Copyright 2007, Society of Petroleum Engineers This paper was prepared for presentation at the 2007 SPE International Symposium on Oilfield Chemistry held in Houston, Texas, U.S.A., 28 February2 March 2007. This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, Texas 75083-3836 U.S.A., fax 01-972-952-9435.

Abstract The purpose of matrix treatments in carbonate reservoirs is to increase connectivity of a formation with the wellbore in the entire zone of interest. Successful matrix treatments depend on the uniform distribution of the treating fluid over the entire interval. When fluids are pumped into a well, they naturally tend to flow into the zone with the highest permeability or least damage. Field experiences showed that there is no assurance of complete zone coverage without proper diversion. Therefore, diversion is recommended in all treatments, especially in extended reach and multi-lateral wells. Diversion techniques can be classified as mechanical or chemical. Mechanical control of treating fluid placement can be accomplished by coiled tubing with an inflatable packer, or with conventional straddle packers or ball sealers. Although mechanical techniques are very effective, they are more expensive and time consuming than chemical techniques and they are often not applicable or not effective in wells with open-hole completion. More importantly, mechanical means diverts treatment fluids from the wellbore; however, there is no control once the fluid enters the formation. Chemical diversion can be achieved through placing a viscous fluid, foam or gel to lower the penetration of treatment fluid in the created wormholes and their surrounding matrix, or a particulate carrying fluid, which creates a filter cake on the surface of the wormholes. This filter cake results in temporary skin effect which alters the injection profile. Gelled and foamed acids are also being used as a means of improving acid placement by combining stimulation and diversion in one step. Diversion is a critical step to ensure the success of matrix acid treatments. Understanding how chemical diverters interact with the formation rock and fluid is the key to selecting the proper product for a specific treatment. It is the intent of this paper to provide a technical overview of

mechanical and chemical diverters used in the oil industry. The various mechanisms by which these chemicals to achieve acid diversion, their application histories, and their limitations are presented. This paper provides guidelines for production engineers to optimize the fluid placement. Introduction Matrix acidizing in carbonates provides opportunity not only to remove or by pass damage in the vicinity of the wellbore, but to also improve the near-wellbore permeability by creating large flow channels (wormholes) with the acid dissolution. The chemistry of carbonate acidizing is much more straight forward than sandstone acidizing. The simplicity results form the fact that the rock is composed of calcite (CaCO3) and/or dolomite (CaMg(CO3)2). Their reaction products are soluble in the spent hydrochloric acid. However, the physics and engineering aspects of the carbonate acidizing process is much more complex.1 This is because the rock structure is significantly altered by the dissolution reaction, which increases the permeability contrast between the treated and the untreated zones. Unless effectively diverted, the treated region eventually becomes the sink for the acid and leaving other regions not adequately acidized. Therefore, one of the most important factors affecting the success or failure of a matrix acid treatment is the correct downhole placement of the acid for optimum zonal coverage.2 Though over the years there have been many products and techniques developed in the industry for acid diversion, the preferred ones generally have to possess the following characteristics: 1. Must not cause permanent damage to the formation. 2. The diverting agent must be compatible with the treating

fluids (overflush or displacement fluids) and formation brines.

3. Must clean up rapidly and completely when the well is put back on production.

4. The chemical and physical properties of the diverting agent must sustain at the bottom hole treating temperature.

Understanding how each acid diversion technique works is the first step towards the optimized carbonate acidizing design. Two techniques can be applied to achieve acid diversion. Mechanical diversion, including coiled tubing and utilizing rate and pressure during pumping; and chemical diversion. Combination of these techniques is often practiced for added efficiency.3

SPE 106444

Chemical Diversion Techniques Used for Carbonate Matrix Acidizing: An Overview and Case Histories Frank F. Chang and Xiangdong Qiu, Schlumberger, and Hisham A. Nasr-El-Din, Saudi Aramco

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The mechanical diverting technique uses zonal isolation tools such as packers to control the point of fluid entry; or uses ball sealers in the cased and perforated completion to selectively block some perforations (undamaged or that correspond to high permeability zones). The intention of using these methods is to divert treatment fluid right from the wellbore. It is also sometimes called external diversion. Though effective, setting packers often requires multiple stages of operations, which add time and cost to the treatment.4 In addition, placing isolation packers in open hole completion is not an easy task and may not be effective, especially if the hole is not gauged. Originally introduced in 1956, ball sealers are small spheres designed to seat in the perforations from the inside of the casing, thereby diverting injected fluids to other perforations.5 These balls are normally made of nylon, hard rubber, biodegradable materials such as collagen.6-8 Ball sealers are added to the treating fluids in stages to shut-off the perforations that are taking the largest quantities of fluids. Although they are widely used, several drawbacks limit this technique from providing consistent diversion. In addition to only applicable to cased and perforated wells, a sufficient rate must be available to maintain a differential pressure across the perforations to keep the balls in place. Their effectiveness is also impacted by the roundness and smoothness of the perforation holes and by the matching of the ball specific gravities with the treating fluid. Finally, for naturally degradable balls, e.g. biodegradable ball sealers, the timing of the degradation can adversely affect the sealing efficiency.4 Paccaloni and coworkers9 have developed a method of using the maximum pressure differential and injection rates (MAPDIR) to force the acid into low permeability zones. This technique involves pumping the treatment fluids at the highest possible rate without fracturing. Results show that the MAPDIR technique allows fast total skin reduction in terms of pumping time, but at the expense of large acid volumes injected into the layer with lower damage. Furthermore, it does not allow treating the low-permeability layer fully. Nonetheless, the MAPDIR is a physically sound technique. It is always practiced when a chemical diverter is used. Coiled tubing has become a widely accepted and routinely prescribed tool for well services and workover operations. Coiled tubing offers several advantages over the conventional bull heading treatments during a matrix acid stimulation. Performing acid treatment through coiled tubing avoids exposing the wellhead or completion tubular to direct contact with corrosive fluids. Spotting the treatment fluid with coiled tubing will ensure the delivery of the treatment fluid against the target sections. When combined with chemicals diverters10 and MAPDIR technique, coiled tubing provides much better chance for success in acid coverage. The drawback of the coiled tubing is that the tubing diameter is much smaller than that of the drill pipe or production tubing used for bull heading treatments. Therefore, the injection rate is limited in situations when sustained high rate and pressure are required. In addition, when treating long horizontal wells, extending coil tubing to the toe of the well requires tractors or vibrators,11-13 significantly increasing the complexity of the treatment execution.

The fundamental difference between a chemical and a mechanical diversion is that a chemical diverting agent achieves diversion by increasing flow resistance insides the created channels, whereas a mechanical diversion process controls the fluid entry point at the wellbore. Hence the chemical diverting agents can be considered as an internal diverting agent as opposed to the external mechanical diversion. It is the intent of the authors that by reviewing the application histories of various chemical diverting agents, an overview of the commonly used products can be provided so that more angles can be considered by the engineers when designing the acidizing jobs in carbonate reservoirs. Chemical Diverting Agents Foam, viscous gels, and particulates are commonly used diverting agents during matrix acidizing of carbonates. These materials reduce the fluid penetration rate in the created wormholes by increasing effective viscosity or allow plugging of the wormholes with finely sized solids. Foam Foam is a dispersion of a gas in a liquid with gas being the non-continuous phase and liquid is the continuous phase. Its stability is largely affected by the nature of the fluid that it contacts. Foams have been used for acid diversion since the 1960s.14 The acid itself can be foamed with the addition of gas and a suitable surfactant, or, more commonly, foam can be injected in alternating slugs with acid. Due to its profile control capability, foam has also been used in improved oil recovery (IOR) processes15 and in sealing leakage in gas storage reservoirs.16 Foam can be generated by injecting a surfactant solution into a porous medium and followed by gas injection. Or it can be created by co-mingled injection of a gas and a surfactant solution.17 The mixing energy provided by forcing the two phases through the porous medium is the dominant foam generation mechanism.18 As it flows through the porous medium, additional foam is generated. Its resistance to movement through the rock matrix increases until the pressure required for further flow exceeds the pressure required to break down other sections of the formation.14 There are many advantages of foam diversion. Foam blocking contains no solid material that could damage the formation permeability. Foam expansion, while flowing well back, helps clean well at lower reservoir pressure. Case history19 showed when treating many openhole water injection wells completed in Arab-D formation in Saudi Arabia the injection pressure gradually rose throughout the treatment giving a positive indication of diversion. The post stimulation injectivity increased from 26 to 112 BWPD/psi with improved water injection distribution profile. Viscous Diverter A viscous gel diverter uses its high viscosity or visco-elastic property to slow down the fluid penetration rate in the existing wormholes so that the acid following the diverter can have better chance to contact the rock in which wormholes have not formed. The viscous gels use either a polymer solution or a viscoelastic surfactant (VES).20-22 Polymer diverters leave residues after the gels break, potentially negating the stimulation by damaging the matrix or the surface the

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wormholes, especially if the volume is designed incorrectly. Surfactant-based gel is claimed to be non-damaging, however, the potential of gel not breaking or forming the emulsion with the reservoir oil are drawbacks of this material. Polymer-based systems have been used previously for blocking zones to help the gel plug reach the desired stiffness and the required isolation between intervals. One of Polymer-based systems Polymer Gel Diverter (PGD) has been used on field for many wells injection. The overall injection was more than 40% and the skin was reduced from +1 to 2.5.23 Another Polymer based Associative Polymer Technology (APT) also has been tested in field. Based on treatment-pressure response, the treatment using several stages of APT and acid appeared to divert the acid into sections of lower permeability. Oil production increased by 34% and the water cut decreased from 21 to 17%. Laboratory and field tests have shown that APT can divert acid from predominantly water-saturated zones to predominantly oil-saturated zones in carbonate formations.24 In addition to use alternating stages of acid/diverter, many polymer and VES systems can be prepared in acid. Increasing the viscosity of the acid causes elevated treating pressure when the acid reaches the formation. There high injection pressure thereby drives the acid into the lower permeability zones. This idea is similar to the MAPDIR concept. However, a much higher injection pressure is required than MAPDIR using straight acid in order to squeeze a more viscous acid into the lower permeability zones. The other drawback is the potential of damaging the lower permeability zones if the gelled acid is not efficiently broken. An improved technology of using viscosity control mechanism for acid diversion is an in-situ gelled acid. The major advantage of an in-situ gelled acid over conventional stimulation treatments is that less number of stages is required to achieve diversion since the acid provides the stimulation and diversion at the same time. An in-situ gelled acid uses unique polymer or surfactant chemistry to produce an acid system that has very low viscosity before reacting with the carbonate rocks. In-situ gelled acid has been shown to improve acid placement in carbonate reservoirs.10,25 The difference between an in-situ gelled acid and external gelled acid is that the external gelled acids or diverting gels are already activated on the surface. Thus, when they reach the formation face, the viscosity is the same against the high permeability and the low permeability rock. The proportion of fluid entering each zone is simply determined by the permeability contrast following the Darcys law. The in situ gelled acid offers the benefit of increasing viscosity inside the formation, therefore, when acid first enters the high permeability zone and generates wormholes, its viscosity becomes higher than the acid still in the wellbore. This creates an injectivity contrast, which provides extra resistance in the already treated high permeability region or in the wormholes, in turn it helps alleviate the severity of the permeability contrast. The result is that the acid has a better chance to enter the low permeability un-treated zone. The polymer-based in-situ gelled acid is prepared by gelling the HCl acid with a polymer and adding into the system a crosslinker.26-28 When the acid spends upon dissolving carbonate, the increase in pH causes the crosslinker

to activate and the gelled acid becomes crosslinked. This crosslinked gel temporarily blocks the wormholes being created and diverts acid elsewhere. Further increase in the pH value by complete spending of the acid causes the crosslink to break, the in-situ gelled acid hence breaks down to nearly water-like viscosity to assist easy flow back. Since the system contains polymers, even though the bulk fluid viscosity is dramatically reduced, there is still polymer residue,29,30 which can potentially plug the face of the wormholes. Viscoelastic Surfactants (VES) have been used in the industry for several stimulation applications. Due to the ability of surfactant monomer to associate and form certain structures under cretin conditions, it can increase the apparent viscosity and elastic properties of the treating fluids. A VES based in-situ gelled acid system can be prepared by adding a surfactant in the acid.13,31 Under the live acid state, the micellar structure does not cause the acid to form an elastic gel. As the acid spends in the formation, the pH increases and reaction products, CaCl2 and MgCl2, force the surfactant molecules to form rod-like micelles, which increase the viscosity and elasticity of the solution. The gel breaks when hydrocarbons contact the fluid during flow back. The surfactant leaves no residue on the wormhole surfaces and requires very low cleanup pressures. Due to its ease of clean up, the VES-based gelled can have a prolonged viscosity buildup without having to break back until the hydrocarbons flowback. This prolonged viscosity buildup provides additional benefit of sustained diversion. When reservoir fluid does not naturally break the VES based in-situ gel, a post flush of mutual solvent (ethyleneglycol monobutlyether) is recommended to ensure the breaking of the gel. One of field use of VES produced an average 1,600% OPD more than conventionally treated wells. In a second oil field, oil production increased by 4 to 5 folds. Also, several dead wells are now naturally producing up to 7,500% OPD after VES treatments. Since the volume of VES acid treatment is used less than polymer based acid, this makes VES acid operationally attractive to offshore environments. All the wells cleaned-up faster than wells treated with polymer systems.13 Although the VES based in-situ gelled acid has demonstrated its merits. Thorough lab testing is required to ensure the applicability to specific fields. The rheological properties of viscoelastic surfactant are a complex function of its type, concentration, pH, additives, salinity, temperature, shear rate and mixing procedure.32,33 A study showed the effect of acid additives and contaminants (mainly Fe3+) on the rheological properties of VES over a wide range of parameters (i.e. pH, temperature, and shear rate). It is observed that temperature, pH, shear conditions and acid additives have a profound influence on the apparent viscosity of the surfactant-acid system. Particulate Diverters Bridging agents or particulate diverters is a common chemical diverting technique used in carbonate formation. Particulate diverting agents are fine particles that form a relatively low-permeability filter-cake on the face. The pressure drop through this filter cake increases the flow resistance and diverting the acid to other part of the formation.

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There has been report of the injection of soap solutions could react with calcium chloride (CaCl2) to form water-insoluble, but oil-soluble, calcium soaps.4 The precipitate acted as a diverting agent for hydrochloric acid (HCl). The generation of solid precipitates in the formation was not, of course, desirable, because they could cause permanent damage. Thus, in the late 1930s, more sophisticated systems were used. Other systems utilized cellophane flakes suspended in a water gel with a biocide, later gels were replaced by oil-external emulsions. Oil-soluble naphthalenes, crushed limestone, sodium tetraborate, oyster shells, gilsonite, perilite, paraformaldehyde and chicken feed were used as diverters with mixed success. These compounds were replaced progressively by rock salt, which is partially soluble in the acid, but inexpensive and easy to handle. A major improvement of diversion techniques were brought about by completely soluble materials, including wax-polymer blends and hydrocarbon resins in production wells and rock salt and benzoic acid in water-injection wells. Benzoic acid flakes have one distinct advantage as a diverting agent: they are soluble in both water and oil. However, they can be used in low temperature reservoirs. Several researchers have found that mixing benzoic acid and rock salt in a 50/50 blend provided a very effective diverting material. The rock salt is soluble in spent acid and some formation fluids, and its dissolution simplifies the rate of solubility of the remaining benzoic acid. The size of diverter stage usually depends upon the size of the interval being treated. A common stage size is 1,000 gallons of carrier fluid. This stage will usually contain 1-2 lbs of sized diverting agent per gallon for diverting treatments over long intervals.34 Naphthalenes were first used as a blocking material in 1954. Oil-soluble naphthalenes were thought to be ideal diverters because they sublime above 175F.4 In 1956 Gilsonite was used as an oil-soluble diverting agent.4 The primary advantage of these materials is their good clean-up characteristics and that they can be used over a broad temperature range.35 However, most oil-soluble resins are not useful for acidizing in carbonates because the resin particles are not able to bridge the large flow spaces created by the reaction of the injected acid with the reservoir rocks. Recently solid organic acids such as lactic acid flakes have been used as a particulate diverting agent.36 This type of material hydrolyzes to release acid after the acidizing treatment under reservoir temperature. However, hydrolysis reaction requires sufficient water to ensure full conversion of the solids into acid. Otherwise, the solids remain and formation damage can be expected. Though the particulates are soluble in water or hydrocarbons, their removal requires exposure to the flowing stream when the well is put back on production. Otherwise, severe formation can occur to negate the stimulation results. Conclusions Effective diversion of reactive acid is necessary for efficient matrix acidizing in carbonates. Diversion in carbonates is more difficult than in sandstones because of the ability of acid to significantly increase the permeability in carbonates as it reacts in the pore spaces and flow channels of matrix.

Although mechanical techniques are very effective, they are more expensive and time consuming than chemical techniques and they are often not applicable nor effective in open-holes. The best diverting technique for a specific field is not necessarily the best for other fields. It is crucial to understand the geological characteristics and the petrographical properties of the reservoir when designing the acidizing treatment by incorporating the fit-for purpose diverting techniques. The properly designed diversion should retain effective blocking of fluid into the high permeability zone throughout the treatment, but the diverting agent is rapidly and completely removed during flow back. Acknowledgments The authors would like to thank Saudi Aramco and Schlumberger for the permission to present and publish this paper. The authors would also like to thank Abdullah S. Sultan for many useful discussions. References

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