SPE 165091 A Relative Permeability Modifier for Water Control: Candidate Selection, Case Histories, and Lessons Learned after more than 3,000 Well Interventions Julio Vasquez and Larry Eoff, Halliburton Copyright 2013, Society of Petroleum Engineers This paper was prepared for presentation at the SPE European Formation Damage Conference and Exhibition held in Noordwijk, The Netherlands, 5–7 June 2013. 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 have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper 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 SPE copyright. Abstract Excessive water production can detrimentally affect the profitability of hydrocarbon producing wells and limit their economic life. Relative permeability modifiers (RPMs) were introduced to the oil and gas industry more than two decades ago as an option to selectively reduce water production. This type of treatment became appealing to operators because of its simplicity of deployment requiring no zonal isolation (i.e., bullhead-type treatments). However, RPM treatments have their limitations, and proper candidate selection is the key to a high success ratio. This paper discusses the application of a unique RPM system developed for water control. This RPM system is based on a hydrophobically modified water soluble polymer (HRPM) that, once adsorbed to the surface of the rock, selectively reduces water effective permeability with little to no damage to oil or gas production. The hydrophobic modification to the base polymer chain adds unique associative properties to the system. In contrast to porosity fill-sealants (i.e., crosslinked polymer gels), HRPM treatments only provide a restriction to water flow. The following parameters are discussed: (1) HRPM performance testing, (2) candidate selection criteria, (3) design considerations and best practices for field implementation, and (4) case histories. To date, more than 3000 treatments have been performed with this HRPM system. A wide variety of case histories are highlighted in this paper discussing different types of reservoirs, wellbore completions, and water production mechanisms, among others. In addition to water control, the application of this HRPM system has been extended to hydraulic fracturing, acid stimulation, and overbalanced workover interventions. Case histories are examined. Often, RPM treatments are applied in reservoir/wellbore conditions outside of their operating capabilities. One of the main objectives of this paper is to assist operators with the candidate selection process for this particular HRPM treatment. Introduction A fundamental objective of the production and operation of hydrocarbon reservoirs is to maximize the recovery factor, while, at the same time, attempting to keep initial investment and operating expenses at the lowest level required to obtain this recovery. However, the produced hydrocarbons are often accompanied by large amounts of undesired water production that can impact the hydrocarbon production and the overall profitability of the well. RPMs have been used by the oil and gas industry for more than two decades with some degree of success to selectively reduce excessive formation water production. As previously stated, RPMs became appealing to operators because their deployment requires no zonal isolation (i.e., bullhead-type treatments). RPMs are typically dilute polymer solutions that perform by adsorption onto the pore walls of the formation flow paths. Several of such polymer systems have been promoted throughout the years, and a large volume of literature has been devoted to this topic (Weaver 1978; Dunlap et al. 1986; Seright 2006). This paper discusses the application of a novel HRPM system that was originally developed for water control; however, its application has also been extended to hydraulic fracturing, acid stimulation, overbalanced workover interventions, and waterflooding (Vasquez and Eoff 2013). Description of the RPM System This HRPM system uses a hydrophobically modified polymer initially developed for water-control applications in hydrocarbon-producing wells (Eoff et al. 2003). The polymer attaches to the surface of the rock immediately as it enters the 2 SPE 165091 formation matrix by simple electrostatic attraction. Once the polymer is attached to the surface of the rock, it selectively reduces the permeability to water-based fluids with little to no effect to hydrocarbon permeability. Treating solutions of the HRPM system exhibit low viscosity, typically less than 2 cp. The hydrophobic modification of the water-soluble polymer allows multiple layers of the polymer to build up because of the association of the hydrophobic groups (Fig. 1). These materials offer improvements to the hydrophilic polymers traditionally used for permeability modifications. For example, hydrophobic modification appears to improve cleanup of the polymer that penetrates an oil- or gas-saturated zone, resulting in less risk of damage to hydrocarbon permeability. Hydrophobic modification also increases reduction to water flow compared to the unmodified polymer (Eoff et al. 2003, 2004). Fig. 1—RPM system base polymer; the hydrophobic modifications allow the polymer to build up because of the association of the hydrophobic groups. HRPM Selective Permeability Reduction. Once the polymer is attached to the surface of the rock, it significantly reduces the permeability to water-based fluids with little to no effect to hydrocarbon permeability. This selective permeability reduction to aqueous-based fluids includes formation water, injection water, completion brine, etc. Fig. 2 illustrates a typical core flow test designed to demonstrate the selective permeability reduction properties of the HRPM system. In this test, regained permeability to water and oil were evaluated using an Aloxite core with the following test sequence: water–oil– water–HRPM system (1 pore volume [PV] injected, 2000 ppm)–water–oil. The evaluation water was API brine (9% NaCl and 1% CaCl2), and the evaluation oil was kerosene. The test was conducted at 120°F. The treatment resulted in 96% reduction to water permeability (4% regain), maintaining constant water flow for two days following the treatment. After this stage, oil flow was resumed and resulted in 95% regained oil permeability. Fig. 2—HRPM system regained-permeability test (2,000 ppm HRPM at 120°F). The HRPM system performance was also validated in a 10-ft sandpack. The test setup allowed measuring the permeability variation at 12 different segments throughout the length of a 10-ft long sandpack. Initial permeability to water averaged 143-md. Then, the sandpack was treated using 1 PV of a 2000-ppm HRPM solution injected at 1-mL/min. The HRPM system showed excellent penetration and permeability reduction to water throughout the length of the sandpack (Fig. 3). This test result is important because it confirmed that the HRPM can effectively penetrate deep into the matrix of the rock. SPE 165091 3 Fig. 3—Permeability reduction vs. depth of penetration in a 10-ft sandpack (2,000-ppm HRPM solution injected at 1 mL/min, 1 PV). Candidate Selection Criteria for HRPM System This section provides guidance regarding when and where the HRPM system can be successfully applied for use in either oil or gas production wells. Candidate selection criteria for RPM systems have been amply documented in the literature (Sydansk and Seright 2006; Botermans et al. 2001; Pietrak et al. 2005). However, it is important to understand that the RPM systems commercially available to the oil industry have different working mechanisms and are applicable to different reservoir/wellbore conditions. The ideal candidate for a RPM treatment is a multilayered formation in which water and hydrocarbons are being produced from separate zones. Ideally, these zones should not be in pressure communication because of impermeable barriers (i.e., shale streaks) separating each layer. Fig. 4 illustrates this scenario in which there are three different sandstone intervals separated by shale barriers. While the three zones had initially high hydrocarbon saturation, the zone in the middle depleted faster and eventually watered out to almost residual oil conditions. The HRPM treatment is designed to cover the three producing intervals (7 to 10-ft radial penetration). As with any water-based treatment, the HRPM treatment will follow the path of least resistance; that is, most of the treatment will travel into the highest-permeability zone, regardless of the fluid saturation of each interval. When the treatment enters the formation in the watered-out zone, it significantly reduces the permeability to water. However, when the treatment enters the other two highly oil-saturated zones, there is little to no effect to hydrocarbon permeability after the flowback period. Fig. 4 illustrates two zoomed pictures of polymer adsorption in the oil and water zones. In the water zone the polymer layer is fully hydrated, effectively decreasing the size of the pore throat and restricting the flow of water. In the oil zone, due to its overall hydrophilic nature, the polymer layer tends to shrink in the presence of oil flow, and offers minimal resistance to the flow of oil. Single pay zones with high mobile water saturation (Fig. 5) are generally not considered good candidates for RPM treatments. After the RPM treatment, water and oil will continue to flow to the wellbore in the same water/oil ratio as before the treatment, but most likely at a reduced total fluid production rate. When the water/oil flow reaches the treated zone, water flow might be impeded while oil flow is not impeded. This could result in an increase in the water saturation, which, in turn, results in a decrease of oil permeability. In such a scenario, the overall production from the well will decrease at the same water cut as before the treatment. With the HRPM described in this paper, laboratory testing has shown that oil flow removes the effect of the polymer treatment, meaning that, following oil flow, water permeability is no longer decreased. Thus, the expected outcome of treating a single pay zone is ultimately no change to the water-oil ratio (WOR) or water cut. Another scenario is multiple pay zones with reservoir crossflow (no impermeable barriers between zones) (Fig. 6). Again, in general, RPM treatments are not considered applicable to this situation. Initially, the treatment might result in reduction of water with no effect on oil. However, because of vertical permeability, when the water reaches the treated zone, it can travel up (or down) into the oil zone. Once it reaches the treated zone there, the same situation as described for a single pay zone could occur. However, as also described, because oil flow seems to remove the effect of the HRPM, this scenario could prove beneficial, at least for short-term reduction of water production, for the HRPM. Water coning also fits into this scenario. It 4 SPE 165091 has been amply documented in the literature that water coning can be more adequately controlled with porosity fill sealants, such as polyacrylamide crosslinked gels (Vasquez et al. 2006). However, some degree of success has been achieved with the application of the HRPM in coning situations. Case histories are shown. Fig. 4—Ideal Scenario for a RPM treatment Fig. 5—Single pay zone with high-mobile-water saturation; not a good candidate for RPM (or HRPM) treatments. SPE 165091 5 Fig. 6—Multiple pay zones with reservoir crossflow. It is important to highlight that the HRPM system has been designed to reduce water production that is flowing through the “matrix” of the rock. Therefore, the following conditions should be considered: • Good zonal isolation behind the casing must be present. If there is channeling behind the casing, the well would not be a good candidate for an HRPM treatment. • No natural fractures or fissures should be present. HRPM treatments can reduce water permeability in matrix flow up to 6,000-md, but is ineffective in fracture flow. • It is strongly advised to perform compatibility testing with the HRPM and formation fluids. In a few instances, it has been determined that a surfactant is required in the HRPM to resolve an incompatibility/emulsion issue. • HRPM treatments should be pumped at matrix rates, never exceeding fracturing pressure. • Attempting to control water production in a previously fractured zone is probably one of the most challenging scenarios for water shutoff treatments. The application of sealants (i.e., crosslinked polymer gels) in this scenario is risky because there is no control of where the treatment will go as a result of the high conductivity of the fracture. HRPM treatments have been successfully applied in previously hydraulically fractured wells. The key point in this type of treatment is that the HRPM treatment must be overdisplaced past the proppant pack volume. The HRPM will only be effective in the matrix of the rock, not in the proppant sand, so the overflush volume must be adjusted to account for the PV of the total proppant present in the formation. • RPM treatments also have been successfully applied in wells completed with gravel packs, frac-packs, slotted liners, standalone screens, etc. The HRPM system does not degrade under high shear conditions. • In oil-wet formations, HRPM treatments must be preceded with a solvent-based stage to change the wettability of the formation to water-wet so that polymer can effectively adsorb to the surface of the rock. The same recommendation applies if the formation has paraffins or asphaltenes deposition. Case histories are shown. HRPM Treatment Design—Volume and Polymer Concentration The HRPM treatments are typically designed to reach 7- to 10-ft radial penetration into the matrix of the rock. The volume design is simply a volumetric calculation and is given by Eq. 1: [ ] Φ 2 2 VTreatment = π ⋅ h ⋅ (rtreatment ) − (r wellbore/ 12) ................................................................................ (1) 100 where Vtreatment is the volume of the HRPM treatment in gallons, h is the thickness of the zone to be treated in ft, f is the average porosity of the rock as a percent, rwellbore is the wellbore radius in inches, and rtreatment is radial penetration of the treatment into the matrix of the rock in feet. Fig. 7 can be used as a reference point. 6 SPE 165091 Fig. 7—HRPM volume design vs. formation average porosity (7- to 10-ft radial penetration). The HRPM system is a “matrix” treatment (up to 6000-md). Depending on the average permeability of the interval to be treated, two different molecular-weight HRPM versions were developed as follows: (1) standard HRPM (20-md < k < 6000md) and (2) low-molecular-weight (LMW) HRPM (0.01-md < k < 20-md) for improved injectivity in low-permeability formations. Polymer concentration is dictated by the average permeability of the treated interval and bottomhole temperature (BHT) (Fig. 8). Fig. 8—Polymer concentration vs. permeability at a given temperature. HRPM treatments are typically placed into the formation using bullhead injection (no mechanical zonal isolation required), which makes this type of systems appealing to operators. HRPM systems have also been deployed by means of coiled tubing (CT). In treatments involving high volumes of the HRPM system, the polymer has been added on-the-fly as it goes immediately into solution (no hydration time necessary) once added to the mixing brine water (i.e., 2% KCl). SPE 165091 7 Case History 1. Well 1 is a cased-hole and perforated wellbore producing from an onshore laminated sandstone oil reservoir in Latin America. This well was completed in 15 different zones (681-ft gross interval, 155-ft of net perforations) with the following properties: 20°API oil, average permeability ~195-md, average porosity ~13%, and BHT~280°F. Water production had been a major challenge in this reservoir, limiting the economic life of many wellbores. No natural fractures were present in this reservoir. Production rates for Well 1 before the RPM treatment were reported as 1200-BFPD, 260-BOPD, 960BWPD, and 80% water cut. Good zonal isolation behind the casing was confirmed. Additionally, Well 1 had never been fractured stimulated. Fig. 9 shows the wellbore schematic and the results of a production logging tool (PLT) run performed before the RPM treatment. Although the PLT clearly identified the intervals contributing to most of the water production, the same intervals were also producing a significant amount of oil. For instance, Zone 9 was producing approximately 44% of the total water production, but it was also accounting for 19% of the oil production. The operator opted not to consider “sealant” chemical treatment options (i.e., crosslinked polymer gels) because of the risk of losing this oil production. This reservoir had a well-documented history of organic deposits that affected the production life of Well 1. Because of this condition, a solvent-based treatment was pumped ahead of the HRPM treatment to remove any paraffin or asphaltene deposits that could prevent the polymer from effectively adsorbing to the rock surface. The treatment consisted of pumping 180-bbl of the HRPM (at 3600-ppm polymer concentration) deployed through a 2-in. CT unit. The treatment was designed to reach a theoretical radial penetration of approximately 7-ft. After the HRPM treatment, Well 1 began producing at 2400BFPD, 1560-BOPD, 840-BWPD, and 35% water cut. Two months later, production had stabilized to 850-BFPD, 510-BOPD, 340-BWPD, and 60% water cut. Fig. 9—Well 1 wellbore schematic and PLT before HRPM treatment. Case History 2. Well 2 is a cased hole and perforated dual completion wellbore (Fig. 10) producing from an offshore multilayer sandstone oil reservoir located in the Asia Pacific region. The short string of the well was producing from six different zones (479-ft gross interval, 78-ft net perforated interval, 49o maximum inclination angle, gas artificial lift) with the following properties: average permeability ~50-md, average porosity ~30%, and BHT~185°F. Because of excessive water and CO2 production, this well had to be shut-in in 2009. The last reported production rates were 54-BOPD, 1.5-MMscf/D gas, and 95% water cut. Two of the sand intervals were believed to be watered-out based on offset producers. To control the undesired water production, an HRPM treatment was performed on this well by bullheading 340-bbl at 2000-ppm polymer concentration. In this particular case, the treatment volume was designed to reach 5-ft radial penetration because of barge space limitations and logistics. After the treatment, production was resumed at 339-BOPD, 0.8-MMscf/D gas, and 2% water cut. Oil production had a six-fold increase, while the water production was decreased from 95 to 2%. It is important to mention that this significant reduction in water cut is not typical of a RPM treatment. For this particular case, the high-water-producing intervals were totally inhibiting the oil from other zones. By reducing the water production from these zones (watered-out zones) other zones with high oil saturation were allowed to begin producing. 8 SPE 165091 Fig. 10—Well 2 wellbore schematic. Case History 3. Well 3 is a cased-hole and perforated wellbore producing from an offshore laminated sandstone oil reservoir in West Africa. This well was producing from eleven different zones with a sliding sleeve device (SSD) completion. Well 3 was producing under gas artificial lift and had a maximum inclination angle of 61o. Before the HRPM treatment, only one SSD was open, from which three sand intervals were contributing to production (Fig. 11). The top two sands had similar petrophysical properties (average permeability ~399-md and average porosity ~26%, 16-ft of net perfs) from the bottom sand interval (average permeability ~982-md and average porosity ~30%, 10-ft of net perfs). Average BHT was 137°F. Because of the SSD completion, it was not possible to perform a PLT to determine the interval mostly contributing to water production. However, based on offset producers, the bottom sand interval was believed to be watered-out. Production rates before the treatment were 525-BOPD, 1092-BWPD, and 67% water cut. Fig. 11—Well 3 wellbore schematic and formation evaluation. The HRPM treatment was batch-mixed on location, stored in tanks for two days, and then transported to location. The treatment consisted of bullheading 55-bbl of the HRPM system at 2000-ppm polymer loading. The treatment volume was designed to reach only 4-ft radial penetration. After the treatment, production rates were reported as 777-BOPD, 978-BWPD, and 56% water cut. As mentioned, the recommended radial penetration for the HRPM treatment is 7 to 10-ft into the matrix SPE 165091 9 of the rock; however, even 4-ft radial penetration was enough to achieve this significant reduction in water cut with an additional +200-BOPD. Case History 4. Well 4 is an oil producer from an onshore laminated sandstone reservoir in Latin America. This well was completed with an openhole standalone screen, covering a gross interval of 264-ft with approximately 106-ft of pay zone, as Fig. 12 illustrates. This formation had the following petrophysical properties: 10° API crude oil, average permeability ~436md, average porosity ~20%, and BHT~240°F. Natural fractures were not present in this reservoir. Before the treatment, this well was producing at 95% water cut. The HRPM treatment consisted of bullheading 400-bbl at 3000-ppm polymer concentration. Because this well was producing with an electric submersible pump (ESP), the treatment was pumped down the annular space. A solvent-based treatment was pumped ahead of the HRPM treatment to remove any paraffin or asphaltene deposits that could have prevented the polymer from effectively adsorbing to the rock surface. The treatment was overdisplaced with 620-bbl of brine. After the treatment, water cut was reduced from 95 to 75%, with a significant oil production increase for at least six months. Fig. 12—Well 4 wellbore schematic and formation evaluation. Case History 5. Well 5 is an oil producer from a laminated sandstone reservoir in the Asia Pacific region. This well had an openhole gravel pack (OHGP) completion with a maximum inclination angle of 52°. The OHGP section was approximately 300-ft. The well was shut-in because of excessive water production (98% water cut). Because of the inability to accurately identify the water production intervals and the limitation on placement options attributed to the completion, a RPM treatment was decided to be implemented. The treatment consisted of pumping 322-bbl of the HRPM system (at 2000-ppm) through a CT unit. Because of the long targeted interval, the treatment was designed to reach only 3-ft radial penetration (rather than the recommended 7- to 10-ft). The treatment was overdisplaced with 98-bbl of brine. As expected during HRPM treatments, a pressure increase was observed as the system began being injected into the formation. After the treatment, water cut was successfully reduced from 98 to 65%, with a significant increase in oil production. Case History 6 (Farrera 2007). Well 6 is a cased-hole and perforated wellbore producing from an onshore sandstone oil reservoir in Latin America. This well was completed in a single sandstone pay zone (16-ft of perforations) that had a highmobile-water saturation underneath (Fig. 13). The interval had the following petrophysical properties: average permeability ~50-md, average porosity ~22%, and BHT ~160°F. Well 6 began producing water-free in February 2002. In August 2002, gas artificial lift was implemented in the wellbore, which resulted in an increase of oil production, but also in a gradual increase of water production, indicating the possibility that this increase in drawdown pressure induced a coning effect on the high-mobile-water saturation zone below the perforated interval. The operator considered two options: Option 1. Conventional Intervention with Workover Equipment: • Remove wellbore completion. • Perform a squeeze job in the current perforated interval. • Perform logging run to identify current water-oil-contact (WOC) and then create perforations at this depth to deploy a deep-penetrating sealant to slow down the coning effect. If WOC is not clearly identified, perform the same treatment at the base of the original perforated interval. • Perforate the top of the original producing interval. • Bring down the production tubing and resume production. 10 SPE 165091 Option 2. Bullheading the HRPM Treatment (No Zonal Isolation Required). There was a substantial difference between the cost associated with the HRPM treatment and the other option requiring workover equipment (Fig. 14), a savings of 79% with the bullhead-type treatment. The treatment consisted of bullheading 252-bbl of the HRPM system at 2000-ppm polymer loading (11-ft radial penetration). After the treatment, production rates stabilized at 104-BOPD, and 58% water cut (2 months after). Six months after the treatment, Well 6 had a total gain of 82% in oil production and a 47% decrease in water production (Fig. 15). At the end of the six months, water cut appeared to be increasing again, but at a slower pace. This behavior was not attributed to the HRPM actually degrading or breaking down under reservoir conditions; it was attributed to the water front traveling around/bypassing the HRPM treatment and making it into the perforations again. Fig. 13—Well 6 wellbore schematic and formation evaluation. Fig. 14—Well 6 well intervention options: (1) conventional workover treatment vs. (2) HRPM treatment. SPE 165091 11 Fig. 15—Well 6 production rates before and after the HRPM treatment. Case History 7 (Gutierrez 2007). Well 7 is a cased-hole and perforated wellbore producing from an onshore sandstone gas reservoir in Latin America. This well was producing from a single sandstone zone (65 ft of perforations, 265-ft gross interval) with the following properties: average permeability ~100-md, average porosity ~18%, and BHT~115°F. Well 7 began producing in 1979 and produced water-free for more than 20 years. In 2003, water production began increasing up to 40-BWPD, drastically affecting gas production and inducing sand control problems as well. The lower perforations were isolated with a conventional cement squeeze. Water production was controlled; but, as expected, after six months, water returned to previous levels (Fig. 16) (no shale barriers were present to separate the gas zone from the mobile-water saturated zone). This well was producing at 720-Mscf/D and 30-BWPD before the treatment. At this stage, this formation was considered a low-pressure, depleted reservoir. The treatment consisted of injecting 50-bbl of the HRPM system at 2000-ppm polymer loading (2.76-ft radial penetration, below the recommended treatment penetration) deployed through a CT unit. After the treatment, this well produced waterfree for more than two years while maintaining a steady gas production of 600-Mscf/D (Fig. 17). Fig. 16—Well 7 wellbore schematic and production history before HRPM treatment. 12 SPE 165091 Fig. 17—Well 7 production history after HRPM treatment. Case History 8 (Peano 2007). Well 7 is a cased-hole and perforated wellbore, previously hydraulically fractured, producing from an onshore sandstone gas reservoir in Latin America. This sandstone gas reservoir had the following characteristics: average permeability ~0.045-md (before fracturing), average porosity ~16%, and BHT ~207°F. Because of the low permeability of this formation, most of the wells in this field had been hydraulically fractured to make gas production economically feasible. Well 8 was perforated to produce from two sandstone intervals (56-ft of total perfs, 122-ft gross interval) (Fig. 18). Both intervals were fracture stimulated, yielding the following production rates: 0.386-MMscf/D gas and 457-BWPD. Based on the formation evaluation, it could be observed that there was high water saturation adjacent to both perforated intervals. It was believed that these zones were intersected during the fracturing operation and contributed to the high levels of water production, which was detrimentally affecting the gas production of the well. After a few days of production, both gas and water rates dropped. The well was then shut-in and put on production again, which resulted in increased gas and water rates that fell very quickly once again. Based on the behavior of the production rates, it was decided to perform an HRPM treatment to decrease water production. Given that this particular well had been previously hydraulically fractured, the treatment was designed to overdisplace the HRPM system past the proppant pack into the matrix of the rock to selectively reduce water production with no effect to the gas production. Treatment consisted of bullheading 150-bbl of the HRPM system at matrix rates and was overdisplaced with 2% KCl water. Immediately following the treatment, the water production fell from 457 to 114-BWPD. Gas production increased from 0.386 to 0.484-MMscf/D. These numbers translated into a 75% reduction in water production and 25% increase in gas production. The water-gas ratio (WGR) decreased from 1184 to 235-BWPD/MMscf/D. Even one year after the treatment, the gas production held constant at 460-MMscf/D and the water production to 100-BWPD, illustrating the longevity of the system. Fig. 18 —Well 8 wellbore schematic and formation evaluation. SPE 165091 13 Conclusions • The HRPM selectively reduces the permeability to water-based fluids with little to no effect to hydrocarbon permeability. • In contrast to porosity fill sealants (i.e., crosslinked polymer gels), HRPM treatments only provide a restriction to water flow. • The ideal candidate for a RPM treatment is a multilayered reservoir in which water and hydrocarbons are being produced from separate zones, where water production is mainly being produced from one zone. • The HRPM treatments are typically designed to reach 7- to 10-ft radial penetration into the matrix of the rock. • The hydrophobic modification of the HRPM system allows multiple layers of the polymer to build up because of the association of the hydrophobic groups, allowing improved cleanup of the polymer that penetrates an oilsaturated zone and increased reduction to water flow compared to the unmodified polymer. • More than 3000 treatments have been performed with this HRPM system for water control, hydraulic fracturing, acid stimulation, and overbalanced workover interventions. 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