Section C2 Fluid Testing and Property Maintenance

Transcription

1 FORMATE FIELD PROCEDURES AND APPLICATIONS Section C2 Fluid Testing and Property Maintenance C2.1 Fluid testing procedures...2 C2.1.1 Introduction...2 C2.1.2 ph...2 C2.1.3 Density...2 C2.1.4 Solids analysis of formate fluids...4 C2.1.5 Total hardness (Ca 2+ + Mg 2+ )...4 C2.1.6 Calcium (Ca 2+ )...5 C2.1.7 Dissolved carbonate and bicarbonate (ph buffer) content...5 C2.2 Property maintenance and adjustment...6 C2.2.1 Introduction...6 C2.2.2 Density...6 C2.2.3 Contamination...8 C2.2.4 ph maintenance...9 C2.2.5 Carbonate / bicarbonate (buffer) maintenance...9 C2.2.6 Calcium carbonate maintenance...10 C2.2.7 Polymer maintenance...10 C2.3 Performance enhancement and problem solving C2.3.1 ROP enhancement...10 C2.3.2 Hole cleaning and hydraulics C2.3.3 Fluid loss, rheology, and gelling problems C2.3.4 Foaming C2.3.5 Erratic gas readings References The Formate Technical Manual is continually updated. To check if a newer version of this section exists please visit NOTICE AND DISCLAIMER. The data and conclusions contained herein are based on work believed to be reliable; however, CABOT cannot and does not guarantee that similar results and/or conclusions will be obtained by others. This information is provided as a convenience and for informational purposes only. No guarantee or warranty as to this information, or any product to which it relates, is given or implied. CABOT DISCLAIMS ALL WARRANTIES EXPRESS OR IMPLIED, INCLUDING MERCHANTABILITY OR FITNESS FOR A PARTICULAR PURPOSE AS TO (i) SUCH INFOR- MATION, (ii) ANY PRODUCT OR (iii) INTELLECTUAL PROPERTY INFRINGEMENT. In no event is CABOT responsible for, and CABOT does not accept and hereby disclaims liability for, any damages whatsoever in connection with the use of or reliance on this information or any product to which it relates Cabot Corporation, M.A.-U.S.A. All rights reserved. CABOT is a registered trademark of Cabot Corporation. SECTION C2 PAGE 1

2 C2.1 Fluid testing procedures C2.1.1 Introduction Most of the standard API testing procedures for brines [1] and water-based drilling fluids [2] are valid for formate-based fluids. There are, however, a few tests that should not be used in formate brines and alternative, formate-specific methods have been developed by Cabot Specialty Fluids (CSF). Table 1 lists the standard API tests, specifying those recommended for formate fluids and those that are not. Full description of the methods that are unique to formate fluids or modified for use with formate fluids are given below. C2.1.2 ph The ph of formate drilling fluid filtrate or completion brine should always be measured on a sample diluted with nine parts deionized water as undiluted samples give erroneous results (see Section A6 ph and Buffering). ph of this diluted brine is best measured with a glass electrode ph meter (see Section A6 ph and Buffering). ph paper can be used, but generally gives a less accurate ph reading. A handheld ph meter, Hanna Instruments Waterproof Handheld ph / Temp probe HI 98128, was tested by Cabot Specialty Fluids and found to give very reliable ph measurements in diluted (1:9) formate brines. If the ph reading is used to calculate buffer concentration (see C2.1.7) it is important that a reliable, calibrated ph meter is used. C2.1.3 Density The density of formate fluids can be measured using one of three devices: pressurized mud balance, hydrometer, or digital densitometer. The pressurized mud balance should be used for formate drilling fluids and preferably the digital densitometer, or alternatively the hydrometer, for formate brines and filtrates. Pressurized mud balance procedure: Place mud balance on bench. Place fluid to be measured in a beaker, and stir if appropriate. Slowly add fluid to the cell until the fluid is approximately half way between the indicator line and the edge of the cell. The aim is that some fluid should spill out of the valve. Put the cap in place and rotate it until firmly seated. Wash or wipe any residual fluid from the outside of the cup. To clean the pressurizing plunger (syringe), fill it with fluid from the beaker and expel the fluid. Fill the plunger again and use this fluid to pressurize the cup. Hold the pump firmly. While pressure is applied, gently pull the pump upwards to force the valve out of the screw cap. Ideally, no fluid should leak out of the valve at this stage. Wash off excess fluid and dry the balance. Place the system on the fulcrum and adjust to achieve balance. Read off the density. Using the pump, push down the valve so that it is immersed again. Disconnect the whole system (the pump might Table 1 API tests in formate brines and fluids. Property Test method Comments ph CSF method CSF method on sample diluted with deionized water Density (drilling fluid) API-13B-1 Use CSF temperature correction method Density (brine) API-13J Use densitometer and CSF temperature correction method Solids analysis CSF method DO NOT run retort with formate fluids. Use alternative CSF method Chlorides API-13B-1 No change Total Hardness (Ca 2+ + Mg 2+ ) Calcium Cation exchange capacity (Methylene Blue Test MBT) API-13B-1 API-13B-1 API-13B-1 Test is not required in buffered formate fluids. If the test is used on formate fluids without buffer present, the sodium hypochlorite treatment should be avoided Test is not required in buffered formate fluids. If the test is used on formate fluids without buffer present, the sodium hypochlorite treatment should be avoided No change Turbidity API-13J No change API fluid loss API-13B-1 HPHT fluid loss API-13B-1 No change Rheology API-13B-1 No change Alkalinity and lime content (P f, M f ) Buffer concentration (CO 3 2- and HCO 3- ) K content API-13B-1 No change. Advisable to run two cells to obtain enough clear filtrate for chemical analyses Mf cannot be measured in formate brines. See alternative CSF method for buffer concentration CSF Method Replaces API alkalinity test (P f, M f ) IDF Technical manual Does not work in formates as sodium hypochlorite is an oxidizing agent PAGE 2 SECTION C2

3 SECTION C: FORMATE FIELD PROCEDURES AND APPLICATIONS CABOT SPECIALTY FLUIDS be used to aid removal of the cap from the cell). Immediately measure the temperature using a 7 cm immersion thermometer. This is the actual temperature of the sample. Wash, dry, and store. The corrected density (at 15.6 C / 60 F) can be calculated using the procedure described below. Hydrometer (for brine and filtrate) Take a 250 ml volumetric cylinder and fill with the test fluid close to the rim of the cylinder. Measure the temperature using a 7 cm immersion thermometer. This is the actual temperature of the sample. Use a hydrometer covering the density range of the sample. Spin hydrometer and measure density once it stops and has balanced. The corrected density (at 15.6 C / 60 F) can be calculated using the procedure described below. Digital Densitometer (Densito 30PX portable densitometer) (for brine and filtrate) Switch the instrument on by pressing and holding the ESC key. The instrument is normally set to measure specific gravity (g/cm 3 ) automatically. The instrument s manual provides information on how to display alternative density units. To calibrate the instrument use distilled water, or preferably, the density standards supplied with the instrument. Insert the sampling tube into the standard. Press the FILL button. Press the OK / MEAS button to start the measurement. If the displayed result is < or > then adjust the instrument using the instructions in the manual. Repeat the above procedure with a sample, always recording the temperature at the time of the measurement. To clean the instrument, press the DRAIN button, fill the measuring cell with a suitable solvent and drain again. Repeat until the cell is clean. Switch the instrument off by pressing and holding the ESC key for two seconds. The corrected density (at 15.6 C / 60 F) can be calculated using the method described below. Calculation of corrected density Once the density and actual temperature have been measured, the corrected density at standard conditions (15.6 C / 60 F) can be calculated. Complete PVT data exists for diluted single-salt potassium formate brines, and for potassium cesium formate brine blends. There are three ways of utilizing these data for calculating density at standard conditions: 1. Use DensiCalc II software, available free from Cabot Specialty Fluids. This method gives the most accurate results. 2. Use tables for corrected density (Table 3 to Table 14). The corrected fluid density can be found in the cell where the measured density and measured temperature intercept. 3. Use the following simplified formula: ρ ST = ( T M ) + ( ρ M ) (1) where ρ ST = density at 15.6 C / 60 F ρ M = measured density T M = measured temperature in C Example: ρ M = T M = 37ºC ρ ST = ( ) + ( ) = Calculation of effective density The effect of temperature and pressure on the density of the fluid in the well must be calculated in order to provide the required equivalent static density (ESD). This is best achieved using the DensiCalc II software, freely available from Cabot Specialty Fluids. Calculating the effective density manually is complex and gives a slightly different result due to rounding errors. For formate brines, the temperature effect on density is much greater than the pressure effect. Therefore, as a rule of thumb, Table 2 can be used for reducing density from the corrected density. Remember this is a rough guide only and is affected by well type, such as deep water wells where the temperature profile is influenced by seawater cooling of the riser. Table 2 Rough estimate of density correction in formate brines as a function of bottom-hole temperature. Bottom-hole temperature Reduction in density from density at standard conditions [ C] [ F] g/cm 3 lb/gal SECTION C2 PAGE 3

4 C2.1.4 Solids analysis of formate fluids Warning never run a retort test on a formate fluid! The standard API retort test should never be used with formate fluids because the condensation chamber of the standard retort could get plugged with salt crystals causing the retort to burst. Even if the retort test could be performed safely, results are invalid since most solids are formed from formate salts crystallizing out of the highly concentrated brines. Solids in a formate mud generally comprise of drilled solids and calcium carbonate bridging solids (no weighting material is required in formate muds). Based on this, an alternative solids analysis procedure is detailed here. Calcium carbonate A method has been developed to test for calcium carbonate weighting material in formate fluids. The method, which is based on the standard API total hardness (Ca 2+, Mg 2+ ) method, involves removing the carbonate component as carbon dioxide by lowering the ph. The method determines the combined calcium carbonate and magnesium carbonate concentrations, which means that any dolomite-type weighting material is also determined. The method is as follows: Add 1 ml formate drilling fluid to a 100 ml volumetric flask. Add 9 ml 2N/5N hydrochloric acid. Agitate gently to ensure all the calcium carbonate has dissolved. Fill the volumetric flask to the 100 ml line with deionized water and shake. Take a 10 ml sample from the volumetric flask and place in a smaller conical flask or beaker. Add 0.5 ml 8N potassium hydroxide (KOH). Check that the ph is at 14 with ph paper and add more potassium hydroxide, if required. Add Calver 2 Indicator and titrate with EDTA (0.01 M), recording the volume of EDTA required to change from red to blue. The calcium carbonate concentration can be calculated as: C CaCO3 (g/l or kg/m 3 ) = 10 V EDTA (ml) (3) where C CaCO3 = CaCO 3 concentration (kg/m 3 or g/l) V EDTA = Volume 0.01M EDTA (ml) Example: If EDTA titration = 5 ml, then the calcium carbonate concentration would be 50 g/l (since the chemical analysis was performed using 10 ml of the 100 ml prepared sample). Drill solids The amount of drill solids in the mud is calculated by determining the total solids in the mud (lowgravity solids comprising drill solids and calcium carbonate), and then subtracting the calcium carbonate portion. The low-gravity solids in the mud can be calculated by measuring the mud and filtrate densities, using the following equation: LGS (%v) = ρ mud-ρ filtrate ρ LGS -ρ filtrate 100 (4) where ρ mud = density or s.g. of mud ρ filtrate = density or s.g. of filtrate ρ LGS = density or s.g. of low-gravity solids The density of the mud is measured using a pressurized mud balance (see C2.1.3) and the density of the mud HPHT filtrate is measured using either the densitometer or a 5 ml gravity bottle. If a density bottle is used, the bottle is first weighed empty, then filled with filtrate and re-weighed. The density is calculated from the difference between the two weights divided by the filtrate volume, which is inscribed on the gravity bottle. The temperatures are also measured and the densities are corrected to standard temperature (15.6 C / 60 F) using DensiCalc II. By assuming that the density of the low-gravity solids is 2.5 g/cm 3 / lb/gal, the low-gravity solids concentration in the fluid can be calculated as: METRIC UNITS C LGS (g/l) = 25 LGS (%V) (5) FIELD UNITS C LGS (lb/bbl) = 8.76 LGS (%V) (6) and the drill solids concentration is calculated as follows: C DS = C LGS - C CaCO3 (7) where C DS, C LGS, and C CaCO3 are concentrations of drill solids, low gravity solids, and calcium carbonate respectively. This equation is valid for all density units. C2.1.5 Total hardness (Ca 2+ + Mg 2+ ) In a formate fluid containing carbonate / bicarbonate ph buffer, it is unnecessary to check calcium or magnesium levels as these ions cannot be present in PAGE 4 SECTION C2

5 SECTION C: FORMATE FIELD PROCEDURES AND APPLICATIONS CABOT SPECIALTY FLUIDS any significant amounts as they precipitate out with the carbonate buffer component. If total hardness is measured in an unbuffered formate fluid or in a formate fluid where the buffer could have been consumed, then the standard API method cannot be used directly because the oxidizing agent, hypochlorite, rapidly oxidizes the formate. If such a test is required, the API method should be modified to omit this step. Cabot Specialty Fluids recommends the following modified method for determining hardness in formate brine or filtrate: Add 1 ml formate brine or filtrate to a 100 ml volumetric flask. Fill the volumetric flask to the 50 ml line with deionized water and shake. Add about 2 ml buffer solution (67.5 g ammonium chloride and 570 ml ammonium hydroxide diluted to 1,000 ml with distilled water) and swirl to mix. Add sufficient hardness indicator (e.g. Calmagite or equivalent) (2 to 6 drops) and mix. A wine-red color develops if calcium and / or magnesium is / are present. Titrate with 0.01 M EDTA, recording the volume of EDTA required to change from red to blue. The concentration of Ca 2+ and Mg 2+ can be calculated as: C Ca 2+ + C Mg 2+ (mol/l) = V EDTA (ml) 100 The equivalent weight of calcium that this corresponds to ( total hardness as calcium ) is: (8) C Ca 2+ (mg/l) = 400 x V EDTA (ml) (9) where: V EDTA = Volume 0.01M EDTA (ml) C2.1.6 Calcium (Ca 2+ ) In a formate fluid containing carbonate / bicarbonate ph buffer, it is unnecessary to check for calcium levels as calcium cannot be present. If one wants to measure calcium concentration in an unbuffered formate fluid or in a formate fluid where the buffer could have been consumed, then the standard API method cannot be used directly because the oxidizing agent, hypochlorite, rapidly oxidizes the formate. Cabot Specialty Fluids recommends the following modified method for determining hardness in a formate brine or filtrate: Add 1 ml formate brine or filtrate to a 100 ml volumetric flask. Fill the volumetric flask to the 50 ml line with deionized water and shake. Add sodium or potassium hydroxide solution to bring the ph up above 14. Check that the ph is at 14 with ph paper and add more sodium or potassium hydroxide, if required. Add enough calcium indicator (e.g. Calver II Indicator) and mix. A wine-red color develops if calcium is present. Titrate with 0.01 M EDTA, recording the volume of EDTA required to change from red to blue. The molar concentration of calcium can be calculated as: C Ca 2+ (mol/l) = V EDTA (ml) 100 (10) And the concentration of calcium on a weight basis is: C Ca 2+ (mg/l) = 400 x V EDTA (ml) (11) where: V EDTA = Volume 0.01M EDTA (ml) C2.1.7 Dissolved carbonate and bicarbonate (ph buffer) content For standard water-based mud filtrates, API RP 13B-1 [1] recommends that carbonate and bi carbonate content are measured by ph titrations. Alkalinity in the form of carbonate content, bicarbonate content, and hydroxide content is determined by the combination of a phenolphthalein titration with an endpoint of ph = 8.2, and a methyl orange titration to an endpoint of ph = 3.1. In formate brines, the determination of the methyl orange titration endpoint is complicated by the formate / formic acid equilibrium present at ph = 3.75 (explained in Section A6). The fact that only one of the two standard titration endpoints can be determined in a formate brine means that the standard API alkalinity test method is unsuitable for determining carbonate and bicarbonate concentrations in formate fluids. Laboratory testing of formate brines with known additions of carbonate and bicarbonate has shown that ph of buffered formate brines is dependent on the carbonate-to-bicarbonate ratio (see Section A6 ph and Buffering).The following relationship, R, has been found between the carbonate and bicarbonate molar ratio and the brine fluid ph: R = [ 2- CO 3 ] (mol/l) = A exp (B ph) (12) [HCO 3- ](mol/l) where A = B = and [CO 32 ] and [HCO 3- ] are the molar concentrations of carbonate and bicarbonate. This relationship, shown in Figure 1, is valid for ph measured with a SECTION C2 PAGE 5

6 glass electrode in formate brine diluted with nine parts deionized water. This relationship can be used to determine the molar ratio of the buffering components, carbonate and bicarbonate. This means that both carbonate and bicarbonate concentrations can be determined just by measuring ph and performing the standard phenolphthalein titration to determine the carbonate concentration. The method is as follows: 1. Prepare a sample consisting of 5 ml fluid sample (brine or mud filtrate) and 45 ml deionized water. 2. Measure ph of the sample using a calibrated glass electrode. 3. Perform a titration to ph = 8.2 with 0.02 N HCl or H 2 SO 4 and report the phenolphthalein alkalinity p f as the volume, V (ml), titrant required per ml of fluid sample (brine or mud filtrate): P f = V(mL)/5 (13) Depending on ph, four situations exist: 1. ph > 11.1 [CO 3 2- ](mol/l) + OH - (mol/l) = 0.02 P f (14) [HCO 3- ] = 0 (15) Assuming that large amounts of [OH - ] have not been added to this fluid, one can assume that most of this alkalinity is from carbonate. 2. ph = 11.1 [OH - ] = 0 (16) 2- [CO 3 ] (mol/l) = 0.02 P f (17) [HCO 3- ] = 0 (18) < ph < 11.1 [OH - ] = 0 (19) 2- [CO 3 ] (mol/l) = 0.02 P f (20) From the carbonate / bicarbonate ph relationship in equation 12 and Figure 1, determine the carbonate / bicarbonate molar ratio, R. Calculate the bicarbonate concentration as: [HCO 3- ] (mol/l) = [CO 3 2- ] (mol/l) / R (21) 4. ph < = 9.0 [OH - ] = 0 (22) [CO 3 2- ] insignificant [HCO 3- ] difficult to determine ph needs to be raised to above 9.0 with OH - before the bicarbonate level can be determined. Carbonate and bicarbonate levels can also be determined on a weight / volume basis: C CO 3 2- (mg/l) = 60,000 [CO 3 2- ] (mol/l) (23) C CO 3 2- (kg/m 3 ) = 60 [CO 3 2- ] (mol/l) (24) C CO 3 2- (lbs/bbl) = [CO 3 2- ] (mol/l) (25) C HCO 3- (mg/l) = 61,000 [HCO 3- ] (mol/l) (26) C HCO 3- (kg/m3 ) = 61 [HCO 3- ] (mol/l) (27) C HCO 3- (lbs/bbl) = [HCO 3- ] (mol/l) (28) where C CO 3 2- = CO 3 2- concentration C HCO 3- = HCO 3- concentration or as sodium or potassium carbonate and bicarbonate (valid for any weight / volume unit, e.g. kg/m 3, g/l, lbs/bbl): C K 2CO3 (w/vol) = 2.30 C CO3 2- (w/vol) (29) C (w/vol) = 1.64 C KHCO 3 HCO3- (w/vol) (30) C Na 2CO3 (w/vol) = 1.77 C CO3 2- (w/vol) (31) C (w/vol) = 1.38 C NaHCO 3 HCO3- (w/vol) (32) where C K 2CO3 = K 2 CO 3 concentration C KHCO3 = KHCO 3 concentration C Na 2CO3 = Na 2 CO 3 concentration C NaHCO3 = NaHCO 3 concentration When the method is used in the laboratory rather than the field, a more accurate standard titration to ph = 8.2 should be applied, instead of the phenol - phthalein indicator. Equation 12 can be used to calculate the bicarbonate concentration directly in a spreadsheet, rather than determining R from Figure 1. C2.2 Property maintenance and adjustment C2.2.1 Introduction The essential properties of formate drilling fluids that need to be monitored and maintained during use are density, rheology, fluid-loss control, solids content, and buffer concentrations. C2.2.2 Density Rigsite density monitoring The method of measuring density and converting to corrected density is described in Section C The corrected fluid density should be maintained during use to provide the required hydrostatic pressure in the wellbore. PAGE 6 SECTION C2

7 SECTION C: FORMATE FIELD PROCEDURES AND APPLICATIONS CABOT SPECIALTY FLUIDS ph vs. [CO 3 2- ] / [HCO 3- ] molar ratio R = [CO 3 2- ] / [HCO3 - ] ph Figure 1 Relationship between ph and carbonate-to-bicarbonate molar ratio in buffered formate brine. Density increase The weighting agent used for density increases should be determined according to the following guidelines: To increase density due to operational requirements (no water contamination), use spike fluid from the heavier formate salt. To restore density due to water contamination, powdered formate salt should be used if available. For cesium / potassium blends it is economically beneficial to restore the density using both the salts in the same ratio as in the original blend rather than just using cesium formate powder. The volume of water contamination can be calculated as follows: METRIC UNITS V w = (ρ before - ρ after ) where V w V c ρ before ρ after V c ρ before -1 = water contamination volume = fluid volume after contamination = density before contamination = density after contamination The equations are independent of volume units as long as they are consistent. The output unit is the same as the input unit. (33) FIELD UNITS Vw = (ρ before - ρ after ) where V c ρ before Vw = water contamination volume V c = fluid volume after contamination ρ before = density before contamination, lb/gal ρ after = density after contamination, lb/gal The equations are independent of volume units as long as they are consistent. The output unit is the same as the input unit. (34) Example: A formate brine with an original density of 2.0 g/cm 3 is contaminated with water. Density reduces to 1.95 g/cm 3 and total volume after contamination is 100 bbl. The volume of water contamination in bbls can be calculated as: 100 V w (bbl) = ( ) = = 5 bbl For all single-salt brines, the amount of salt required to adjust density should be calculated using Table 15 to Table 20. To calculate the quantity of salt required, convert the volume of water contamination to weight: METRIC UNITS W water (kg) = V water (m 3 ) 999 (35) where W water = weight of water contamination in kg V water = volume of water contamination in m 3 SECTION C2 PAGE 7

8 FIELD UNITS W water (lb) = V water (bbl) 350 (36) where W water = weight of water contamination in lb V water = volume of water contamination in bbl Example: In the example above, the 5 bbl of water has a weight of: W water (lb) = = 1,750 lbs In the appropriate table (Table 15 to Table 20), find the density required in the first column and read off the %wt salt from the second column. The weight of salt required can be calculated as: METRIC AND FIELD UNIT W salt = W water %wt salt %wt salt (37) where W salt = weight of salt required W water = weight of water contamination The equation is independent of weight units as long as they are consistent. The output unit is the same as the input unit. In order to weigh up blended cesium and potassium formate brines, use either pure cesium formate powder or a blend of cesium and potassium formate powder. If pure cesium formate powder is used, the single-salt cesium formate brine table should be used (Table 19 and Table 20). If a blend of cesium and potassium formate powder is used, the cesium / potassium formate blending tables (Table 21 to Table 26) should be used to determine the %wt potassium, %wt cesium, and %wt water required. The weight of each salt required is: W CsFo = W water W KFo = W water %wt CsFo %wt water (38) %wt KFo %wt water (39) Example: For the example used earlier, 5 bbl of water contamination requires salt to restore the density to 2.0 g/cm 3 From Table 21, the amount of cesium formate powder required for a 2.0 g/cm 3 blend is 59.9%wt, the amount of potassium formate powder is 18.7%wt, and the amount of water is 21.4%wt. The amount of cesium formate salt required can be calculated as: W CsFo = 1,750 lbs = 4,898 lbs And the amount of potassium formate salt required as: W KFo = 1,750 lbs = 1,529 lbs Density reduction The choice of fluid for density reduction is quite complex. For single-salt brines, density reduction should be made using water. Lower density formate brines can be used, but for pure cesium formate brine the addition of potassium formate has a significant negative impact on the value of the brine returned. For formate blends, density reduction should be made by adding the spike fluid of the lower density component, for example potassium formate spike fluid should be used to reduce the density of a cesium / potassium formate blend. For logistical reasons, it might be necessary to use water to dilute blended brines. To calculate the quantity of lower density fluid (diluent) required use the following formula: V diluent = V start ( ρ start - ρ required ) ( ρ required - ρ diluent ) where V diluent = diluent volume V start = start volume ρ start = start density ρ required = required density ρ diluent = diluent density (40) The equations are independent of units as long as they are consistent. The output unit is the same as the input unit. Solids Solid weighting agents can be used to increase the density of formate drilling fluids, but in emergency situations only. The presence of solid weighting material not only reduces the value of the returned brine, but it will have a negative impact on the fluid s properties. C2.2.3 Contamination Like all well construction and intervention fluids, formate brines can become contaminated with various soluble and insoluble substances during use. These contaminants should be treated as follows. Calcium and magnesium A formate fluid containing a carbonate / bicarbonate ph buffer system does not contain any soluble calcium or magnesium ions. This is because these ions precipitate out with the buffer and form calcium or magnesium carbonate as soon as they enter the buffered brine. If at any time the buffer is consumed, then free calcium or magnesium ions may be present in the fluid. If calcium or magnesium PAGE 8 SECTION C2

9 SECTION C: FORMATE FIELD PROCEDURES AND APPLICATIONS CABOT SPECIALTY FLUIDS is measured in a buffered formate fluid, then this is a sure sign that the buffer has been consumed. Calcium or magnesium contaminants should be removed and buffer level restored with the addition of new buffer. The addition of potassium or sodium carbonate precipitates out calcium or magnesium as calcium or magnesium carbonate and buffer levels are restored. Cement contamination If a formate fluid gets contaminated with cement, the buffer might be consumed by precipitation of calcium carbonate. As cement contamination also causes ph to rise, cement contamination is best treated with potassium or sodium bicarbonate. This precipitates out calcium as calcium carbonate and at the same time restores ph. Solids contamination Over time, formate fluids pick up solid contaminants. For brine operations, solids should be removed using conventional filtration. Formate drilling fluids normally provide excellent hole cleaning, efficiently removing drilled cuttings from the hole. The low solids and shear thinning properties of formate drilling fluids enables solids control equipment to be run very efficiently. Very fine shaker screens should be run, once the mud has warmed and the polymers are fully hydrated. However, fine shaker screens usually have a relatively low life expectancy so they need to be monitored very closely in order to detect and repair tears. Centrifuges can be very effective at removing drill solids and should be run if available, although the discharge must be monitored closely to ensure it is dry. The dump and dilute method can also be used to control drill solids, but any cesium formate-based brines and possibly potassium formate-based brines should be returned to the plant for reclamation and must not be discharged. C2.2.4 ph maintenance In a formate fluid buffered with carbonate / bicarbonate, ph is dependent on the state of the buffer. More specifically, ph is dependent on the carbonate-to-bicarbonate ratio as shown in Figure 1. Therefore, if ph changes in the fluid, this is a sign that the carbonate and bicarbonate concentrations are changing, so levels of carbonate and bicarbonate would need to be measured. Treatment with acid or hydroxide to adjust ph should not be conducted unless this is the treatment that is recommended in order to maintain carbonate / bicarbonate concentrations (see C2.2.5). C2.2.5 Carbonate / bicarbonate (buffer) maintenance Carbonate and bicarbonate forms part of the buffering system used in formate fluids and should always be present in significant quantities if influxes of acid gas are expected while the formate brine is static in the hole for extended periods. (See Section A6 ph and Buffering and C2.1.7.) During field use, one normally experiences that the carbonate concentration (buffer capacity) reduces during use whilst the bicarbonate concentration either increases or decreases. The following downhole events can impact on buffer concentrations: Influx of CO 2 gas The consequences of this event are that the carbonate concentration decreases whilst the bicarbonate concentration increases (the increase in bicarbonate concentration equals twice the decrease of the carbonate concentration). The first sign of this is a drop in ph. Another sign is that a relatively large amount of treatment with carbonate is required to restore ph. Influx of divalent ions (e.g. Ca 2+ or Mg 2+ ) The consequences of this event are that both carbonate and bicarbonate levels decrease. The whole buffer could be consumed. The first sign of such an influx is a fast fall in ph after it has been restored with carbonate. After such events, in order to restore buffer capacity and ph, CSF normally recommends adding more potassium or sodium carbonate. One should be aware, however, that the addition of carbonate to restore buffer capacity after significant influxes of acid gas could lead to a build-up of the bicarbonate concentration over time, which could have an adverse effect on certain polymers (e.g. PAC and xanthan), resulting in high fluid loss, excessive rheology, or gelling problems. If this is suspected, pilot testing should be conducted with potassium or sodium hydroxide additions instead of potassium or sodium carbonate additions. Such hydroxide additions restore the carbonate level (buffer capacity) by converting bicarbonate to carbonate, simultaneously as bicarbonate concentration lowers. It is imperative that excessive potassium or sodium hydroxide additions are avoided because such hydroxide additions can have an adverse effect on polymers in the fluid. The plot shown in Figure 2 can be useful in determining the amount of carbonate and bicarbonate additions required to maintain programmed buffer levels and ph in buffered formate brines. SECTION C2 PAGE 9

10 ph vs [CO 3 2- ] / [HCO 3- ] molar ratio [CO 3 2- ] / [HCO 3- ] (mol / mol) C / C K2CO3 (wt / wt) KHCO3 C / C Na2CO3 (wt / wt) NaHCO3 R = C CO3 2- / C HCO ph Figure 2 Relationship between ph and carbonate-to-bicarbonate molar ratio (red line), potassium carbonate-to-potassium bicarbonate weight ratio (dark blue line) and sodium carbonate-to-sodium bicarbonate weight ratio (light blue line) in buffered formate brines. C2.2.6 Calcium carbonate maintenance In formate drilling fluids, graded CaCO 3 is often added to help improve filter cake quality and control fluid loss. Due to the low solids content, formate fluid systems have a much improved rheology and reduced ECD compared to solids-weighted systems. The carefully sized calcium carbonate bridging particles are designed to seal permeable formations, providing a means to reduce or even eliminate seepage losses to the reservoir. Lower ECDs reduce seepage losses without having to reduce pump rate or ROP. However, the product also acts as a weighting agent and this must be allowed for and included in density adjustment calculations for the circulating system and for pre-mixes whenever these additions are made. The level of CaCO 3 may also require adjustment after shearing, once the properties have stabilized. Screens as fine as 250 mesh are likely to be run during formate drilling operations, so regular monitoring of CaCO 3 levels is required and additions have to be made to the system via suitably treated active mud or premix additions to replace larger CaCO 3 particles screened out at the shakers. C2.2.7 Polymer maintenance Due to the extra temperature and shear conditions required to provide effective yield of polymers in formate brines, formate fluids delivered to the rig site are thinner and exhibit higher initial fluid loss than programmed. The system must be allowed to circulate for several hours before assessing the true level of viscosity and fluid loss, prior to making any adjustments with suitably treated pre-mix additions. Remember, there is a significant time delay between adding the polymers and realizing the full effect on fluid properties. 1. Polymers should be added to the formate fluids slowly through a high shear hopper to facilitate mixing and to prevent the formation of fisheyes. 2. A reduced quantity of polymers should be added to the initial mix to prevent blinding of the shakers on the initial circulation. The additional polymers can then be added gradually over the first few circulations. 3. Fine shaker screens should not be used before the polymers are properly hydrated. C2.3 Performance enhancement and problem solving C2.3.1 ROP enhancement In HPHT wells, ROP is normally limited by well control procedures (see Section C3 Drilling Fluid Applications). However, in very hard rock formations this is not the case. ROPs achieved with formate drilling fluids are often substantially higher than with conventional mud systems. The reasons for this are PAGE 10 SECTION C2

11 SECTION C: FORMATE FIELD PROCEDURES AND APPLICATIONS CABOT SPECIALTY FLUIDS the low level of solids in the system. Maintaining a low-solids level has two main effects. 1. The higher spurt loss of the low-solids system equalizes the pressure around cutting, effectively reducing the chip hold-down pressure. 2. The reduced ECD is beneficial for reducing the risk of losses and improving flow rates for turbine power and hole cleaning. For ROP, this reduced overbalance reduces rock strength and improves ROP. In the BP Devenick offset core, rock strength increases dramatically with small increases in confinement pressure. For Devenick, the expected pressures were 700 psi for cesium formate and 1,000 psi for OBM. In order to maximize ROP it is recommended to allow the fluid spurt loss to run quite high as long as the filter cakes are thin. It is beneficial to maintain a low rheology to maximize pump rates and thereby maximize turbine or motor power. Minimizing ECD reduces confinement pressures and therefore rock strength. C2.3.2 Hole cleaning and hydraulics Formate drilling fluids usually exhibit lower ECDs and gel strengths than conventional drilling fluids. Low ECDs mean that higher pump rates are possible, which is critical for effective hole cleaning. Field experience has confirmed this. If hole cleaning problems are suspected, a high-vis pill should be pumped and the shakers monitored for increased cuttings returns. PresMod software from ScanPower can be used to predict fluid hydraulics using the specialized Cabot formate fluids models. C2.3.3 Fluid loss, rheology, and gelling problems Occasionally fluid loss, rheology, and gelling problems have been experienced after extensive treatments with potassium or sodium carbonate in order to restore buffer capacity and ph after influx of CO 2 gas [4]. As mentioned in C2.2.5, the build-up of bicarbonate in the fluid can have an adverse effect on certain polymers (e.g. PAC, xanthan), which could lead to high fluid loss, excessive rheology, and gelling problems. It is imperative that excessive amounts of potassium or sodium hydroxide are not added. Care should also be taken as hydroxide additions can cause damage to polymers in the fluid. C2.3.4 Foaming A supply of defoamer should be stocked in the unlikely event of foaming in the pits, which could present difficulties when monitoring active circulating volume. For suitable defoamers, see Section B5 Compatibility with Additives. C2.3.5 Erratic gas readings Electronic gas detectors are often installed on the rig to monitor hydrogen sulfide (H 2 S) and carbon monoxide (CO). In several cases, false alarms have been reported on this kind of equipment with formate use. In high temperature wells, a small amount of hydrogen gas might be produced as a product of formate decomposition. This is normal, and not a concern in itself. One should be aware, however, that hydrogen gas might set off the alarm on both H 2 S detectors and CO detectors. Before relying on such detectors to measure H 2 S and CO it is important to check with the manufacturer of the instruments whether or not they are sensitive to hydrogen gas. References [1] API RP 13J: Recommended Practice for Testing Heavy Brines. [2] API RP 13B-1: Standard Procedures for Field Testing Water-Based Drilling Fluids. [3] IDF: Technical Manual for Drilling, Completion and Workover Fluid Technology. [4] Berg, P.C., Pedersen, E.S., Lauritsen, Behjat, N., Hagerup-Jenssen, S., Howard, S., Olsvik, G., Downs, J.D., Harris, M., Turner, J.: Drilling, Completion, and Openhole Formation Evaluation of High-Angle Wells in High-Density Cesium Formate Brine: The Kvitebjørn Experience, , SPE , February If this is suspected, pilot testing should be conducted with potassium or sodium hydroxide additions instead of potassium or sodium carbonate additions. Such a hydroxide addition restores the carbonate level (buffer capacity) by converting bicarbonate to carbonate and simultaneously lowers bicarbonate concentration. SECTION C2 PAGE 11

12 Table 3 Metric density correction table for temperatures 10 to 25 C and density 1.0 to 1.4 g/cm 3. The corrections are valid for diluted potassium formate brine. Temperature correction table cesium / potassium formate brine blend showing corrected temperature at 15.6 C Measured Measured fluid temperature [ C] g/cm PAGE 12 SECTION C2

13 SECTION C: FORMATE FIELD PROCEDURES AND APPLICATIONS CABOT SPECIALTY FLUIDS Table 4 Metric density correction table for temperatures 25 to 40 C and density 1.0 to 1.4 g/cm 3. The corrections are valid for diluted potassium formate brine. Temperature correction table cesium / potassium formate brine blend showing corrected temperature at 15.6 C Measured Measured fluid temperature [ C] g/cm SECTION C2 PAGE 13