This paper (SPE 52503) was revised for publication from paper SPE 37220, first presented at the 1997 SPE International Symposium on Oilfield Chemistry held in Houston, 18-21 February. Original manuscript received for review 18 February 1997. Received manuscript revised 27 June 1998. Revised manuscript approved 5 August 1998. Summary The gelation behavior of a polyacrylamide/aluminum citrate colloidal-dispersion gel (CDG) system was investigated in sandpacks at frontal advance rates of 2 ft/D. A gelatinous mass formed where the gelant encountered a change in flow medium. Permeabilities of homogeneous media were reduced only by factors that were similar to those obtained with a polymer displacement alone. A laboratory investigation of a polyacrylamide/aluminum citrate CDG system was conducted to determine whether the system develops in-depth permeability modification in unconsolidated sandpacks. The study includes flow of the polymer and in-situ gelation behavior of the gelant in porous media and aggregate growth during the gelation reaction in beakers. Flow experiments were conducted in long unconsolidated sandpacks in which the gel solution was mixed in-line before injection. Injection rates were designed to provide adequate residence time for the gel solution to develop in-situ flow resistance during displacements based on bulk gel characterization tests. Residual resistance factors were determined following a static rest period in which the sandpack was left saturated with the injected gel solution. For comparison, apparent viscosity and residual resistance factors were also determined for the polymer flowing through unconsolidated sandpacks. Membrane dialysis was used to study the aggregate size distribution of the gel system at selected times after mixing. In-depth in-situ flow resistance did not develop when the gelling solution was injected into the sandpacks at frontal advance rates of 2 ft/D. Propagation through the sandpack was similar to a polymer solution. Flow resistance was characterized by the formation of a gelatinous filter cake, which formed when the injected solution encountered a change in flow medium, such as a screen placed at the ends to retain sand in place, the interface between the 50-mesh coarse sand layer at the inlet and the rest of the sandpack, and void spaces. Delaying injection by 2 hours after mixing in-line (to simulate field conditions) resulted in severe front-end stripping of gel aggregates. In all cases, residual resistance factors for the gel solution were similar to those obtained with a polymer displacement alone. Effluent fractions from gel solution displacements never developed a gel structure, and their viscosities were significantly lower than the injected solution. In the study of gel size distribution, aggregates were not detected at reaction times of 4 and 8 hours. P. 337

Summary Chromium acetate-hydrolyzed polyacrylamide gel systems are applied in fractured reservoirs for conformance control. A portion of the gelant leaks off into the adjoining matrix during placement of the gelant in the fracture. This paper describes an experimental study on the effect of fluid leakoff on the performance of a gel treatment. The stability of a gel that is placed in a fracture and is subjected to a pressure gradient was also investigated. Physical models of a fracture were developed to conduct displacement experiments. The models were fractured Berea sandstones designed to permit leakoff of the gelant into the matrix on the sides of the fracture. A polyacrylamide-chromium acetate gelant was injected into the fracture under conditions in which there was leakoff and no leakoff into the matrix. A gel did not form, and the gelant was easily displaced from the fracture by subsequent brine injection when the gelant was placed without leakoff. When the gelant was placed with leakoff, a gel formed in the fracture after placement and provided significant flow resistance. It is hypothesized that the lack of gelation in the absence of leakoff was caused by diffusion of chromium from the fracture to the matrix. Diffusion reduced the chromium concentration in the gelant to levels at which gelation would not occur when the gelant was placed without leakoff. It was discovered that gels that were formed in a fracture ruptured when a brine pressure was applied at the inlet. The pressure where rupture occurred was determined for gels placed in tubing of various lengths and diameters. The rupture pressure was proportional to a length/diameter ratio. Introduction Fractures occur in hydrocarbon reservoirs for various reasons and at a variety of scales. In addition to natural fractures, the reservoir around oil wells may be hydraulically fractured to improve production. Over pressuring and thermal stresses during water injection also cause fractures. During waterflooding of a fractured reservoir, most of the water may bypass the matrix and preferentially flow through channels consisting of a single fracture or an interconnected network of fractures. The consequence is additional cost for handling of excess water, and an incomplete recovery of oil from the reservoir. One remedy is injection of a gelant into the fracture that reacts to form an immobile gel. The immobile gel then diverts injected water to previously unswept portions of the reservoir. Investigators have studied the application of gelled polymer treatments to fractured systems. Sydansk1 presented detailed laboratory testing and evaluation of a Cr(III)-partially hydrolyzed polyacrylamide gel system for fracture applications. Seright2 studied the performance of several immature, preformed, and mechanically degraded gels by displacing them through fractured cores. Immediate breakthrough of the tracer after treatment of the core with immature gel was observed, indicating poor performance of the gel to divert flow into the matrix. Similar experiments with mature gel resulted in delayed breakthrough of the tracer, indicating sweep improvement. Seright concluded that superior diversion can be obtained by injecting mature gel (rather than gelant) in the fracture. Seright3 also studied the placement of preformed Cr(III)- partially hydrolyzed polyacrylamide gel in fractured Berea core. He investigated the pressure drop, the gel dehydration, and the delay in gel propagation that occur during the flow of preformed gel through fractured cores. Dehydration and leakoff of water concentrated the gel in the fracture. The gel injected at a later stage of extrusion made wormholes through the thickened gel to reach the fracture outlet. During placement of an immature gel (referred to here as a gelant) through a fracture, some of the gelant leaks off to the adjoining matrix. The effect of leakoff on the strength of gel placed in a fracture was not studied previously. The objectives of this research were to study (a) the role of leakoff on the performance of a gel placed in a fracture and (b) the ability of a gel formed within a fracture to resist failure when subjected to an imposed brine pressure. Experimental Details Fracture Models. Three types of fracture models were used for displacement experiments: fractured slabs, fractured cores, and slots. The slabs and cores contained one fracture and were constructed to provide for leakoff from both sides of the fracture to the adjoining matrix. The slot was constructed from a saw-cut rock and an acrylic wall. A schematic of the fractured slab and associated fluid ports is shown in Fig. 1. Slabs cut from Berea sandstone were 10 in. long, 2 ft wide, and 1 in. thick. Each slab was fractured along the 10 in. length using a Hydrasplit (Park Industries Inc., St. Cloud, Minnesota) rock splitter. Spacers were placed between the two symmetric halves to establish a fracture aperture of known width. The top and bottom of the fracture were then sealed with an epoxy coating. Acrylic fluid ports were installed across the fracture aperture at the front and back faces to allow flow through the fracture. Acrylic side plates were installed on each side of the matrix opposite the fracture. The side plates were milled to provide an aperture between the plate and the smooth face of the slab. Ports at each end of the side plates provided for fluid withdrawal from each side of the slab. The slab was sealed by coating the top, bottom, front, and back surfaces with epoxy. Pressure ports were installed at the inlet and outlet ends of the fracture. Details of the slab preparation process are found in Ref. 4. Each slab was initially saturated with 1% NaCl brine. Permeability of the fracture was determined by flowing brine at constant flow rates through the fracture with the side outlets closed. Aperture width was estimated using the theory of flow between two parallel plates. Matrix permeability was determined by injecting brine into the fracture and measuring the flow rate at the matrix (side) outlets and pressure differentials across the matrix sections. Pore volume of the matrix was determined from tracer runs. A step change in concentration of potassium iodide was introduced into the fracture, and the effluent concentrations from the matrix (side) outlets were monitored using a UV spectrophotometer. The slabs had permeabilities of about 200 md and an average porosity of 0.17. Some slabs were cleaned and reused in other runs.

Summary Chromium(III)-polymer systems are often used in permeability modification treatments. The transport of chromium(III) in-depth in porous rocks is sometimes limited due to precipitation. Precipitation is caused by the increase in the solution pH because of fluid-rock interactions, particularly in carbonate rocks. This paper presents experimental data on the rate of precipitation of chromium from chromium(III) acetate solutions. Experimental data were obtained for the precipitation of chromium from chromium acetate solution at constant pH. Data were obtained as a function of pH, temperature, salinity, and OAc/Cr mole ratio. The pH range studied was between 7 and 10, and the temperature range was between 25 and 45°C. Precipitation of chromium was preceded by an induction period where there was no change in concentration. The induction period decreased from 1,200 minutes at pH 7 to less than 200 minutes at pH 10 at 2°C. A higher temperature increased the precipitation rate. Precipitation is delayed by the addition of acetate ion. Both the salinity and salt type have significant effects on the rate of precipitation. A kinetic model was developed to describe both the induction period and the rate of precipitation of chromium from a chromium acetate solution in 1% KCl at 25°C for a pH range of 7 to 10 with OAc/Cr mole ratios between 3 and 9. Background Several investigators1–4 have studied the application of chromium-crosslinked gel systems to carbonate (or carbonate-containing) reservoirs. Results showed that the polymer propagates through carbonate (or carbonate-containing) rock but poor propagation was observed for chromium(III). It was concluded that the retention of chromium was caused by precipitation brought on by the elevated pH environment because of the dissolution of carbonates into the injected fluids. This interpretation is supported by solubility calculations of chromic hydroxide. Fig. 1 shows the solubility of chromic hydroxide using solubility constants from Rai et al.5 McCool et al.1 studied the interaction between dolomite cores and xanthan-chromium(III) gel systems. Significant amounts of chromium(III) precipitated when chromium was injected as a chromium acetate solution. McCool et al. concluded that the chromium was retained due to precipitation at elevated in-situ pH levels. Seright2 studied the propagation of chromium acetate and chromium chloride in Indiana limestone cores. More chromium propagated when the counter-ion was acetate. Seright suggested that chromium was removed from solution by precipitation. Stavland et al.3 found precipitation was the primary mechanism for chromium retention in Berea and Brent sandstone cores. Precipitation was caused by the dissolution of carbonate minerals that increased the pH of the injected solution. The pH of unbuffered solutions that are injected into dolomite matrix rock has been shown to increase due to carbonate dissolution.6 Carbonate dissolution and the corresponding effect on pH behavior in carbonate rock were studied by injecting potassium chloride brine at selected pH values through a 6-in.-long Baker dolomite rock. The pH and magnesium concentration in the effluent (for contact times of a few hours) as a function of the pH of the injected potassium chloride brine are shown by the symbols in Fig. 2. The lines in Fig. 2 are the calculated pH and magnesium concentrations for a simulation of geochemical reactions using the computer program PHREEQE.7 The effluent pH exhibited a three-stage behavior when the pH of the injected solution increased from 1 to 13. In the typical pH range of injected gelant, the effluent pH reached around 10 for a nonbuffered solution. This study of fluid-rock interactions showed the dramatic increase in pH that can occur by carbonate dissolution when brine solutions that do not have strong buffering capacities are injected through carbonate rocks. Polyacrylamide-chromium acetate is a commonly used gel system. A study of aqueous chromium acetate8 showed that dissolving solid chromic triacetate in water produced a complex mixture in which bridge-structured trimers were the dominant species, including both cyclic and linear trimers. Increasing the pH of the trimeric chromium(III) solution causes hydroxyl groups to replace the bridging acetate group. Hydroxyl substitution converts the cyclic structure to a linear structure. Additional hydroxyls cause precipitation of the complex. Bryant et al.4 indicated that the precipitation of chromium involved the slow, irreversible formation of insoluble chromium(III) colloids such as Cr(OH)3(H2O)3. Burrafato et al.9 studied the stability of chromium(III) solution with various carboxylate ligands. It was observed that chromium acetate precipitates at moderate pH in unbuffered solutions. Chromium precipitation is a kinetic process1 and the precipitation rate and chromium solubility are dependent upon many parameters. In this work, the effects of pH, temperature, salinity, acetate ligand concentration, and salt type on chromium precipitation were studied using constant pH titrations. The investigation covered experimental conditions for a pH range between 7 and 10. The experimental study was concentrated between pH 7 and 10 because the pH of a nonbuffered chromium acetate solution usually increases to this range after being injected through dolomite core. The temperature range studied was between 25 and 45°C, the salinity range was between 0 and 5% KCl, and the ratio of acetate to chromium was between 3 and 9. The effect of salt type on precipitation was also studied for monovalent and divalent cations. Experiment Materials. The chromium triacetate was obtained from Alfa Products. The empirical formula of the material is Cr(OAc)3·H2O. Chromic chloride, CrCl3·6H2O, was obtained from Fisher Scientific. The titratant was 0.1 M NaOH (Fisher Scientific) unless described otherwise. Reagent grade potassium chloride was used to adjust the ionic strength in the solution. Distilled, de-ionized, and de-aerated water was used to prepare all solutions. Except for those specified otherwise, all chromic acetate solutions were prepared by dissolving solid Cr(OAc)3·H2O in a 1% potassium chloride solution. The initial pH of the Cr(OAc)3 solution (200 ppm chromium) was about 4.5 and was not adjusted during the aging period prior to titration. The aging period for the chromium solution was at least 7 days. Acetic acid (1.0 M) prepared from reagent-grade glacial acetic acid was used to adjust the ratio of acetate to chromium.

Summary It is well established that treatment of porous rocks with gelled polymer systems can cause the permeability of water at residual oil saturation to be reduced by one to three orders of magnitude more than the permeability of oil at the water saturation that is immobile after treatment. This phenomenon is called disproportionate permeability reduction (DPR) and is of interest because application of gel treatments in production wells has potential to reduce water production. The mechanisms that cause this phenomenon are not well understood. This paper describes how permeability to oil and water is developed in pore space that is filled with a chromium acetate/ partially hydrolyzed polyacrylamide (HPAM) gel and proposes a mechanism for DPR based on the interpretation of the experimental data. Experimental data for the flow of oil and brine were obtained in unconsolidated sandpacks and in Berea sandstone cores with and without residual oil saturation after a chromium acetate/Alcoflood 935 gelant was injected and gelled in situ. Interpretation of the experimental data suggests that oil permeability develops as oil penetrates into the gel-filled pore space, dehydrating the gel by displacing brine from the gel structure and creating "new flow channels" within or around the gel. The "new pore space" is a fraction of the original porosity, and the permeability to oil is reduced substantially from its value before placement and in-situ gelation of the gelant. Subsequent brine injection displaces oil from these flow channels but traps some of the oil in the new pore space as a residual saturation. The trapping of residual oil in the new pore space causes the disproportionate reduction in brine permeability because the brine flows primarily in the pore channels created by dehydration of the gel even though the gel has some brine permeability. When gelant is placed in a matrix containing residual oil, dehydration of the gel reconnects some of the trapped oil, and the oil permeability increases. Subsequent brine displacement experiments conducted at the same pressure drop showed that initial brine permeability was reduced by factors of 100 to 1,000 more than the oil permeability, verifying the existence of DPR. Introduction Increased water production is a worldwide problem in mature fields produced by natural waterdrive or active waterflood. There are economic and environmental incentives to develop methods that reduce water production without significantly affecting oil production. During the past 15 years, a number of polymer systems have been developed that, when placed in a porous matrix, reduce the permeability to water at residual oil saturation significantly more than the permeability to oil at the saturation at which water is immobile. This phenomenon is termed DPR, and systems that exhibit this behavior are called relative permeability modifiers (RPM). There are extensive investigations (Liang et al.,1 Dawe and Zhang,2 Liang and Seright,3,4 Thompson and Fogler,5 Nilsson et al.,6 and Al-Sharji et al.7) on the mechanisms that cause DPR. Proposed mechanisms include segregated flow paths on a microscopic level, wall effects caused by a polymer/gel film that covers the pore walls, restriction of pore throats because of adsorption of polymer or precipitation of hydrophilic components of the gel system, changes in wettability, lubrication effects, swelling and shrinking of gels and polymer films, and change in pore morphology. Of the proposed mechanisms, research continues on the microscopic segregated flow path model, wall effect models, restricted pore-throat model, and effects of changes in pore morphology. None of these proposed mechanisms has been unequivocally demonstrated to be the primary cause of DPR. This paper describes an experimental study of chromium acetate- polyacrylamide gels, which demonstrate DPR when placed in sandpacks and Berea sandstone core material. The research was stimulated by experiments conducted by Dawe and Zhang,2 who used microscale models to observe mechanisms of oil and water flow through a gel placed in a porous medium made by etching pore structure on a glass plate. They observed that oil flowed through the micromodel by fingering through the gel. Water flowed through the gel by diffusing into the gel structure. A subsequent paper by Al-Sharji et al.7 provides additional support for the pore level mechanisms observed by Dawe and Zhang.2 Thompson and Fogler5 studied pore-level mechanisms by altering the permeability of a porous matrix following a gel treatment. In their studies, the interstitial water saturation was gelled in situ by introducing an organic orthosilicate in the hydrocarbon phase after the interstitial water saturation was attained. The orthosilicate reacted with the interstitial water to form a silica gel, effectively immobilizing the initial interstitial water saturation. In subsequent two-phase flow experiments, trapping of a residual hydrocarbon phase and a "new" residual water phase altered the endpoint saturations as well as the endpoint values of both water and oil permeabilities. The presence of the new residual water phase reduced the oil-phase permeability, while the trapping of residual oil in the new pore space reduced the water-phase permeability at residual oil saturation. Disproportionate permeability reduction was observed. However, the permeabilities of both oil and water phases at endpoint saturations were reduced significantly.

Summary Recent displacement data conclusively show that the initial permeability reduction during in-situ gelation processes does not result from a bulk gelation of the injected fluid. This paper presents a filtration-based model that correctly accounts paper presents a filtration-based model that correctly accounts for all physical phenomena occurring during in-situ gelation displacements. Introduction Permeability modification treatments are used to improve waterflood Permeability modification treatments are used to improve waterflood sweep efficiency in mature waterfloods. These treatments consist of injecting a polymer solution combined with a crosslinking agent into a water-injection well. It is envisioned that the viscous gelling solution enter shigh-permeability, water-swept regions of the reservoir and plugs these channels, forcing subsequent water injection into regions of the reservoir that have not been swept by water. Previous investigators represented the in-situ permeability reduction mechanism as simple bulk gelation of the injection solution. However, displacement data show that flow resistance developed in sandpacks before the injected polymer solution could get in bulk. McCool and McCool et al. proposed that the initial permeability was reduced by filtration of Cr+3/polyacrylamide permeability was reduced by filtration ofCr+3/polyacrylamide aggregates from the gelling solution, well before a true" gel" could form. This paper presents a new numerical model based on the filtration hypothesis. The model consists of a mass-transport equation for10 species coupled with kinetic models of the gelation process and porousmedium and with filtration models from the process and porous medium and with filtration models from the literature. The model successfully matches Marty et al. five in-situ gelation displacements. Model formulation and simulation results are presented here. Background Permeability modification treatments for injection wells are Permeability modification treatments for injection wells are designed by choosing a treatment radius around the wellbore and calculating the volume of gelling solution required to displace the water saturated PV in this region. It is assumed that the gelling solution forms a bulk gel throughout this region after injection. Laboratory displacement data show that high flow resistance developed in sandpacks before the polymer solution could gel in bulk. Large pressure drops caused by this region of high flow resistance limited the amount of gel solution that could be injected into the sandpacks. Although a bulk get formed in the region bounded by this zone of high flow resistance, the treatment depth was limited and was significantly less than predicted from formation of a bulk gel. Previous investigators assumed that an in-situ permeability reduction mechanism resulted from simple bulk gelation of the injected solution. However, McCool et al. hypothesized that the permeability reduction resulted because the porous medium filtered permeability reduction resulted because the porous medium filtered aggregates of chromium/polyacrylamide from the gelling solution well before a true"get" could form. None of the models in the literature include the mechanisms needed to simulate correctly the in-situ gelation behavior of gelling systems studied by McCool, McCool et al., and Marty et al. The model developed in this paper is based on the filtration of gel aggregates from agelling solution. Model Description This section describes a conceptual model of in-situ gelation and develops mathematical equations to model the process. The model was developed by combining transport equations for the various chemical species in porous media with models of gelation kinetics and filtration processes. Equations describing chemical reaction kinetics and filtration mechanisms are taken from the literature. The porous medium consists of a linear sandpack of known permeability and porosity. A solution of thiourea, dichromate, and permeability and porosity. A solution of thiourea, dichromate, and polyacrylamide is injected into one end of the sandpack and polyacrylamide is injected into one end of the sandpack and progresses through the porous medium. Initially, nopolymer chains progresses through the porous medium. Initially, no polymer chains are chemically crosslinked, although the solution has a beginning level of entanglement "crosslinks," giving the solution an initial shear modulus, G', and defining an initial size distribution of "pregelclusters." Polyacrylamide solutions used in gelation displacements typically exceed the polymer entanglement concentration. Pregel clusters oraggregates first form when individual polymer chains become physically entangled with other polymer chains. Chemical crosslinking in the polyacrylamide/redox system begins when thiourea reacts with dichromate to produce CT +3 ions, which then attach to polymer chains. Attached CT +3 ions participate in crosslink formation, joining polymer chains and small clusters to form larger pregel clusters. During gelation processes, these pregel clusters steadily increase in size as small clusters combine pregel clusters steadily increase in size as small clusters combine to form larger ones. In the absence of shear, the largest aggregates ultimately form an "infinite" gel molecule throughout the volume of gelling solution. We believe that permeability reduction during in-situ gelation displacements results largely from the filtration of these large polymer aggregates before the infinite gel network is formed. Polymer is retained in the porous medium in two ways. When injected polymer first contacts the porous medium, a layer of polymer adsorbs on to the surface of the sand grains. This thin, polymer adsorbs onto the surface of the sand grains. This thin, dense initial layer is attached to the surface of the sand grain by physical entrapment and surface attractions and has little effect physical entrapment and surface attractions and has little effect on permeability. As polymer aggregates increase in size, some are filtered out and attach to previously deposited polymer. The filtration rate increases with polymer concentration, aggregate size, and attached Cr+3concentration. Porosity and permeability of the porous medium decrease as filtration progresses, causing the zone of high flow resistance observed during laboratory in-situ gelation displacements.