4.4

MATERIAL Barite Bentonite Blacknight Calcium Carbonate Calcium Chloride (94%) Calcium Chloride (Flake) Calcium Lignosulfonte Calcium Oxide (Hot Lime) Calcium Sulfate Caustic Potash Cement Citric Acid Clays (Drilled Solids) CMC Diesel Fuel Dolomite Envirofloc Feldspar Fresh Water Galena Gypsum HEC 10 Polymer Hematite Iron Ironite Sponge Lead Lignite Lime (Hydrated) Lime (Hot or Quick Lime) Limestone Potassium Chloride Pyrite Quartz Salt Salt Gel Sand SAPP Sea Water Soda Ash Sodium Bicarbonate Sodium Sulfite Starch Steel X-Pel-G Zinc Carbonate

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9.31 RECOMMENDED SOLIDS CONTENT OF WATER BASE MUDS Return to Table of Contents

Approximate range of field muds in good condition

9.32 SUGGESTED RANGES OF PLASTIC VISCOSITY


Page-404

9.33 SUGGESTED RANGES OF YIELD POINT


9.34 GENERAL FORMULAS 1. Annular Volume; m3 = [Hole Capacity, m3/m – (Pipe Displacement, m3/m + Pipe Capacity, m3/m)] X Length, m 2. Pipe Volume; m3 = Pipe Capacity, m3/m X Length, m 3. Total Hole Volume; m3 = (Hole Capacity, m3/m – Pipe Displacement, m3/m) X Length, m 4. Tank Volume; m3 = Length, m X Width, m X Height, m 5. Total Circulating Volume; m3 = Total Hole Volume, m 3 + Tank Volume, m3 6. Total Circulating Time; min = Total Circulating Volume, m3 Pump Output, m3/min 7. Bottoms Up Time; min = Total Annular Volume, m3 Pump Output, m3/min 8. Annular Velocity; m3/min = Pump Output, m3/min X 1273000 (Dh2) – (Dp2) Dh = Hole Diameter, mm Dp = Pipe Diameter, mm

Page-405

Hydrostatic Pressure; kPa = Density, kg/m3 X 0.00981 X Depth, m 9. Pressure Gradient; kPa/m = Density, kg/m3 X 0.00981 10. Barite Required for a Mud Density Increase; kg/m3 = 4250 (W2 – W1) 4250 – W2 W2 = Desired Mud Density, kg/m3 W1 = Initial Mud Density, kg/m3 11. Volume Increase form Barite Addition; m3 = Amount of Barite Added, kg 4250 12. Density Reduction with Water; water required m3 = V (W1 – W2) W2 – 1000 V = Initial Starting Volume, m3 W1 = Initial Mud Density , kg/m3 W2 = Desired Mud density, kg/m3 13. Density Reduction with Oil; final mud density, kg/m3 = W1 + % Oil (Wo) 1 + % Oil W1 = Initial Mud Density, kg/m3 Wo = Density of Oil, kg/m 3 % Oil = Volume Fraction of Oil, i.e.: 2% oil as a volume fraction is 0.02 14. Pressure Loss at the Bit;  Pb (mPa) = MW X Q2 X 248__ (d12 + d22 + d32)2 MW = Mud Weight , kg/m3 Q = Pump Output, m3/min d1, d2, d3 = Bit Nozzle Diameter, mm 15. Hydraulic Horsepower at the Bit; HHb (W) = Q X  Pb X (1.66X104) Q = Pump Output, m3/min  Pb = Pressure Loss at the Bit, mPa

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16. Hydraulic Horsepower Across the Face of the Bit,; HH (MH/m2) = HHb X 1.27 d2 HHb – Hydraulic Horsepower at the Bit, W d = Diameter of the Bit, mm 17. Equivalent Circulating Density; kg/m3 = MW + [

 P_____ ] L X 0.00981

MW = Mud Weight  P = Sum of all the Annular Pressure Losses, kPa L = Depth of Interest, m 18. “n” Factor Power Law Index = 3.32 log10 (600 ) (300 )  = Viscometer Dial Reading 19. Volume Fraction of Solids (unweighted muds); % volume fraction =

[ ( MW – 1 )] X 0.625 1000

MW = Mud Weight, kg/m3 Return to Table of Contents

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Advantage Mud Manual .pdf

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