Reservoir Formation Damage Episode 3 Part 2 pptx

Laboratory Evaluation of Formation Damage 507 Table 15-3 Reactions of Aux Vases Sandstone Minerals with Well Fluids* Mineral Quartz K-feldspar Na-feldspar Illite Mixed-layered illite/smectite Chlorite Calcite Fe-dolomite Anatase Barite-celestite Solid H-carbon Pyrite Exposure to fluids Low Low to med Low to med High High High Low to high Low Low Low Low to med Low Solubility in 15%HCI Insoluble Low Insoluble Low Low Low Low to med High High Insoluble Insoluble Med Insoluble Chemical composition SiOa K(AISi3Os) Na(AISiaO8) (Fe,Mg)KxAl2(Si 4 -x,Alx)Oio(OH)2 (Fe,Mg)K x Al2(Si4- x ,Al x )Oio(OH)2 (V4Ca,Na)-7(AI,Mg,Fe)4 - (Si,AI)sO20(OH)4-nH2O (Mg,Fe)5(AI,Fe)(AI,Si 3 Oio)(OH) 8 CaCOa (Ca,Mg,Fe)COa TiOa (Ba,Sr)SO4 C,OH,H,S,N Fe 2 S Released None K^X 3 ,^ None K +1 ,AI +3 ,Si +4 K +1 ,AI +3 ,Si +4 Ca +2 ,Na +1 ,Fe +2 ,Mg +2 ,Al t3 ,Si +4 Ca +2 ,COa" Mg +2 ,Fe +2 ,Ca +2 ,C0 3 ' None None C^.S* 4 None * Adapted from Pfot and Pertuis (1989). After Haggerty and Seyler, 1997; reprinted by permission of the Illinois State Geological Survey. minerals and the permeability of Aux Vases reservoir rocks by conducting dynamic, constant rate injection coreflood experiments; 2. Investigate how 15% HCL and MCA affects crude oil from Aux Vases reservoirs by conducting compatibility experiments; 3. Examine how exposure to fluids of various salinities affects permeability in samples of Aux Vases reservoirs by conducting coreflood experiments; 4. Investigate the effects of long-term contact of 15% HCL and MCA with pore-lining minerals in reservoir samples by conduct- ing static soak experiments; 5. Compare XRD analyses of the bulk mineralogy and SEM/EDX analyses of pore-lining minerals with flood results to identify minerals that would be most affected by fluids commonly used during drilling, completion, and stimulation of Aux Vases reservoirs. Therefore, Haggerty and Seyler (1997) carried out five sets of bench experiments, with the specific objectives described in Table 15-4. The direct contact experiments have been conducted to determine the effect of the acids on the physical properties of crude oil. In the coreflood tests, they continuously injected excessive amounts (25 to 50 pore volumes) of fluid during coreflood experiments. Therefore, Haggerty and Seyler (1997) state that their coreflood experiments most closely represent the 508 Reservoir Formation Damage Table 15-4 Experimental Overview Type of experiment Direct contact: crude oil and acids Coreflood: continuous injection at a constant rate Coreflood: interrupted injection, constant rate Core waterflood: interrupted injection, constant rate Acid soak Fluids Crude oils MCA MCA 15%HCI MCA MCA Waters, various salinities 15%HCI MCA Field, well Boyd, Baldridge B5 Bizot Dale, Farrar 2 McCullum Community Energy, Budmark 2 Morgan Coal Zeigler, Gallagher Drilling 1 Alex Energy, Budmark 2 Morgan Coal Zeigler, Gallagher Drilling 2 Mack Energy, Budmark 2 Morgan Coal Dale Cons, Farrar 1 McCreery Energy, Budmark 2 Morgan Coal Boyd, Superior Oil 9 Sanders Energy, Budmark 2 Morgan Coal Energy, Budmark 2 Morgan Coal Zeigler, Gallagher Drilling 2 Mack Dale Cons., Farrar 1 McCreery Energy, Budmark 2 Morgan Coal Energy, Budmark 2 Morgan Coal Energy, Budmark 2 Morgan Coal Depth ft 2,170 3,158-3,176 2,385-2,395 2,615-2,630 2,392.1 2,627 2,393.5 3,198.7 2,391.1 2,163 2,390 2,388 2,611 3,200.6 2,388.3 2,392.8 2,393 To determine Compatibility of 15%HCIvsMCA Effects on permeability and pore-lining minerals Effects of interrupting injection and soaking sample in MCA; simulates potential damage after injection and before swabbing Sensitivity of rock to injected water of varying salinities; note permeability changes Long-term reaction of reservoir rock to MCA and15%HCI After Haggerty and Seyler, 1997; reprinted by permission of the Illinois State Geological Survey. completely flushed reservoir zones and, under these conditions, the precipitates cannot deposit and cause formation damage in porous media, within the time scale of the convective flow. The acid soak experiments served for the purpose of observing the long-term effects of reactions in unflushed and incompletely flushed zones. Description and Preparation of Materials Core Plugs. Table 15-5 shows the sources and available data of the Aux Vases reservoir core samples used by Haggerty and Seyler (1997). One- inch-diameter (2.54 cm) core plugs were extracted out of 4-inch-diameter Laboratory Evaluation of Formation Damage 509 Table 15-5 Samples Used for the Experiments and Methods Used to Describe Them Field, well and well ID Energy 2 Morgan Coal 1219923465 Dale 1 McCreery 1205523456 Zeigler 2 Mack 1205523750 Boyd 9 Sanders 1208102628 Depth ft 2,393.5 2,388.3 2,391.1 2,390 2,388 2,393 2,392.8 3,198.7 3,200.6 2,611 2,627 2,163 SEM/EDX Yes Yes Yes No No Yes Yes Yes No Yes Yes No XRD No Yes No Yes No No Yes No No Yes Yes No Thin section No Yes No Yes No No Yes Yes No Yes Yes No After Haggerty and Seyler, 1997; reprinted by permission of the Illinois State Geological Survey. whole cores with maximum possible lengths permitted by drilling. In the coreflood experiments, they used core plugs of 1-inch (2.54 cm) to 2.5-inch (6.35 cm) long. In the MCA and HCL soak experiments, they used 1-inch-diameter (2.54 cm) and 0.25-inch-thick (0.635 cm) core plug wafers. Fluids. Halliburton, Inc. provided the MCA solution containing "15% HCL in a proprietary formulation of surfactants, suspending agents, anti- sludge agents, clay mineral stabilizers, iron-sequestering agents, and corrosion inhibitors," as stated by Haggerty and Seyler (1997). The characteristics of the waters used by Haggerty and Seyler (1997) are described in Table 15-6. The Aux Vases formation brine was obtained from the Budmark No. 3 Morgan Coal lease in Energy Field, filtered, and then used in coreflood tests with a 13.7% TDS (total dissolved solids) content. A fresh water mixture containing 1.2% TDS and its mixtures with the formation brine at various proportions, as described in Table 15-6, were synthetically prepared and used in the coreflood tests. Haggerty and Seyler (1997) measured the resistivities of these mixtures and then 510 Reservoir Formation Damage Table 15-6 Characteristics of Water Mixtures Type Formation brine Supply water 95%(1)-5%' 90%(1)-10% 75%(1)-25% 50%(1)-50% Ionic composition meq/l Ca 2+ Na + Ba 2 " 1 " Fe 3+ Mg 2+ C\~ SO4 2 " HCO 3 ~ pH 341 1883 0.0 0.4 173 2394 1.0 1.7 6.1 16 14 0.1 0.0 13 28.2 13.5 1.5 5.3 Rw Q-m 0.063 0.433 0.064 0.068 0.076 0.124 IDS % 13.7 1.2 13.5 12.4 10.5 5.95 * 95% (by volume) of formation brine and 5% (by volume) of the supply water, meq/l = mole wt/charge per liter After Haggerty and Seyler, 1997; reprinted by permission of the Illinois State Geological Survey. estimated their TDS using the TDS-resistivity correlation developed by Demir (1995): TDS(ppm) = 6,786.09 (15-8) where R» denotes the resistivity of water in £2-m and T denotes the water temperature in °F. Equipment Haggerty and Seyler (1997) performed their coreflood tests using a TEMCO™ integrated coreflood apparatus. This system is described schematically in Figure 15-29. A conventional Hassler-type coreholder is placed in an oven for temperature control. The core is placed inside a rubber sleeve between metal end pieces. Spacers are attached to adjust for different core lengths. The space between the coreholder and rubber sleeve is filled with a pressurized hydraulic fluid. A confining pressure pump and gauge system applies pressure to the rubber sleeve containing the core sample. The confining pressure applied over the core plugs prevents the bypassing of the injected fluids around core plugs and the mixing of the injected and hydraulic fluids. The coreholder is connected to oil and water reservoirs and the oil and water recycling cylinders. The coreholder is equipped with an inlet pressure transducer and gauge and a back pressure regulator and gauge. The other auxiliary equipment Laboratory Evaluation of Formation Damage 511 H V2C V2 hi j JLJM ,. r-n-i I-TT-I 4, V25 • L _ _. »4 1 V27 V26* ~ V23 V22 31 32 5 13 » I I r 1 r<V2B V29 V30, 3 H 1 •»••.»! V3ll r 1 - 4 I i . " V9 f*i BT 1 ^— t_j j-^- f 19 18 1 1 1 r— f>-20 -f20 r«, hMi ^-€>7 V12 IJ^l^ C±D 97 I— O^ 16 XUrXr- ~tlin ^ V8 M I f^_ 7 « visCjTl TLJ vtT>^P V3 , V4 ^ * «a , 26 - jBj oven cabinet control panel cabinet 1 oil rodded cylinder 22 vent line V12 vacuum valve 2 water rodded cylinder 23 back pressure regulator V13 positive transducer valve 3 core holder 24 effluent collection burette V14 negative transducer valve 4 confining pressure fluid-in line 25 wet test meter V15 rodded cylinder drain valve 5 confining pressure release line 26 rotameters V16 dear cylinder fill valve, oil-base 6 confining pressure pump 27 back pressure regulator bleed V17 dear cylinder HI valve, water-base 7 pressure gauge 28 back pressure regulator nline V18 BPR outlet valve 8 injection fluid to core line 29 back pressure regulator equilibrium ine V19 effluent outlet valve 9 differential pressure transducer 30 external BPR port V20 rodded cylinder Intel valve, oil-base 0 micro pump fluid reservoir V21 rodded cylinder outlet valve, oil-base 1 injection fluid micro pump, oil-base V1 confining pressure valve V22 forward flow core inlet valve, oil-base 2 injection fluid micro pump, water-base V2 BPR in valve V23 reverse (low core inlet valve, oil-base 3 reverse flow Hne V3 BPR equilibrium valve V24 rodded cylinder inlet valve, water-base 4 vacuum vapor trap V4 BPR release valve V25 rodded cylinder outlet valve, water-base 5 external oil clear cylinder V5 BPR monitoring valve V26 forward flow core inlet valve, water-base 8 external water dear cylinder V6 air pressure regulator valve V27 reverse flow core inlet valve, water-base 7 input fluid filters V7 BPR release regulator valve V28 confining fluid purge valve 8 input transfer ine, oil-base V8 zero transducer valve V29 reverse flow control valve ) input transfer Ine, water-base V9 rodded cylinder utility valve V30 forward flow outlet valve 0 vacuum Ine V10 vent valve V31 reverse flow outlet valve 1 air pressure Ine V11 air valve Figure 15-29. Temco integrated coreflood apparatus (after Haggerty and Seyler, 1997; reprinted by permission of the Illinois State Geological Survey). includes a nitrogen gas cylinder, rotameters, pressure valves, and a wet test meter (Oil and Gas Section—ISGS, 1993). Coreflood Tests Haggerty and Seyler (1997) report that the core plugs were cleaned in a CO 2 /solvent core cleaner and vacuum-dried. Then the porosity and permeability to nitrogen gas were measured. The baseline liquid permeability was measured by injecting 1.5 cm 3 /min brine continuously into the core plugs. They determined the 1.5 cm 3 /min rate by scaling the typical reservoir fluid velocity of 14 ft/day and 68.6 bbl/day in a 10-feet- thick pay zone, using the scaling coefficient of unity (LV\i w = 1) for 65% 512 Reservoir Formation Damage oil recovery at water breakthrough (Kyte and Rapoport, 1958; Delclaud, 1991). This corresponds to 0.296 cm/min or 1.5 cc/min flow through 1-inch- diameter core plugs. They measured the pressure difference between the inlet and outlet of the core plugs and calculated the effective liquid permeability of the core plugs using Darcy's law. Haggerty and Seyler (1997) estimated the overburden pressure of the Aux Vases formations located at 2,100 to 3,200-ft depths to be in the range of 2,100 to 3,200 psi by assuming a gradient of 1 psi/ft for typical sedimentary basins (Leverson, 1967). Assuming the reservoir fluid is normally pressured and using a hydrostatic pore pressure gradient of 0.45 psi/ft, they estimated the pore fluid pressure to be 1,200 psi. The bottom hole temperatures of wells in the Aux Vases formations vary from 75° to 98°F (24° to 36°C). However, they performed the coreflood tests at 1,000 psig (6,895 KPa) confining pressure and 75°F (24°C) temperature. They assumed that the effects of the differences between the test and field conditions are negligible based on the arguments by Amyx et al. (1960) and Eickmeier and Ramey (1970). They conducted the flow tests at constant injection rates. The pressure difference across the core plugs typically varied between 10-50 psi (69.8-345 KPa) for injection at a 14 ft/day rate. A 50-75 psi (345-517 KPa) back pressure was sufficient to maintain single phase and avoid CO 2 gas bubbles. As stated by Haggerty and Seyler (1997) tests conducted using core plugs have certain, inherent limitations: 1. Their small size represents a very small percentage of the total reservoir; therefore the entire range of effects that introduced fluid may have on reservoir behavior cannot be fully determined, and 2. Each experiment represents a discrete phase of the drilling, com- pletion, or stimulation process. However, coreflood tests conducted at near in-situ conditions can help explain the reactions between pore-lining minerals and extraneous fluids introduced by drilling, completion and stimulation operations (Haggerty and Seyler, 1997). Then, the cumulative effects of the rock- fluid interactions on formation damage can be determined by simulation or other means. Experimental Results Haggerty and Seyler (1997) conducted a number of tests with 15% HCL and 15% HCL-MCA to determine the effect of the clay stabilizing agents present in the mud cleaning acid (MCP) provided by Halliburton, Inc. Laboratory Evaluation of Formation Damage 513 Calcite Dissolution with the MCA. The HCL in the MCA dissolves calcite by the reaction: + 2HCI -> CO 2(g} CaCl 2 + H 2 O (15-9) The produced carbon dioxide (CO 2 ) gas dissolves in the aqueous phase at elevated pressures, but separates as the effluent solution comes out of the core. Haggerty and Seyler (1997) conducted four types of tests. These tests and their results are summarized in the following. Coreflood Tests with MCA. They conducted interrupted and continuous acid corefloods using a 15% HCL-MCA on samples described in Tables 15-3 and 15-4. They injected ten pore volumes of the acid solution into the core plugs for complete flushing of the cores to simulate the total flushing of the near-wellbore formation during acid stimulation. The primary objective of the interrupted corefloods was to investigate the effects of the MCA solution on the formation without the presence of other reservoir fluids (i.e., oil and brine). Therefore, Haggerty and Seyler (1997) injected MCA into a dry core sample. The acid injection was interrupted at certain time intervals and the permeability of the core was measured. Figures 15-30 and 15-31 show the measured permea- bilities of two different core plugs. The acid dissolved the calcite cement and permeability increased. Although some fine particles may have been unleashed by calcite dissolution, damage by fine particles migration and deposition was not observed because the fine particles were flushed out of the core plugs by an excessive amount of acid injection (ten pore volumes). In fact, after 24 hours of exposure, Haggerty and Seyler (1997) detected fine-grained sand, silt-sized grains of nonclay minerals, and diagenetic clay particles in the effluent. The continuous acid corefloods were conducted to simulate the flushing of the near wellbore formation in the presence of formation fluids. For this purpose, the cores were restored to their reservoir conditions by a series of displacement processes. First, the cores were saturated with brine, the brine was displaced by oil up to irreducible water saturation, and the cores were allowed to establish oil-water equilibrium by soaking them in oil for 48 hours. The oil present in the cores, prepared in this way, was displaced with brine and then MCA was injected to displace the brine and effective permeabilities were measured during continuous acid injection. As indicated in Figure 15-32 by Haggerty and Seyler (1997), the permeability first decreased rapidly and then increased continuously. Haggerty and Seyler (1997) attribute the initial decreasing of permeability to carbon dioxide (CO 2 ) gas production. 514 Reservoir Formation Damage K (brine before MCA treatment) = 27.5 md 5 .2 ^ 0 A-B 1 -hr soak and flow B-C no MCA flow C-D no MCA flow 10 20 30 40 50 60 MCA contact time (hrs) 70 80 Figure 15-30. An interrupted, constant flow rate, acid coreflood exposed a core plug (3,198.7-ft depth, Farrar 1 McCreery, Dale Cons. Field) to MCA for 74 hours. Permeability increased with MCA-rock contact time as calcite cement dissolved, disloging some fine grains that were flushed out of the core sample (after Haggerty and Seyler, 1997; reprinted by permission of the Illinois State Geological Survey). Z? 2 1 -E o A gas phase reduces permeablity B inception of mobBe COz phase B-C continuous acid flow C-D no acid flow D acid flow ' D-E no acid flow | E acid flow 10 15 20 25 Rock/MCA contact time (hrs) 30 35 Figure 15-31. Permeability changes during a 30-hour, interrupted, constant flow rate (1.5 cm 3 /min) coreflood test using a 1-inch-diameter core plug (2,392.1-ft depth, Budmark 2 Morgan Coal, Energy Field). Permeability increased with MCA-rock sample contact (no flow) and flow times. The increase is more pronounced in the McCreery core plug (Figure 15-30) because of the dissolution of large amounts of calcite cement aligned along crossbedding laminae; the Budmark 2 Morgan Coal sample did not have as much calcite cement (after Haggerty and Seyler, 1997; reprinted by per- mission of the Illinois State Geological Survey). Laboratory Evaluation of Formation Damage 515 o A-B gas phase reduces permeability B inception of mobile gas phase A-C continuous acid flow 234 Rock/MCA contact time (hrs) Figure 15-32. Permeability of a sample (2,627.5-ft depth, Gallagher Drilling Co. 2 Mack, Zeigler Field) varied significantly during a 4.5-hour continuous, constant rate coreflood test using MCA (after Haggerty and Seyler, 1997; reprinted by permission of the Illinois State Geological Survey). Figures 15-33a and b are the photomicrograph and SEM photomicro- graph, respectively, of a thin section taken from a core plug exposed to MCA for 75 hours. These photomicrographs clearly show that calcite cement was dissolved and the pores were enlarged. Calcite Dissolution in MCA Soak Tests. The MCA soak tests were conducted statically (without flow) at ambient room conditions to observe the effect of acid on pore-lining minerals. These tests determine the effect of the acid remaining in locations far away from the well bore after acid stimulation. Figures 15-27a and 15-26 by Haggerty and Seyler (1997) show that untreated core samples are loosely cemented and friable sandstone with grains coated with diagenetic clay minerals. Figure 15-27c shows pores filled with patchy calcite cement in an untreated sample. Figures 15-27c and d show the pores of 30 minute acid-treated cores. Comparison of Figure 15-27a to Figure 15-27b and Figures 15-27c to Figure 15-27d indicate that some crystals and patches of calcite cement were partially dissolved after 30 minutes, but the diagenetic clay minerals were not affected. Haggerty and Seyler (1997) attribute this to the function of clay- stabilizing additives present in the MCA. Coreflood Tests With 15% HCL without Additives. In order to determine the effect of acid treatment without the clay stabilizers, Haggerty and 516 Reservoir Formation Damage (a) (b) Figure 15-33. (a) Photomicrograph of a thin section made from the core plug after 74 hours of exposure to MCA shows that coarse grained laminae, filled with calcite cement prior to the coreflood, developed a channelized pore system due to total dissolution of calcite cement along the laminae. As a result, large oversize pores formed (arrow); (b) SEM photomicrograph of the same sample after coreflood also shows enlarged pores (arrow) and diagenetic clay minerals coating siliciclastic framework grains. The framework grains have bimodal size distribution and are either very fine grained (100 ^im) or medium grained at 250 p,m or greater (after Haggerty and Seyler, 1997; reprinted by permission of the Illinois State Geological Survey). [...]... 518 Reservoir Formation Damage Table 15-7 Composition of Effluent from HCI Coreflow: Energy Field Sample, 2 ,39 2. 6-foot depth, Budmark 2 Morgan Coal Well mg/l Effluent sampled at 1 hour 2 hours 2 days Al As B Ba Be Ca 825 0 1550 31 30 26 .5 25 0 56.4 0 .2 1 1 0 .26 0.11 0.1 2. 18 0.68 0. 83 0.004 001 0.0 02 Cd Co Cr Cu Fe 1 hour 2 hours 2 days 0.04 0.46 0.40 0.46 0 .34 K La Li 1 hour 2 hours 2 days 9 7 6 0. 52 0.19... 15 -38 15 -38 15 -31 and 32 15 -34 Crude oil/1 5% HCI Crude oil/MCA Continuous corefloods with MCA Continuous coreflood with HCI Discontinous coreflood with MCA HCI soak MCA soak 15 -30 15 -35 a-d 15 -27 band15 -27 d Water sensitivity Gradual increase in freshwater Boyd (2, 1 63- ftdepth) Energy (2 ,38 8-ft depth) Energy (2, 190-ft depth) Dale (3, 20 0.6-ft depth) Zeigler (2, 61 1-tt depth) 15 -36 15 -37 15 -37 15 -37 15 -37 ... 1 hour 2 hours 2 days 9 7 6 0. 52 0.19 0 .28 0.19 0.47 0. 12 1 hour 2 hours 2 days 895 168 154 01 Na Sr 1 hour 2 hours 2 days 17.1 1. 63 2 .35 Ni 131 57.4 49.4 Ti 0.10 0. 13 0.11 8.1 11.1 15.1 Li 08 0.14 0.04 TI 1 1 1 19.4 10.6 9 .21 Mg 92. 6 177 48.5 109 409 158 Mn Mo 15.4 4.09 7.49 40.8 21 .2 15.4 Mg Mn Mo 0.010 0.009 0. 022 1 1 1 17.8 15.7 19 .2 V Zn Zr 0. 02 0.70 0 .20 1.64 1.74 0.80 0.07 0.07 0.10 After Haggerty... Really Eliminate Formation Damage? ," SPE 2 735 2 paper, SPE Formation Damage Control Symposium, February 1994, Lafayette, LA Cernansky, A., & Siroky, R., "Deep-bed Filtration on Filament Layers on Particle polydispersed in Liquids," Int Chem Eng., Vol 25 , No 2, 1985, pp 36 4 -37 5 Civan, F., "A Generalized Model for Formation Damage by Rock-Fluid Interactions and Particulate Processes," SPE 21 1 83 paper, SPE... Comparison of the Formation Damage Models," SPE 23 7 87 paper, SPE International Symposium on Formation Damage Control, February 26 -27 , 19 92, Lafayette, Louisiana, pp 21 9- 23 6 Civan, F, Predictability of Formation Damage: An Assessment Study and Generalized Models, Final Report, U.S DOE Contract No DE-AC 229 0-BC14658, April 1994 Civan, F., "A Multi-Phase Mud Filtrate Invasion and Well Bore Filter Cake Formation. .. Petroleum Engineers, Vol 2 13, 1958, pp 4 23 - 426 Levorsen, A I., Geology of Petroleum (2nd ed.), W.H Freeman & Company, 1967, San Francisco, California, 409 p Marshall, D S., Gray, R., & Byrne, M., "Development of a Recommended Practice for Formation Damage Testing," SPE 38 154 paper, SPE European Formation Damage Conference, June 2 -3, 1997, The Hague, The Netherlands, pp 1 03- 1 13 Masikevich, J., & Bennion,... without any additives formed an emulsified sludge with 522 Reservoir Formation Damage 100 10- Injecting i A formation water ( 13% IDS) B fresh water (1 -2% IDS) ' C 50% fresh water + 50% formation water D 25 % fresh water + 75% formation water E 10% fresh water + 90% formation water F 100% de-ionized water (no TDS) 1 3 4 Injection water Figure 15 -37 Changes in permeability of core plugs tested with water... Meet Reservoir Issues —A Process," / Canadian Petroleum Technology, Vol 38 , No 5, May 1999, pp 61-71 Miranda, R M., & Underdown, D R., "Laboratory Measurement of Critical Rate: A Novel Approach for Quantifying Fines Migration Problems," SPE 25 4 32 paper, SPE Production Operations Symposium, March 21 - 23 , 19 93, Oklahoma City, Oklahoma, pp 27 1 -28 6 Mungan, N., "Discussion of An Overview of Formation Damage, "... Filtrate Invasion and Well Bore Filter Cake Formation Model," SPE 28 709 paper, SPE International Petroleum Conference & Exhibition of Mexico, October 10- 13, 1994, Veracruz, Mexico, pp 39 9-4 12 Civan, F., "A Multi-Purpose Formation Damage Model," SPE 31 101 paper, SPE Formation Damage Symposium, Lafayette, Louisiana, February 14-15, 1996, pp 31 1 - 32 6 Delclaud, J., "Laboratory Measurement of the Residual Gas... makers References Amaefule, J Formation Operations Amaefule, J "Advances O., Ajufo, A., Peterson, E., & Durst, K., "Understanding Damage Processes," SPE 16 23 2 paper, SPE Production Symposium, Oklahoma City, Oklahoma, 1987 O., Kersey, D G., Norman, D L., & Shannon, P M., in Formation Damage Assessment and Control Strategies," Laboratory Evaluation of Formation Damage 5 23 Figure 15 -38 (a) Emulsified sludge . ID Energy 2 Morgan Coal 121 99 23 4 65 Dale 1 McCreery 120 55 23 4 56 Zeigler 2 Mack 120 55 23 7 50 Boyd 9 Sanders 120 81 026 28 Depth ft 2 ,39 3.5 2 ,38 8 .3 2 ,39 1.1 2 ,39 0 2 ,38 8 2 ,39 3 2 ,39 2. 8 3, 198.7 3, 20 0.6 2, 611 2, 627 2, 1 63 SEM/EDX Yes Yes Yes No No Yes Yes Yes No Yes Yes No XRD No Yes No Yes No No Yes No No Yes Yes No Thin section No Yes No Yes No No Yes Yes No Yes Yes No After . Budmark 2 Morgan Coal Energy, Budmark 2 Morgan Coal Energy, Budmark 2 Morgan Coal Depth ft 2, 170 3, 158 -3, 176 2 ,38 5 -2 ,39 5 2, 615 -2, 630 2 ,39 2. 1 2, 627 2 ,39 3.5 3, 198.7 2 ,39 1.1 2, 1 63 2 ,39 0 2 ,38 8 2, 611 3, 20 0.6 2 ,38 8 .3 2 ,39 2. 8 2 ,39 3 To . Evaluation of Formation Damage 511 H V2C V2 hi j JLJM ,. r-n-i I-TT-I 4, V25 • L _ _. »4 1 V27 V26* ~ V 23 V 22 31 32 5 13 » I I r 1 r<V2B V29 V30, 3 H 1 •»••.»! V3ll r 1 - 4