Reservoir Formation Damage Episode 3 Part 1 pps

482 Reservoir Formation Damage where p c denotes the capillary pressure necessary for water retention, a is the surface tension between water and hydrocarbon, 0 is the contact angle between the water and hydrocarbon, and r is the pore radius. Eq. 15-1 indicates that water retention can be reduced by workover schemes reducing the surface tension and/or increasing the contact angle to favor a less water-wet condition. The Mud Damage Problem Keelan and Koepf (1977) explain that drilling muds contain solid particles that form a filter cake over the wellbore wall, the filter cake restricts the mud flow into the near well bore formation, but some filtrate and fine particle invasion are unavoidable and usually occurs. The filtrate may react with the resident formation clays causing clay swelling, mobili- zation, and migration. The released particles and the fine particles carried into the formation by the filtrate can plug the pores and reduce permeability of the formation. The water-based filtrates increase the irreducible water saturation and create water block and hydrocarbon permeability reduction. Evaluation of Drilling Muds— Damage Potential and Removal As depicted in Figure 15-11 by Amaefule et al. (1988), the face of a core sample is exposed to mud under a pressure difference across the core. As described by Keelan and Koepf (1977), test sequences can be con- ducted with and without the presence of mobile hydrocarbons in core plugs. Figure 15-12 by Keelan and Koepf (1977) delineates the test sequence without the presence of mobile hydrocarbons and shows the equations used to determine the magnitude of formation damage or remediation. Keelan and Koepf (1977) explain that "This test indicates impairment of productivity by clay hydration and movement of fines into the formation during the drilling operation, and any benefit of the fines' removal when the well flow in a reverse direction into the wellbore." The core plug is saturated with the brine to be tested and may or may not contain irreducible, immobile oil. Hence, the water-block effect is elimi- nated because the water saturation is constant. During these tests, the filtrate volume or rate versus the filtration time is measured until mud- off. If the experimental design permits, the filter cake properties, such as porosity, permeability, and thickness, and the effluent fines and liquid volumes should also be measured. The pressure difference applied to the core plug should be determined by scaling from the planned drilling over balance pressure (Keelan and Koepf, 1977). Laboratory Evaluation of Formation Damage 483 Mud Circulation Flow Out: ^ _ Flow In: R injection Pi, injection Particulate Invaded Zone Filtrate Invaded Zone Fluid Flow: toP res. Figure 15-11. Core holder design for drilling mud evaluation systems (after Amaefule et al., ©1988; reprinted by permission of the Canadian Institute of Mining, Metallurgy and Petroleum). Figure 15-13 by Keelan and Koepf (1977) delineates the test sequence with the presence of mobile hydrocarbons and shows the equations used to determine the magnitude of formation damage or remediation. They explain that this test indicates "the water-block potential of a formation." In this test, the water saturation varies and is calculated by measuring the effluent filtrate volume. Any permeability reduction remaining, after the production of all the injected, extraneous filtrate water, is attributed to clay hydration and/or mud-solids invasion (Keelan and Koepf, 1977). Figure 15-14 by Keelan and Koepf (1977) depicts the results of the evaluation tests of two muds, referred to as Muds A and B. Figure 15-14 indicates that Mud A causes more damage than Mud B. In the case of Mud A, the return permeability is only 6% of the initial permeability, while it is 54% for Mud B. Keelan and Koepf (1977) conducted evaluation tests for two different drilling mud fluids, specially prepared for stabilizing the formation to 484 Reservoir Formation Damage NO MOBILE HYDROCARBONS PRESENT SAME AS MEDIUM K % ACID IMPROVEMENT NOTE PORE VOLUMES OF FILTRATE REQUIRED, RATE OF FLUID LOSS, AND PRESSURE DROP DAMAGE DUE TO 0 MUD SOLIDS ® CLAY HYDRATION AND/OR MOVEMENT MAY REQUIRE PREFLUSH, ACIDIZATION AND AFTERFLUSH Figure 15-12. Test sequence without the presence of mobile hydrocarbons (after Keelan and Koepf, ©1977 SPE; reprinted by permission of the Society of Petroleum Engineers). avoid formation damage during water flooding. Keelan and Koepf (1977) used fresh cores containing irreducible oil. They recommend running tests with the presence of irreducible oil because they explain that "The presence of residual oil, or associated organic compounds, sometimes protects clay surfaces, making them less sensitive to alteration when contacted by incompatible brines." They injected coarsely filtered mud Laboratory Evaluation of Formation Damage MOBILE HYDROCARBONS PRESENT 485 % ACID IMPROVEMENT 100 DAMAGE DUE TO MUD SOLIDS <2) CLAY HYDRATION AND/OR MOVEMENT (T) RELATIVE PERMEABILITY (WATER BLOCK) Figure 15-13. Test sequence with the presence of mobile hydrocarbons (after Keelan and Koepf, ©1977 SPE; reprinted by permission of the Society of Petroleum Engineers). filtrates (thus containing fine particles) into core plugs and measured the permeability impairment. Figure 15-15 by Keelan and Koepf (1977) presents the results of injecting formation brine, filtrate, and injection brine samples into the core plugs. As can be seen, the effective permeability is 30% higher for KC1 mud filtrate compared to that of lignosulfonate mud filtrate. 486 Reservoir Formation Damage ORIGINAL _ _ rs. 01 CD O Sl.4 0 S" (C ll. 1 A MEABILITY : 0> <B C £ '* £ .2 0 i i i i - FORMATION BRINE i " (PRIOR TO MUD-OFF) - i i i i i i i i - ^MUD-OFF r i ! FORMATION BRINE 1 (AFTER MUD-OFF) I AP«300 W»- AP»150/ ® 1 r— — — ' 11 ! ' AP'WO iP-500 IIUD " ?0 40 60 BO KX> 120 140 160 180 200 CUMMULAT'VE INJECTION '• PORE VOLUMES Figure 15-14. Mud damage evaluation (after Keelan and Koepf, ©1977 SPE; reprinted by permission of the Society of Petroleum Engineers). t.V 1.8 o •3 *^ s® 1 ' a-J 10 as < '- 0 uj ac 0. o o S g 50 2 u. - 10 .6 X 0 i* oc ii» 0 - KCJ FILTRATE, DAMAGE _ — - " Ul ae I o ^- i Ul 1 i — i ^ M S § 1 • LI6NOSULPHOHATE FILTRATE DAMAGE „ ^ Ul 1 2 i *H rn fsJ W ^ oc a - i i * SAMPLES CONTAIN RESIDUAL 00. Figure 15-15. Permeability to injection brine following exposure to KCI and lignosulfonate mud filtrate (after Keelan and Koepf, ©1977 SPE; reprinted by permission of the Society of Petroleum Engineers). Laboratory Evaluation of Formation Damage 487 For purposes of remediation treatment after damage, Keelan and Koepf (1977) evaluated two types of acids: (1) "a regular mud acid contain- ing about 7 -i % inhibited HCI and a low surface-tension agent," and (2) a mud acid "composed of 3% HF and 12% HCI." They explain that "Recommended use of the HF acid required a preflush with 15% HCI, injection of the HF acid, and an after flush with diesel oil containing 20% of a mutual solvent." Based on the results presented in Figure 15-16, Keelan and Koepf (1977) summarized their interpretation of the acid treatment results as following: 1. Similar permeability reduction to each filtrate was noted in these test cores. 2. In the cores contacted with KC1 filtrate, HF acid yielded 136% higher permeability to injection brine than did the regular mud acid, and resulted in a net permeability enhancement above initial. The regular mud acid was not effective, and final permeability to injec- tion brine was no higher than when the acid wash was not used. 3. In the lignosulfonate-contacted cores, the regular mud acid and the HF acid were equally effective, and each yielded a permeability greater than the original. 2.2 1.8 - S' 6 o £ S i sli.0 uj 3= a. 5 S « .8 => ° o 5 4 KCI FILTRATE a RECOVERY BY ACIDlZATlOtt UGNOSULPHONATE FILTRATE DAMAGE ! 'iH ft RECOVERY BY ACIDlZATION CD MYDROflOWCiHF) Figure 15-16. Permeability improvement by HF and HCI acid treatment following exposure to KCI and lignosulfonate mud filtrate (after Keelan and Koepf, ©1977 SPE; reprinted by permission of the Society of Petroleum Engineers). 488 Reservoir Formation Damage 4. In summary, either mud was suitable if HF acid was used for remedial treatment. If the regular mud acid was to be used, the most suitable drilling mud would be lignosulfonate. Evaluation of Hydraulic Fracturing Fluids As explained by Keelan and Koepf (1977) fracturing fluids cause formation damage by water-block, solids invasion associated with fluid leak-off, and clay hydration in the near-fracture formation. Therefore, it is important to use compatible fluids and fluid-loss additives. Hence, they recommend performing tests on core samples extracted from the reservoir formation, in which fractures will be created. In these tests, the spurt loss, fluid-loss coefficient, effect of additives, acid solubility of formation, fines release with the acid reaction, are typically determined (Keelan and Koepf, 1977). Evaluation of Workover and Injection Fluids These tests indicate the incompatibility of clays with the extraneously introduced water, including filtered formation brine and filtered mud filtrate (Keelan and Koepf, 1977). Such tests can also be used to evaluate the effectiveness of clay stabilizers added to workover and injection fluids (Keelan and Koepf, 1977). Keelan and Koepf (1977) state that "Use of filtered workover fluids removes plugging solids and results in evaluation of damage resulting from clay swelling and/or clay-particle movement." The rock-water system is considered compatible when the formation permeability does not decrease by fluid injection. Keelan and Koepf (1977) state that The clays damage productivity either by swelling in place or by release from their anchor point and subsequent movement to block pore channels. The inclusion of certain ions in workover and injection fluids often offers a relatively inexpensive and effective stabilization of the clays and prevention of productivity impairment. Figure 15-17 by Keelan and Koepf (1977) presents the test sequence and the equations necessary for determining formation damage for evalu- ation of the compatibility of the injection and workover fluids with the formation clays. Figure 15-18 by Keelan and Koepf (1977) shows the results of injecting brines with and without KC1 and CaCl 2 added. Injecting a brine, rather than the formation brine, into a core sample A reduced the permeability to 50% of its formation brine permeability. Injecting a brine containing 100 ppm KC1 into a core sample B doubled Laboratory Evaluation of Formation Damage 489 T3 0) _C Q. 2 LU Q_ 0) r O) © a. o o * T3 CO Q t CO ;g '3 0) o .£ O •D CO ^ C 'w' .2 o "o o> 0) C rg si II IS 0) O CD §•«> 8 I to „_ Si CD 3 Q. 490 Reservoir Formation Damage v ] J 18 i" o 14 O o ••* u. ln 1 " h- S -6 A Ul 3E 6 cc U> CL. o 4 i _ SAMPLE ® - • " 3 ? h f ol — UJ i % o . I i >5 2 SAMPLE (D S ED g «§ * w S: § ^ SAMPLE © - tu ae O3 i 5 1 » r^ 0 1 § MIXED WITH INJECTION BRINE Figure 15-18. Permeability to injection brine with and without KCI and CaCI 2 addition (after Keelan and Koepf, ©1977 SPE; reprinted by permission of the Society of Petroleum Engineers). its formation brine permeability. However, injecting a brine containing 100 ppm CaCl 2 reduced the permeability to 50% of its formation brine permeability. Figure 15-19 by Keelan and Koepf (1977) shows that consecutively decreasing concentrations of KCI and CaCl 2 in the injected brines yields permeabilities above the initial formation brine permeability. Keelan and Koepf (1977) concluded that KCI treatment is favorable even though the data appear unusual. Keelan and Koepf (1977) recommend the water-oil relative perme- ability measurements as a practical approach to damage assessment in core plugs. Keelan and Koepf (1977) express that the fluids compatible with the core material should typically yield the relative permeability curves similar to those shown between the AA' and BB' lines in Figure 15-10. However, Keelan and Koepf (1977) explain that, when a filtered injection brine is injected into a core containing irreducible oil, a specific value of the water relative permeability, denoted by Point E in Figure 15-10, is obtained. This particular value represents the water relative permeability at the injection-wellbore formation face. Whereas, the water relative permeability at a sufficiently long distance from the well bore is represented by Point B. Laboratory Evaluation of Formation Damage 491 s.v -J1.8 o u. 0 14 O EC ^ 1 0 • i IV 13 .8 S J* S 6 ce S 4 o Zi 2 0 TEST SEQUENCE SAMPLE ®p«l itbijtwutNU. SAMPLE ©gJSCaClz. - - _ - - II: ::: it ::! *i 5 DD | •y | rn i 5*C 1 S i II! ::: n « 1 Q § 9K 5 Q. I III i 1 .::: :!: K ill: !•: iil * ^ 0 .;:: 1 i E: 3? : c: i tl! • : 1!! *;| ! n i ':• TT jii ::: j£J J5 ^ § 1 L> K lil ~ _ _ - - * MIXED WITH INJECTION BRINE Figure 15-19. Permeability with reduced concentrations of KCI and CaCI 2 solutions (after Keelan and Koepf, ©1977 SPE; reprinted by permission of the Society of Petroleum Engineers). Evaluation of Workover Damage and Remedial Chemicals Figure 15-20 by Keelan and Koepf (1977) describes the testing schemes and equations necessary for determining the damage and evaluation of remedial chemical treatment of water block. Keelan and Koepf (1977) facilitate surface tension reducing chemicals to remove the water forming the water-block. Critical Interstitial Fluid Velocity and pH for Hydrodynamic Detachment of Fines in Porous Media The drag force acting upon a fine particle attached to the pore surface is proportional to the interstitial velocity and viscosity of the fluid and the surface area of the particle, as discussed in Chapter 8. As the fluid velocity is increased gradually, a critical velocity necessary for detach- ment of fine particles from the pore surface can be reached. Amaefule et al. (1987) state that "The critical velocity is dependent on the ionic strength and pH of the carrier fluid, interfacial tension, pore geometry [...]... 1 McCreery, Dale Consolidated Field — AP1 12 055 234 56 3, 19 0.5 3, 19 1.5 3, 19 2.7 3, 19 4.0 3, 19 5.7 3, 19 7.9 3, 19 9.4 3, 2 01. 0 3, 2 03. 3 3, 205.8 3, 207 .1 3, 208.4 3, 209.9 3, 212 .7 3, 216 .7 3, 219 .2 49.0 81. 5 10 6.0 11 6.0 55.8 56.8 41. 9 35 .5 27.9 15 .8 1. 8 2.5 -0 .1 NA NA NA 20.4 23. 4 25.6 23. 6 19 .8 24.8 24 .3 21. 4 18 .6 21. 4 14 .6 13 . 1 0.7 NA NA NA 3. 2 2.8 2.5 3. 4 2.6 3. 1 2 .1 3. 1 2 .1 2.4 3. 1 1.7 5.2 2.7 1. 5 4.6 1. 4 1. 5 1. 1... Field — AP1 12 199 234 65 2 ,38 7.6 2 ,38 8.4 2 ,39 0 .1 2 ,39 2.7 2 ,39 4.7 2 ,39 5.2 18 4.0 246.0 69.0 85.0 69.0 4 .3 21 .3 21. 7 23. 6 23. 3 20.6 13 . 6 1. 6 1. 2 1. 4 0.8 1. 0 1. 6 0.9 1. 1 0.7 0 .3 0.5 0.9 2.4 1. 9 2.5 1. 7 3. 0 4 .1 6.0 30 .9 6.7 16 .6 12 .5 27.5 0.0 0.0 0.0 0.0 0.0 0.0 Superior Oil Company 1 Price, Boyd Field — AP1 12 0 810 1972 2 ,12 9.0 2, 13 1 .0 2, 13 3 .0 2, 13 4 .0 2, 13 5 .0 0.0 1. 7 11 8.0 81. 0 0.0 7 .3 17 .7 15 .1 11. 4 7.0 1. 2 0.8... 12 4.0 15 2.0 35 .6 89.5 47.8 47.8 56.0 NA -0 .1 -0 .1 -0 .1 14.4 25 .1 22 .1 22 .1 24 .1 25.5 23. 6 24.5 24.8 23. 5 23. 8 NA 8.8 17 .0 11 .0 5.5 3. 7 2.9 2.4 1. 7 4.2 2 .3 0.5 1. 2 2.0 2.2 2.4 2.5 2.5 1. 0 2.7 2.7 1. 2 1. 4 0.8 1. 9 1. 2 0 .3 0.6 2 .1 0.7 2 .1 1.9 2.5 1. 1 1. 1 2.2 1. 9 2.2 1. 9 3. 3 3. 7 1. 5 4 .3 6.0 7.2 5.2 5 .3 4.9 3. 0 9.4 8.7 6 6 4 .3 9.4 7 .1 2 .3 6.2 9.7 9.7 9.9 5 .1 69.2 64.2 85.0 86.4 86.2 72 .1 77.9 91. 4 82.7 61. 8... 82.7 61. 8 78.8 72.7 80 .3 84.5 90.6 5 4.2 4.7 2.7 4.5 6.6 80.8 56.5 85.4 72.7 76 .3 63. 5 0.0 0.2 0.6 0.2 0.4 0.0 8.2 8.2 2.6 7.8 6 .3 2.5 2.6 2.9 1. 5 8.8 1. 8 93. 7 90.7 88 .3 80.6 67.6 2.0 3. 3 1 .3 1. 2 1. 2 1. 0 2 .3 0.5 0.8 0.8 2.6 1. 5 4 .1 2.4 80.9 84.2 84.9 88 .3 2.5 2.6 3. 2 2.9 0.7 1 .3 1. 6 1. 1 10 .1 10 .1 20.5 18 .5 16 .7 3. 9 2.9 3. 9 3. 4 3. 7 1. 9 3. 8 3. 3 4.2 15 .2 1. 9 1. 5 0.0 0.0 0.0 0 .1 0.0 0 .3 0.0 0.0 0.0 0.0 0.0... 1. 5 1. 1 2.5 1. 5 1. 7 1. 5 2 .3 2 .1 2 .1 4.2 1. 9 4.7 3. 7 2.0 4.4 0.7 0.7 0.6 0.9 0.7 0.8 0.6 0.9 0.4 0.5 0.7 0.5 1. 9 0.0 0.0 0 .1 11. 8 6.4 3. 5 9 .1 2.4 2.9 3. 4 14 .2 7.6 21. 8 8.4 16 .8 91. 2 93. 6 71. 8 15 .6 Gallagher Drilling Company 2 Mack, Zeigler Field — API 12 055 237 50 2,605.5 2,606.5 2,608.5 2, 610 .5 2, 611 .5 2, 612 .5 2, 614 .5 2, 617 .5 2, 618 .5 2,620.5 2,6 21. 5 2,6 23. 7 2,6 23. 8 2,625.5 2,629 24.9 216 .0 49.0 64.0 12 4.0... 4 .1 84.5 81. 6 84.9 79.5 88.0 80.7 82.5 82 .3 77.8 83. 7 67.8 82.9 68.4 1 .3 1. 7 1. 5 1. 2 0.0 2.6 2.7 2.6 1. 5 1. 2 0.8 1. 7 1. 2 0.0 0.0 0.0 2.5 3. 2 3. 7 4 .3 1. 9 2.6 3. 7 3. 3 1. 9 2.4 1. 5 2.8 1. 8 0.0 0.0 0.0 6.4 8.6 5.6 8 .1 3. 2 8.5 6.8 5.5 0.0 0.0 0.0 0.0 2.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 3. 0 1. 1 0.6 0.4 8.9 2 .3 0.0 0.2 0.6 0.2 5.0 0.5 0.4 2.9 7.4 3. 9 4.0 4.9 6 .1 9.0 4.4 7 .1 4 .3 6.4 2.2 3. 1 3. 7 3. 9... 2, 13 5 .0 0.0 1. 7 11 8.0 81. 0 0.0 7 .3 17 .7 15 .1 11. 4 7.0 1. 2 0.8 0.5 3. 7 0.4 0.9 0.6 0 .3 2.6 0 .3 0.5 1. 5 0.7 2.5 1. 1 0.5 0.5 8 .1 8.4 28.5 0.2 0 .3 0.2 0.2 0 .1 Superior Oil Company 7 Sanders, Boyd Field — AP1 12 0 810 1950 2 ,14 1.0 2 ,14 4.0 2 ,15 1.0 2 ,15 5.0 42.0 21. 6 36 2.0 24.2 14 0.0 21. 5 19 .5 58.0 1. 1 0.4 1. 4 0.6 0.8 0 .3 1. 0 0.5 0.7 0.7 1. 6 1 .3 12 .9 10 .1 6.0 4.7 Perm = permeability, D = dolomite, Cc = calcite, C... 15 -2 by Haggerty and Seyler (19 97) They concluded that Aux Vases formation core samples contained 65-90% quartz, 3- 15 % feldspar, 0 -15 % calcite and 2-7% clay minerals 502 Reservoir Formation Damage Table 15 -2 Aux Vases Samples: Bulk Weight Percentage of Clay Minerals (absolute percentage of other minerals) Perm Depth ft Porosity I I/S C md % % % BC Q Kf Pf Cc D 5 .3 5 4 .3 6.8 4.8 5.6 4.2 6 .3 4.6 5 .1. .. 15 -22 Effect of flow regime: (a) permeability alteration by mobilized particles during Darcy flow, and (b) apparent permeability alteration by mobilized particles during non-Darcy flow (after Amaefule et al., 19 87 SPE; reprinted by permission of the Society of Petroleum Engineers) IBB t-A- ^V CRITICAL VELOCITY FOR KCL * B .16 21 " A = 11 .36 c«2 18 .1 Z ^= W er o 8.82 e.Bi 0.H6 a.aa ' a.ia a 8 .16 1N1ERS11TIAL... (Gruesbeck and Collins, 19 82; Gabriel and Inamdar, 19 83; Egbogah, 19 84; Amaefule et al, 19 87, 19 88; Miranda and Underdown, 19 93) The theory of the critical velocity determination is based on Forchheimer's (19 14) equation, given below, which describes flow through porous media for conditions ranging from laminar to inertial flow: (15 -2) The interstitial velocity is given by: (15 -3) Considering horizontal . .2 0 i i i i - FORMATION BRINE i " (PRIOR TO MUD-OFF) - i i i i i i i i - ^MUD-OFF r i ! FORMATION BRINE 1 (AFTER MUD-OFF) I AP 30 0 W»- AP 15 0/ ® 1 r— — — ' 11 ! ' . IIUD " ?0 40 60 BO KX> 12 0 14 0 16 0 18 0 200 CUMMULAT'VE INJECTION '• PORE VOLUMES Figure 15 -14 . Mud damage evaluation (after Keelan and Koepf, 19 77 SPE; reprinted by . Engineers). t.V 1. 8 o 3 *^ s® 1 ' a-J 10 as < '- 0 uj ac 0. o o S g 50 2 u. - 10 .6 X 0 i* oc ii» 0 - KCJ FILTRATE, DAMAGE _ — - " Ul ae I o ^- i Ul 1 i — i ^ M S § 1 • LI6NOSULPHOHATE FILTRATE