Formation Damage Control and Remediation 707 cases, such as open hole completions (Bennion, 1999). Because formation damage is usually nonreversible, it is better to avoid formation damage rather than deal with it later on using expensive and complicated pro- cedures (Porter, 1989; Mungan, 1986). In many cases, remedial treatments may also cause other types of damages, while the intent is to cure the present damage problems. When asked "Is it more cost effective to prevent formation damage or bypass it?" (JPT, ©1994 SPE; reprinted by permission of the Society of Petroleum Engineers), some experts replied as following: McLeod: "There is no universal answer for this question. Often the formation quality determines whether it is more cost effective to prevent damage or to remove it or bypass it later by acidizing or hydraulic fracturing. Generally, damage prevention is more cost effective than removing or bypassing damage later." Peden: "Prevention of damage must be cost effective but it requires a greater understanding of the physics of the processes, as well as an improvement both in our predictive and operational techniques. Bypassing damage can never be an attractive alternative to damage minimization." Penberthy: "If it is more cost effective to prevent damage, then that is probably the best solution. If an effective, inexpensive acid job or a minifrac treatment is less expensive than the cost of the completion fluid, the post-treatment approach probably should be selected." Some of the other comments of the experts are quoted in the following from JPT (1994): Burnett: "If there is existing formation damage in a well, there are three choices: live with it; fracture or perforate past it; or use some means of removing it. The choice depends upon economics and technology. The key to formation damage cleanup is understanding what has caused the damage. The damage may be caused by tenacious filter cakes, particle invasion into the rock, and/or fluid-filtrate chemical damage. Many of us believe that particulate damage extends only a few tenths of a foot into a zone. On the other hand, chemical damage (clay reactions, formation fines movement, rock/fluid incom- patibility, and precipitation) can exist tens of feet into the pay zone. Near-well damage can be reduced (but not eliminated) with acids, oxidizers, and solvents. If you have deep damage, then sidetracking is nearly always the best option." 708 Reservoir Formation Damage Peden: "The further we get away from the borehole, the less control we have over our ability to clean up or remove impairment . . . However, formation damage is largely characterized by a lack of understanding of the potential of the processes and the mechanisms involved . . . Greater understanding, training, and technology transfer is required between the service and operating-company sectors." Penberthy: "One of the main causes for formation damage is using techniques, procedures, and fluid systems that are known to cause problems and risking the chance that somehow the operator will be able to "get by with it." Whether a particular fluid is nondamaging depends on the par- ticular site-specific application and formation in which the well is completed; i.e., there may be no such thing as a universal non- damaging completion fluid. Suggestions are to use clear brines that are compatible with the reservoir rock. I will specify the guidelines for selecting an ideal fluid. While it may be rare that all properties can be achieved, compromising between fluid properties and characteristics should identify com- pletion fluids that will provide acceptable results. An ideal completion fluid should be compatible with the reservoir rock (nondamaging) and have low fluid loss, acceptable suspension and transport properties, thin filter cake, and low friction loss. The density should be easily controlled. The fluid should also be readily available, inexpensive, easily mixed and handled, and nontoxic." Ali: "All brine systems are potentially formation damaging at high temperatures. In addition, unfavorable fluid/rock interaction at relatively low temperature can produce mobile fines with the added potential for the precipitation of carbonate, sulfide, sulfate, and sodium-chlorite scales. The need for thoroughly evaluating the compatibility of completion fluids with formation brine, formation mineralogy, and produced fluids cannot be overly stressed." Burnett: "In fields we have studied, we've found that formation damage from water-based fluids was no worse than corresponding oil-based or synthetic fluids. The key is ensuring that the fluid, whatever it may be, is compatible with the formation fluids and the rock matrix." McLeod: "In high-permeability formations, polymers and other fluid-loss control materials can cause severe damage if not mixed properly. Sometimes that damage may be removed by appropriate Formation Damage Control and Remediation 709 acidizing. If fluid-loss pills are not used, sometimes fluid losses are so high that they pick up contaminants still attached to tubing and casing surfaces after incomplete cleaning of mud, rust, and other particles. Those particles are carried into the formation, where they are filtered out and reduce permeability. Good filtration of compatible brines and shearing and filtering of polymers used for fluid-loss control are key to preventing or reduc- ing damage. Even with good hydration techniques, microgels in polymer solutions can plug formations unless the microgels are reduced or removed by shearing and filtration before their placement in the well." Peden: "To establish fluid-selection procedures, realize that forma- tion damage is a result of either a solid/solid interaction between the drilling-mud particulates and the formation or a fluid/ fluid interaction resulting from the base fluid interacting with the reservoir fluid. Or alternately, it is an interaction between the base fluid of the drilling mud and the rock constituents. To select appro- priate fluids, devise testing programs that address those issues." Ali: "By conducting core displacement tests with various drilling fluids on representative reservoir samples, the least damag- ing drilling fluid can be selected. In addition, fluid rheology, solids content and size distribution, overbalance pressure, formation permeability, and other parameters can be considered for selecting well-specific fluid systems." Burnett: "We . . . recommend that our clients obtain certain basic information about the formation and about the fluids that con- tact the formation. Information such as mineral content, porosity, permeability, and formation pore-size distribution can be used to screen completion fluids." Formation damage control and remediation is both a science and an art. There are no universally proven technologies that are panesia for all problems. Creative approaches, supported by science and laboratory and field tests yield the best solution. An examination of the reported studies reveals that numerous recipes and/or recommended procedures have been developed. However, their applicability and/or effectiveness have been validated for certain specific rock and fluid systems and, therefore generalization of these approaches is questionable. In this chapter, some of the more common treatment methods are reviewed. However, their applicability in specific fields should be investigated and 710 Reservoir Formation Damage adapted by laboratory core testing. Here, they are only provided for instructional purposes, as our learning curve is still evolving, judging by the new techniques that are being introduced in the literature. Selection of Treatment Fluids As expressed by Thomas et al. (1998),* The type and location of the damage must be determined to select the proper treating fluids . . . Additionally, precautions should be taken to avoid further damage. Damage can be from emulsions, wettability changes, a water block, scale, organic deposits (paraffin and asphaltenes), mix deposits (a mixture of scale and organic material), silt and clay, and bacterial deposits. In most cases, the type or types of damage cannot be precisely identified with 100% accuracy. However, the most probable type or types can be deter- mined; therefore, most matrix treatments incorporate treating fluids to remove more than one type of damage. The selection of the treatment fluids depends on the specific applica- tions and purposes. The treatment fluid volumes are usually determined by means of laboratory core tests and mathematical models. Treatment fluids should contain various additives for various purposes. Thomas et al. (1998) explain the issue of additives as following: Although proper fluid selection is critical to the success of a matrix treatment, the treatment may be a failure if the proper additives are not used. The major treating fluid is designed to remove the damage effectively. Additives are used to prevent excessive corrosion, sludg- ing and emulsions, provide uniform fluid distribution, improve cleanup, and prevent precipitation of reaction products. Additionally, additives are used in preflushes and overflushes to stabilize clays, disperse paraffins and asphaltenes and inhibit scale and organic deposition. Additive selection is primarily dependent upon the treating fluid, the type of well, bottom-hole conditions, the type of tubulars, and the placement technique . . . Diverters are essential to obtain uniform fluid distribution in a horizontal well. The volume of each additive used is dependent on the specific problem addressed. For example, surfactants are commonly used at 0.2 to 0.5% to lower surface and interfacial tension and provide water wetting. As a rule, the minimum amount of additive should be used. Normally, the recommended concentration is determined in the labora- tory and is based on testing (i.e., nonemulsifiers, anti-sludge agents). * Reproduced by permission of the Society of Petroleum Engineers, ©1998 SPE. Formation Damage Control and Remediation 711 Clay Stabilization When clays are exposed to low salinity solutions, two mechanisms cause formation damage (Himes et al., 1991). Swelling clays imbibe water into their crystalline structure and enlarge in size and plug the pore space. Mobilization, migration, and deposition of clays can plug the pore throats. Himes et al. (1991) describe the desirable features of effective clay stabilizers, especially for applications in tight formation as following: 1. The product should have a low, uniform molecular weight to prevent bridging and plugging of pore channels. 2. The chemical should be nonwetting on sandstone surfaces to reduce water saturation. 3. It should have a strong affinity for silica (clay) surfaces to compete favorably with the gel polymers for adsorption sites when placed from gelled solutions and to resist wash-off by flowing hydrocarbons and brines. 4. The molecule must have a suitable cationic charge to neutralize the surface anionic charges of the clay effectively. Inorganic Cations (1C) Clay stabilization can be maintained by the aqueous solution salinity above that of the connate water (Himes et al., 1991). Figure 23-1 by Himes et al. (1991) shows the clay stabilizing effectiveness of various brines. The basal spacing versus the salt concentrations are shown as an indication of clay swelling, measured by x-ray diffraction (XRD). The clay will disperse when the basal spacing is greater than 21A (Himes et al., 1991). In this respect, Figure 23-1 indicates that the clays are stable even at very low concentrations of K + and NHj cations; whereas, a sufficiently high concentration of Na + cation is necessary to maintain clay stability. Therefore, K + and NHj are natural clay stabilizers, but are not permanent because they can be exchanged with Na + (Himes et al., 1991). Figure 23-1 shows that calcium ion can maintain clay stability, but it is not preferred as a clay stabilizing agent because it may react with formation brines and chemical additives (Himes et al., 1991). Cesium cation (Cs + ) is also very effective at low concentrations, but it is very rare and expensive (Khilar and Fogler, 1985; Himes et al., 1991). Damage resulting from clay swelling and mobilization, migration, and redeposition can be prevented by adding certain ions to stabilize the clays in workover and injection fluids (Keelan and Koepf, 1977). Five percent solutions of CaCl 2 and KCl, and hydroxy-aluminum (OH-Af) may be effective (Keelan and Koepf, 1977). 712 Reservoir Formation Damage 26 24 << ^ 22 20 18 16 14 0.01 0.1 1 10 SALT CONCENTRATION (%) 100 Figure 23-1. Basal spacing of smectite clay vs. concentration of various brines (after Himes et al., ©1991 SPE; reprinted by permission of the Society of Petroleum Engineers). Cationic Inorganic Polymers (CIP) In order to provide somewhat permanent clay stabilization, cationic inorganic polymers (CIP) such as hydroxyl aluminum and zirconium oxychloride, have been introduced (Reed, 1974; Valey and Coulter, 1968; Coppell et al., 1973; Himes et al., 1991). These agents provide resistance to cation exchange, but they are applicable for clay stabilization in non- carbonate containing sandstones and the formation should be retreated after acidizing (Himes et al., 1991). Cationic Organic Polymers (COP) Quaternary cationic organic polymers (COP) are used for effective and permanent stabilization of clays (especially smectite clays), and control- ling fines and sand in sandstone as well as carbonate formations (Himes et al., 1991). They are applicable in acidizing and fracturing treatments. Formation Damage Control and Remediation 713 They provide permanent protection because of the availability of multiple cationic sites of attachment. However, their applicability in tight forma- tions is limited to low concentrations (Himes et al., 1991). They can cause permeability damage by pore plugging because these high molecular weight and long-chain polymers have molecular sizes comparable with the some pore size fractions in porous rock. They can also increase the irreducible water content of porous rock because they are hydrophobic and water-wetting. Their effectiveness is substantially lower in gelled- water solutions used for hydraulic fracturing and gravel-packing as indicated by Table 23-1 by Himes et al. (1991) because of gel competition for adsorption on clay surfaces. Oligomers Oligomers are low-molecular-weight, cationic, organic molecules having an average of 0.017 \lm length (Penny et al., 1983; Himes et al., 1991). Oligomers offer many potential advantages over the cationic organic polymers for clay stabilization (Himes et al., 1991). Availability of many repeating sites and high affinity for clay surfaces enables better competition of oligomers with gels in water used for hydraulic fracturing and gravel-packing. Because of their smaller size compared to pore size, the treatment-imposed permeability damage is significantly reduced. Because they are only slightly water-wetting (contact angle is 72°), the irreducible water content is also reduced. Zaitoun and Berton (1996) examined the effectiveness of cationic polyacrylamides (CPAM) and nonionic polyacrylamides (PAM) for stabilization of montmorillonite clay by means of the critical salinity concentration method (CSC). As schematically depicted in Figure 23-2 by Zaitoun and Berton (1996), the polymers prevent fines migration by coating over the pore surface and Table 23-1 Basal Spacing of Smectite Clay Exposed to Various Brines Spacing—Dry Solution (A) 2%KC1+1%COP 2% KC1 + 0.5% HPG 2% KC1 + 0.5% HPG + 1% COP 2%KCl+l%oligomer 2% KC1 + 0.5% HPG + 1% oligomer 14.8 18.7 17.3 14.3 14.3 After Himes et al., ©1991 SPE; reprinted by permission of the Society of Petroleum Engineers. 714 Reservoir Formation Damage Figure 23-2. Polymer coating of pore surface for clay migration prevention (after Zaitoun and Berton, ©1996 SPE; reprinted by permission of the Society of Petroleum Engineers). blocking the clay particles. They determined that low-molecular-weight polymers have comparable stabilizing capability to high-molecular-weight polymers and are more advantageous because they cause less treatment- induced permeability damage. Kalfayan and Watkins (1990) used organosilane compounds as additives to acid systems to prevent the weakening of the rock by acid dissolution. This additive undergoes a hydrolysis reaction to form silanols, which tie to the silanol sites present on siliceous mineral surfaces and forms a polysiloxane coating to bind clay and siliceous fines in place. />#-Buffer Solutions Buffering is an effective means of pH control by maintaining the hydrogen ion activity constant in spite of the changing conditions. Buffer capacity expresses the sensitivity of pH of an aqueous solution to adding a strong base (Gustafsson et al., 1995). Hayatdavoudi (1998) hypothesizes that alteration of kaolinite to dickite, nacrite, and halloysite, through chemical oxidation according to the following reactions, may be respons- ible for fines generation, at high pH in the presence of alkali hydroxides. Formation Damage Control and Remediation 715 2Na + O-> NaO 22 Na 2 O 2 + 2H 2 O -> 2NaOH + H 2 O 2 Therefore, Hayatdavoudi (1998) recommends buffering the pH of brines to 8 or below and avoid aeration of injected fluids to prevent kaolinite comminution-induced formation damage. Hayatdavoudi (1998) also recom- mends adding ammonium chloride and/or ammonium sulfate buffers to prevent silicate dissolution at high pH environments. Clay and Silt Fines The fluid selection studies conducted by Thomas et al. (1998) have indicated that: 1. The sandstone formation damage can be treated by fluids that can dissolve the materials causing the damage. 2. The carbonate (limestone) formations are very reactive with acid and, therefore, the damage can be alleviated by dissolving or creating wormholes to bypass the damaged zone. If there is a silt or clay damage, HCl should be used to bypass the damage. The damage by calcium fluoride precipitation cannot be treated by HCl or HF acid treatment. Formation damaged by silt and clay fines introduced by drilling, completion or production operations require different acid treat- ment recipes that vary by the formation type, location of damage and temperature (Thomas et al., 1998). Recipes recommended for acidizing of carbonate (limestone) formations are outlined in Figure 23-3 by Thomas et al. (1998). Motta and Santos (1999) proposed that certain blends of fluosilicic acid (H 2 SiF 6 ) with hydrochloric acid (HCl) or an organic acid, such as acedic acid (//Ac) can dissolve clays and feldspars without reacting with the quartz. These systems remove deep clay damage in sandstone formations, without the usual adverse effects of the secondary precipitation reaction encountered in conventional acidizing by HF or H 2 SiF 6 alone. Motta and Santos (1999) have determined that properly designed acid blends can substantially reduce the skin in the field. Gdanski and Shuchart (1996) have shown that the equilibrium condition between fluosilicic acid and 716 Reservoir Formation Damage Treating Fluid Selection for Damaged Carbonates Damage in Fissures and/or Matrix Temperature < 300°F. Temperature > 300°F. < 400 °F. Temperature > 400°F. 15to28%HCI with mud/silt dispersants 15%HCI or 9% Formic Acid with mud/silt dispersants 10% Acetic Acid with mud/silt dispersants Figure 23-3. Fluid selection for carbonate acidizing (after Thomas et al., ©1998 SPE; reprinted by permission of the Society of Petroleum Engineers). hydrochloric acid controls the extent of the primary and secondary reactions of hydrofluoric acid with the aluminum silicates. Fluobaric acid (//BF 4 ) is a retarded acid, which reacts with the alumina layers of clays to form a borosilicate film. The borosilicate film prevents the migration of in-situ clay and silt fines at high shear-rates of flow because the borosilicate film stabilizes the fine particles in petroleum- bearing formations (Thomas and Crowe, 1978; Colmenares et al., 1997). The fluoboric acid can be effective for applications extending 3 to 5 feet from the wellbore (Ezeukwu et al., 1998). Bacterial Damage Bacteria growth in injection wells can cause many problems including plugging of the near-wellbore formation. Johnson et al. (1999) recommend the use of 10-wt% anthrahydroquinone disodium salt in caustic to con- trol the growth of sulfate-reducing bacteria (SRB) combined with the traditional biocide treatment for control of other types of bacteria. For example, bacteria-induced formation damage in injection wells can be treated using a highly alkaline hypochlorite solution, followed by a HCl overflush for neutralization of the system (Thomas et al., 1998). [...]... Petroleum Technology, August 1996, pp 7 23- 724 Leontaritis, K J., Amaefule, J O., & Charles, R E., "A Systematic Approach for the Prevention and Treatment of Formation Damage Caused by Asphaltene Deposition," SPE 238 10 paper, SPE International Symposium on Formation Damage Control, Lafayette, Louisiana, February 26-27, 1992, pp 38 3 -39 5 728 Reservoir Formation Damage McLaughlin, H C., Elphingstone, E... petrographical, 49 Characterization, formation damage, 9 Characterization, porous media processes, formation damage, 127 Characterization, reservoir rock, 9, 102 Chemical equilibria, graphical description, of rock-fluid, 33 9 Clay content, graphical representation of, 42 Clay expansion, coefficient, time-dependent, 33 Clay fines, control, 715 Clay minerals, saturation index charts, 35 1 Clay stabilization, 711... coefficient, 31 mechanisms, 22 models, 25 water content, 32 Coefficient, clay expansion, time-dependent, 33 Coefficient, clay swelling, 31 Colloidal release and mobilization, 155, 250 Compartments-in-series ordinary differential model, 197 Completion fluids, formation damage, control, 718 Composition, petroleum-bearing formations, 12 731 Compressive cake filtration including fines invasion, 291, 536 Constant-flow-rate... detachment of fines in porous media, 491 Crude-oil emulsions, formation damage, control, 718 Crystal growth in porous media, 164 Crystal surface displacement by dissolution and precipitation, 178 Crystallization, 166 kinetics, 171 Damage, depth of, 6 93 Damage by formation fines migration, 251 Damage by mud filtration, 255 Damage by particle invasion, 2 53 Damage ration, 687 Deposition calcite, model, 674 ... High-Pressure/HighTemperature Reservoir Conditions on Selection and Application of Conventional Scale Inhibitors: Thermal-Stability Studies," J of Petroleum Technology, June 1997, pp 632 - 633 Gustafsson, T K., Skrifvars, B O., Sandstrom, K V, & Waller, K V, "Modeling of pH for Control," Ind Eng Chem Res., Vol 34 , 1995, pp 820-827 Hayatdavoudi, A., "Controlling Formation Damage Caused by Kaolinite Clay Minerals: Part II," SPE 39 464... Formations Comprising Argillaceous Material," U.S Patent No 3, 382,924, May 14, 1968 Zaitoun, A., & Berton, N., "Stabilization of Montmorillonite Clay in Porous Media by Polyacrylamides," SPE 31 109 paper, SPE Formation Damage Control Symposium, February 14-15, 1996, Lafayette, Louisiana, pp 4 23- 428 Zhang, Y., Chen, Z., & Yan, J., "Investigation of Formation- Damage Control of the Methylglucoside Fluids," J of... reactions, 32 8 Aqueous speciation models, 33 7 Aqueous species of the Fe-OH2O systems, 36 7 Aqueous species of the Fe-OH2O-S systems, 37 0 Aqueous O-H2O systems, 37 2 Area open for flow, 53 Asphaltene adsorption, 405 Asphaltene deposition, two-phase, dual-porosity model, 428 Asphaltene phase behavior and deposition envelopes, 39 2 Asphaltene precipitation, singlephase, empirical algebraic model, 410 Asphaltenic... 19 83, San Francisco, California Porter, K E., "An Overview of Formation Damage, " J of Petroleum Technology, Vol 41, No 8, 1989, pp 780-786 Reed, M G., "Formation Permeability Maintenance with Hydroxy-Aluminum Solutions," U.S Patent No 3, 827,500, August 6, 1974 Samuelson, M L., "Alternatives to Aromatics for Solvency of Organic Deposits," SPE 238 16 paper, SPE International Symposium on Formation Damage. .. 28 -31 , 1999, Oklahoma City, Oklahoma, 10 p Bennion, B., "Formation Damage The Impairment of the Invisible, by the Inevitable and Uncontrollable, Resulting in an Indeterminate Reduction of the Unquantifiable!" Journal of Canadian Petroleum Technology, Vol 38 , No 2, February 1999, pp 11-17 Bennion, B., "Experts Share Views on Formation Damage Solutions," J of Petroleum Technology, November 1994, pp 936 -940... region by the thermallyinduced stresses 4 Increases near-wellbore formation permeability Jamaluddin etal (1998) o o P 3 P CTQ CD n o a o n> CL P' cr o -a K> tn 726 Reservoir Formation Damage (text continued from page 719) Bennion, D B., Thomas, F B., & Bennion, D W., "Effective Laboratory Coreflood Tests to Evaluate and Minimize Formation Damage in Horizontal Wells," Third International Conference on . oligomer 14.8 18.7 17 .3 14 .3 14 .3 After Himes et al., ©1991 SPE; reprinted by permission of the Society of Petroleum Engineers. 714 Reservoir Formation Damage Figure 23- 2. Polymer coating . fluosilicic acid and 716 Reservoir Formation Damage Treating Fluid Selection for Damaged Carbonates Damage in Fissures and/or Matrix Temperature < 30 0°F. Temperature > 30 0°F. < 400 . effective (Keelan and Koepf, 1977). 712 Reservoir Formation Damage 26 24 << ^ 22 20 18 16 14 0.01 0.1 1 10 SALT CONCENTRATION (%) 100 Figure 23- 1. Basal spacing of smectite clay