Improved Methods for Water Shutoff. Annual Report, October 1, 1996--September 30, 1997

In the US, more than 20 billion barrels of water are produced each year during oilfield operations. There is a tremendous economic incentive to reduce water production if that can be accomplished without significantly sacrificing hydrocarbon production. In an earlier project, the authors determined that the ability of blocking agents to reduce permeability to water much more than that to oil is critical to the success of these blocking treatments in production wells if zones are not protected during placement of the blocking agent. This research project has three objectives: (1) to identify chemical blocking agents that will during placement, flow readily through fractures without penetrating significantly into porous rock and without screening out or developing excessive pressure gradients and at a predictable and controllable time, become immobile and resist breakdown upon exposure to moderate to high pressure gradients; (2) to identify schemes that optimize placement of blocking agents; and (3) to explain why gels and other chemical blocking agents reduce permeability to one phase (e.g., water) more than that of another phase (e.g., oil or gas). Chapter 2 examines the validity of using water/oil ratio plots to distinguish between coning and channeling water production mechanisms. Chapter 3 develops a method to size gelant treatments in hydraulically fractured production wells. Chapter 4 identifies characteristics of naturally fractured reservoirs where gel treatments have the greatest potential. Chapter 5 reports experimental results from studies of gel properties in fractures. Finally, Chapter 6, the authors investigate the mechanism responsible for gels reducing the permeability to water more than that to oil

Porous structure and fluid partitioning in polyethylene cores from 3D X-ray microtomoC12017

Abstract Using oil-wet polyethylene core models, we present the development of robust throat finding techniques for the extraction, from X-ray microtomographic images, of a pore network description of porous media having porosity up to 50%. Measurements of volume, surface area, shape factor, and principal diameters are extracted for pores and area, shape factor and principal diameters for throats. We also present results on the partitioning of wetting and non-wetting phases in the pore space at fixed volume increments of the injected fluid during a complete cycle of drainage and imbibition. We compare these results with fixed fractional flow injection, where wetting and non-wetting phase are simultaneously injected at fixed volume ratio. Finally we demonstrate the ability to differentiate three fluid phases (oil, water, air) in the pore space

Gel placement in production wells

Summary. Straightforward applications of fractional-flow theory and material-balance calculations demonstrate that, if zones are not isolated during gel placement in production wells, gelant can penetrate significantly into all open zones, not just those with high water saturations. Unless oil saturations in the oil-productive zones are extremely high, oil productivity will be damaged even if the gel reduces water permeability without affecting oil permeability. Also, in field applications, capillary pressure will not prevent gelant penetration into oil-productive zones. An explanation is provided for the occurrence of successful applications of gels in fractured wells produced by bottomwater drive. With the right properties, gels could significantly increase the critical rate for water influx in fractured wells

Improved methods for water shutoff. Final technical progress report, October 1, 1997--September 30, 1998

In the United States, more than 20 billion barrels of salt water are produced each year during oilfield operations. A tremendous economic incentive exists to reduce water production if that can be accomplished without significantly sacrificing hydrocarbon production. This three-year research project had three objectives. The first objective was to identify chemical blocking agents that will (a) during placement, flow readily through fractures without penetrating significantly into porous rock and with screening out or developing excessive pressure gradients and (b) at a predictable and controllable time, become immobile and resistant breakdown upon exposure to moderate to high pressure gradients. The second objective was to identify schemes that optimize placement of the above blocking agents. The third objective was to explain why gels and other chemical blocking agents reduce permeability to one phase (e.g., water) more than that to another phase (e.g., oil or gas). The authors also wanted to identify conditions that maximize this phenomenon. This project consisted of three tasks, each of which addressed one of the above objectives. This report describes work performed during the third and final period of the project. During this three-year project, they: (1) Developed a procedure and software for sizing gelant treatments in hydraulically fractured production wells; (2) Developed a method (based on interwell tracer results) to determine the potential for applying gel treatments in naturally fractured reservoirs; (3) Characterized gel properties during extrusion through fractures; (4) Developed a method to predict gel placement in naturally fractured reservoirs; (5) Made progress in elucidating the mechanism for why some gels can reduce permeability to water more than that to oil; (6) Demonstrated the limitations of using water/oil ratio diagnostic plots to distinguish between channeling and coning; and (7) Proposed a philosophy for diagnosing and attacking water-production problems

Polymer Flow Through Porous Media: Numerical Prediction of the Contribution of Slip to the Apparent Viscosity.

The flow of polymer solutions in porous media is often described using Darcy’s law with an apparent viscosity capturing the observed thinning or thickening effects. While the macroscale form is well accepted, the fundamentals of the pore-scale mechanisms, their link with the apparent viscosity, and their relative influence are still a matter of debate. Besides the complex effects associated with the rheology of the bulk fluid, the flow is also deeply influenced by the mechanisms occurring close to the solid/liquid interface, where polymer molecules can arrange and interact in a complex manner. In this paper, we focus on a repulsive mechanism, where polymer molecules are pushed away from the interface, yielding a so-called depletion layer in the vicinity of the wall. This depletion layer acts as a lubricating film that may be represented by an effective slip boundary condition. Here, our goal is to provide a simple mean to evaluate the contribution of this slip effect to the apparent viscosity. To do so, we solve the pore-scale flow numerically in idealized porous media with a slip length evaluated analytically in a tube. Besides its simplicity, the advantage of our approach is also that it captures relatively well the apparent viscosity obtained from core-flood experiments, using only a limited number of inputs. Therefore, it may be useful in many applications to rapidly estimate the influence of the depletion layer effect over the macroscale flow and its relative contribution compared to other phenomena, such as non-Newtonian effects

Impact of Permeability and Lithology on Gel Performance

of Petroleum Engineers. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is prasented. Write Librarian Manager, SPE, P.O. Box 833836, Richardson, TX 75083-3836. Telex, 730989 SPEDAL. I Abstract This paper describes an experimental investigation of the effects of rock permeability and lithology on the performance of several gels, including those formed from resorcinolformaldehyde, colloidal silica, C? +(chloride)-xanthan, and C? + (acetate)-pol yacrylamide. During these experiments, particular attention was paid to (1) the importance of pH to gelation, (2) gel performance as a function of fluid velocity, and (3) the use of tracers to assess the fraction of the pore space that was occupied by gel. During core experiments, the Iktrongest" gels were found to reduce the permeability of all cores to approximately the same value (in the low microdarcy range). Tracer studies indicated that these gels occupied most of the available pore space. Flow experiments were performed in rectangular micromodels to determine whether these gels have some inherent permeability to water. The permeabilities for five gels were found to be less than or equal to 60 pD. For "weaker" gels (i.e., those leaving a significant permeability), residual resistance factors generally decreased with increased rock permeability. Tracer studies indicated that these gels occupied a small fraction of the pore space in a core. Experiments revealed that gelation in the porous rock was often far less complete than that in a bottle. For unbuffered gelants in porous rocks, the pH at which gelation occurs may be determined more by rock mineralogy than by the pH of the injected gelant. Thus, the buffering action of reservoir rocks should be considered when evaluating gel performance in the laboratory. The immense buffering capacity of limestone can effectively preclude the propagation of unbuffered C?+(chloride)-xanthan gelants or CrC13 solutions through porous limestone. I References and figures at end of paper. Introduction Ideally, gel treatments should reduce channeling of fluids through high-permeability, watered-out flow paths without damaging oil-productive zones. However, in most applications, the gelant penetrates to some extent into lowpermeability, oil-productive zones. A gel treatment can either enhance or harm oil production, depending on how the gel's performance in low-permeability rock compares with that in the "thief" zone.'f Some researchers have attempted to evaluate the effectiveness of fluid diversion processes using porous media with only one permeabilit~.~" Unfortunately, this type of evaluation indicates nothing about the performance of the diversion process in strata with different permeabilities. For example, assume that a diverting agent reduces the flow capacity of a "thief" zone by a factor of ten. If the diverting agent reduces the flow capacity of a nearby oil-productive zone by a factor of two, then the fluid diversion process could improve sweep efficiency. However, if the diverting agent reduces the flow capacity of the oil-productive zone by a factor of twenty, then the diversion process could reduce sweep efficiency substantially. Thus, the effectiveness of a diversion process cannot be assessed by using rock with a single permeability. Other researchers have used parallel linear corefloods with cores of different permeabilities to evaluate the effectiveness of fluid diversion pr~cesses.~''~ Unfortunately, these studies can be extremely misleading for several reason^.'"'^ First, the results are not relevant to unfractured wells where the flow geometry is radial. Simple calculations using the Darcy equation reveal that the performance of a diverting agent can be substantially different in a radial geometry than in a linear Second, the short bank of the diverting agent in the less-permeable core can be diluted enough by diffusion and 347 -1 . 2 Impact of Permeability and dispersion to deactivate the diverting agent. This situation is much more likely to occur on a laboratory scale than on a field scale." Third, depending on the wettability of the system, capillary effects may prevent an aqueous diversion fluid from entering the less-permeable core. This circumstance is also much more likely to occur on a laboratory scale than on a field scale.18 Fourth, the flow lines leading to the core inlets must be completely filled with the diverting agent at the start of the displacement process. Otherwise (if the lines are filled with water instead of diverting agent), the diverting agent could penetrate well into the most-permeable core before it reaches the inlet face of the less-permeable core.16 Fifth, if both cores become filled with a shear-thinning fluid, then the ratio of flow rates for the two cores can erroneously lead one to believe that the fluid is unusually selective in entering the most-permeable core." In summary, results from parallel linear corefloods are often misleading, and they provide a poor method to evaluate the effectiveness of a diversion process. To properly evaluate the effectiveness of a fluid diversion process in the laboratory, some experiments should be performed to determine the permeability reduction (residual resistance factor) provided by the gel in cores with different permeabilities. For the reasons mentioned above, these corefloods should be performed separately rather than in parallel. Rocks should be used that are representative of those to be contacted by gel in the intended field application. This paper describes an experimental investigation of the effects of rock permeability and lithology on the performance of several gels. During our experiments, particular attention was paid to (1) the importance of pH to gelation, (2) gel performance as a function of fluid velocity, and (3) the use of tracers to assess the fraction of the pore space that was occupied by gel. A companion papeso examines the effects of oil and wettability on gel performance. Gelants and Gelant Placement Procedures Gelants Studied. In this work, experiments were performed with four different gelants, including resorcinol-formaldehyde, colloidal silicaz1 (DuPont's Ludox SW), C s +(chloride)-xanthan, and C?+(acetate)-polyacrylamide22-s (Marathon's MARCIP). Seven different formulations were investigated. The compositions of these formulations are listed in For the seven gelants, Approximate gelation times and gel-strength codes are also listed in Rocks Used. Three types of rock were used during our core experiments, including (1) a high-permeability Berea sandstone, (2) a low-permeability Berea sandstone, and (3) an Indiana limestone. Porosities for the three types of rock averaged 0.22, 0.19, and 0.19, respectively. Coreflood Sequence. The sequence followed during our core experiments is listed in Tracer studies were routinely performed to characterize pore volumes and dispersivities of the cores. These studies involved injecting a brine bank that contained potassium iodide as a tracer. The tracer concentration in the effluent was monitored spectrophotometrically at a wavelength of 230 nm. Usually, four replicates were performed for each tracer study. Also, the replicates included studies performed at different injection rates. For all of the tracer studies described in this work, an error-function solution25 fit the tracer curves fairly well. For a given core, many pore volumes of gelant (typically, 10 PV) were injected to insure that the cores were saturated (i.e., most of the chemical retention sites in the rock were occupied). Thus, in field applications, the gel properties reported in this study are more relevant to the region behind (upstream of) the front of the gel bank than to the region at the front of the gel bank. While injecting the gelants, resistance factors were continuously monitored in both segments of the core. Effluent properties were also monitored, including pH, viscosity, composition, appearance, gelation time, and final gel strength. Detailed results from these experiments are documented in Refs. 16, 18, 26, 27, and 28. PE 24190 R.S. Chromium Propagation Without Polymer. Several experiments were performed to assess how well chromium propagates through porous rock. The propagation of C?+ through porous rock can be related to the pH dependence of chromium chemistry. Although controversy still exists about the exact forms of chromium that participate in g e l a t i~n ,~~"~ there is agreement that CI ? is most soluble at acidic pH values and that chromium association is promoted as pH is increased-ultimately leading to the formation of a colloid or a precipitate at neutral or alkaline pH values. If an unbuffered chromium solution (e.g., one containing CrC13) is injected at low pH, rock minerals can raise the pH and induce formation of colloidal chromium (i.e., insoluble chromium hydroxide). Deposition in or filtration by the porous medium may then inhibit propagation of the colloidal chromium. In contrast, a buffered chromium solution (e.g., one containing acetate) will resist pH changes, and the soluble chromium will propagate through porous rock more effectively than a colloid. Formation of chromium-carboxylate complexes may also promote chromium solubility at pH values of 6 or higher?l3* The above ideas are supported by the effluent pH values that accompanied our chromium propagation data.18*27*28 For the unbuffered chromium-chloride solutions, the effluent pH can be correlated with chromium propagation. The pH was 3.35 for the unbuffered chromium-chloride solution before injection. After injecting 10 PV, the pH values were 4.89, 5.05, and 7.03, for effluent from the high-permeability sandstone, the low-permeability sandstone, and the limestone, respectively. For the chromium-chloride solutions, Results from our experiments using chromium acetate are consistent with reports that chromium solubility at neutral pH values is increased by the presence of carboxylate compound^.^^*^^ For the chromium-acetate solution, the pH was 5.90 before injection. After injecting 10 PV, the pH values were 6.01, 5.65, and 5.92, for effluent from the highpermeability sandstone, the low-permeability sandstone, and the limestone, respectively. Thus, the acetate effectively buffered the solutions in the porous rack. Also, in spite of a pH value near 6, chromium propagation in all three types of rock was as good or better with the acetate than that for chromium-chloride solutions with lower pH values. Chromium Propagation With Polymer. Propagation of chromium in the presence of 0.4% xanthan is illustrated in A close comparison of Figs. 1 and 2 suggests that the rate of chromium propagation for unbuffered chromium-chloride solutions is greater in the presence of 0.4% xanthan than in its absence. This observation was made for all three rock types. We note that Garver ef a1.35 suggested the opposite possibility. However, the apparent difference in interpretation can readily be explained. In the experiments of Garver ef ul., injection rates were relatively low, so gelation could occur during gelant injection. As Garver e? al. noted, filtration of gel by the core probably caused very high chromium retention in the presence of polymer. In our experiments, injection rates were relatively high, so gelation and filtration of gel particles occurred to a lesser extent during gelant injection. As discussed earlier, the effluent pH decreased to values between pH 4.38 and 5.05 during the course of injecting 10 PV of unbuffered chromium-chloride formulation into Berea sandstone. During injection of an unbuffered gelant into limestone, the pH only decreased to 6.57 after 10 PV. For the formulation with 0.3% acetate, the core was first saturated with brine buffered at pH=4.8. At the start of gelant injection, the pH of the effluent was 5.39. Presumably, the effluent pH was greater than 4.8 because reaction with rack minerals neutralized some of the acid. Even so, the buffering action of the acetate prevented the pH from rising to the values . . , * Ahologv on Gel Performance SPE 2419 4 ImDact of Permeability and observed for the unbuffered brines. Also, the pH remained low during injection of 10 PV of gelant. After injecting 10 PV of gelant, the core was shut in for several days. After this shut-in period, brine was reinjeckd. Evidently, reactions with rock minerals increased the gelant pH during the shut-in period. As expected, the pH increase in l3erea sandstone during the shut-in period was less for the buffered gelant than for the unbuffered gelant. The preceding observations raise concerns about the practice of injecting unbuffered gelants. During laboratory corefloods and, especially, in field applications, a pH gradient will form in the rock when injecting an unbuffered gelant. This pH gradient will depend upon the gelant composition, the injection rate, and the rock mineralogy. For gelation reactions that are sensitive to pH, the pH gradient and the performance of the gel treatment may be difficult to predict. In contrast, for buffered gelants, gelation should be more predictable and controllable. Fi . 4 illustrates chromium propagation during injection of a C(acetate)-polyacrylamide gelant in high-and lowpermeability Berea sandstone. It also illustrates chromium propagation for a chromium solution (without polymer) through high-permeability Berea sandstone. Previously, we noted that chromium propagation is relatively rapid in the presence of acetate. The data in Residual Resistance Factors After injecting a given gelant, the core was shut in for three to six days. In all cases, the gelation times were substantially less (by factors ranging from 12 to 40) than the shut-in times. Following the shut-in period, brine was injected to determine residual resistance factors ( F , . , , , , ) . These F , values were determined by dividing brine mobility before gel placement by brine mobility after gelation. Residual resistance factors were determined as a function of injection rate. Low injection rates were used first. A note was made of how rapidly F , values stabilized and whether any gel was forced from the core along with the eauent. After stabilization, brine injection rates were increased, and the observations were repeated. Then, the injection rate was decreased to determine whether F , values at lower rates had changed. This process was repeated with successively higher injection rates. The objectives of this procedure were to (1) determine whether gel mobilization or breakdown occurred at a particular flow rate or pressure gradient, and (2) determine the apparent rheology of the gel in porous media. Detailed listings of the residual resistance factors (as a function of fluid velocity) are documented in Refs. 16, 18, 27, and 28. All of the residual resistance factors reported in this paper apply to the second segment (= 12 cm) of the core. When brine was subsequently injected at 1.57 Wd, F,=63. Then, when the velocity was decreased, the F , data could be described using Eq. 3. F , = 71.0 u-0*59 The above procedure was repeated using successively higher injection velocities. As shown in The apparent shear-thinning character was noted for both buffered and unbuffered C?+-xanthan gels in both low-and high-permeabfity Berea sandstone. This is illustrated in The residual resistance factors for the buffered gel were significantly lower than those for the unbuffered gel, This observation is interesting. Originally, we expected the acetate buffer to allow stronger gels to form in the porous media because the average pH during gelation was lower than that for the unbuffered gelant. Therefore, we expected to find residual resistance factors that were much higher than those for the unbuffered gel. However, since dissolved acetate or 'E 24190 R.S. carboxylate groups on the polymer molecule compete for c?+, the acetate apparently caused ~+-xanthan gels to be weaker or less rigid than analogous gels formed when acetate was not present. During gelation studies in bottles, we noted that the unbuffered C?+-xanthan formulations formed more rigid gels than the buffered formulations. Resorcinol-Formaldehyde Gels. For the resorcinolformaldehyde gels, a much more detailed description of our studies can be found in Refs. 16 and 26. Although residual resistance factors for these gels can show a slight shearthinning character, their behavior is essentially Newtonian. As with most gels, residual resistance factors for resorcinolformaldehyde formulations are sensitive to gelation pH. Colloidal-Silica Gels. For the colloidal-silica gels, residual resistance factors averaged 23,200 in 630-md Berea sandstone, 3,810 in 50-md Berea sandstone, and 819 in 12-md Indiana limestone In one sense, the above permeability dependence of the F, , values could be very desirable. All gel-contacted portions of a heterogeneous reservoir could be altered to have nearly the same permeability. However, with 10% colloidal silica, the permeability is so low that flow is effectively stopped. In order to eliminate the need for zone isolation during gel placement, the residual permeability after gelation should be much higher than 30 pD. Jurinak et al. found that a 4% colloidal-silica gel uniformly reduced the permeability of different permeable media to about 1 md (see Our studies of colloidal silica did not reveal conclusive evidence of gel breakdown, even after exposure to pressure gradients as high as 1300 psi/ft. In earlier work, Jurinak et al. found that pressure gradients above 2500 psi/ft were required to cause gel breakdown. Detailed results from our experiments with colloidal silica can be found in Ref. 18. C$+ (Acetate)-Polyacrylamide Gels. For the C$+(acetate)-polyacrylamide gels, one set of experiments was performed using 212-ppm C?+. A second set of experiments was performed using 636-ppm C?+. As expected, a stiffer gel was formed using the higher chromium concentration (gel code I, compared with H for the lower concentration). Using the :right higher chromium concentration, residual resis6ce f a c t o y averaged 187,000 in 662-md Berea sandstone, 44,600 in 65-md Eerea sandstone, and 5,810 in 1 1-md Indiana limestone F O~ the experiments performed using &+(acetate)-polyacrylamide gels with 212-ppm C?', F values were For the gel with 212-ppm C?+, it is somewhat surprising that the F , values in 74-md sandstone were significantly less than those in 746-md sandstone. In both cores, the relationship between F , and u values can be described using power-law equations where the velocity exponent is near -0.5 (see lower than those for gels with 636-ppm C? @ (see Two core experiments were performed using gelants containing 1.39% polyacrylamide in 1 1-md Indiana limestone. The C?+ concentrations in the gelants were 212 ppm and 636 ppm. During placement in the cores, only 0.9 and 1.2 PV of gelant were injected, respectively, before excessive pressure gradients mandated that injection be stopped. Because these cores may not have been completely saturated with gelant, the corresponding properties listed in Results From Tracer Studies After measuring F, values, tracer studies were performed to determine (1) the fraction of the pore volume that remained available to flow, and (2) the new dispersivity of the core. The results from our tracer studies are listed in For the colloidal-silica gel and the resorcinol-formaldehyde gel formed at pH=9, In contrast, the unbuffered C?+-xanthan gel provided fairly high F , values but apparently occupied no more than 13% of the pore space. Perhaps, small gel particles lodge in pore throats-thereby, dramatically reducing brine permeability without occupying much volume. Experiments performed using 154-ppm C2+ without xanthan indicate that this behavior was not due to the chromium alone. These chromium solutions had no significant effect on the apparent pore volume, the dispersivity, or the permeability of the cores. For most cases when &+(acetate)-polyacrylamide gels were used, the flow rates were so low during brine injection after gelation that tracer studies could not be performed. In view of the very high residual resistance factors In these cases, the gel apparently occupied from 11 % to 13% of the pore space (see observed in a beaker.16s t 6s37 Also, tracer studies reveal that We tried to determine if gels have some inherent permeability so that water can flow through the gel matrix. Two-dimensional glass micromodels were fabricated using the procedures described in Ref. 16. The internal dimensions for these rectangular micromodels were 10.3 cm x 0.2 cm x 0.02 cm. Before placing gelant in the models, the "permeability" to water was found to be about 900 darcies. The direction of flow was perpendicular to the 0.2-cm x 0.02-em face. The five gelants described in Permeabilities to water were calculated using the Darcy equation, and the results are listed in However, the possibility remains that the observed permeabilities were influenced by undetected fractures or by flow around the gel. Therefore, the values listed in Note that all permeabilities listed in 2. During core experiments, the "strongest" gels were found to reduce the permeability of all cores to approximately the same value (in the low microdarcy range). Tracer studies indicated that these gels occupied most of the available pore space. 3. Flow experiments performed in rectangular micromodels indicated that the permeabilities (to water) for five gels were less than or equal to 60

Improved techniques for fluid diversion in oil recovery. First annual report

This three-year project has two general objectives. The first objective is to compare the effectiveness of gels in fluid diversion with those of other types of processes. Several different types of fluid-diversion processes are being compared, including those using gels, foams, emulsions, and particulates. The ultimate goals of these comparisons are to (1) establish which of these processes are most effective in a given application, and (2) determine whether aspects of one process can be combined with those of other processes to improve performance. Analyses and experiments are being performed to verify which materials are the most effective in entering and blocking high-permeability zones. Another objective of the project is to identify the mechanisms by which materials (particularly gels) selectively reduce permeability to water more than to oil. This report describes work performed during the first year of the project. Following the introduction, Chapters 2 through 5 present several surveys concerning field applications of gel treatments. Based on the results of the surveys, guidelines are proposed in Chapter 5 for the selection of candidates for gel treatments (both injection wells and production wells). Chapters 6, 7, 8, and 11 discuss theoretical work that was performed during the project. Chapter 6 examines whether Hall plots indicated selectivity during gelant placement. Chapter 7 discusses several important theoretical aspects of gel treatments in production wells with water-coning problems. Chapter 8 considers exploitation of density differences during gelant placement. Chapter 11 presents a preliminary consideration of the use of precipitates as blocking agents. Chapters 9 and 10 detail the experimental work for the project. Chapter 9 describes an experimental investigation of gelant placement in fractured systems. Chapter 10 describes experiments that probe the mechanisms for disproportionate permeability reduction by gels

Reduction of Gas and Water Permeabilities Using Gels

Summary We investigated how different types of gels reduce permeability to water and gases in porous rock. Five types of gels were studied, including (1) a "weak" resorcinol-formaldehyde gel, (2) a"strong" resorcinol-formaldehyde gel, (3) a Cr(II1)-xanthan gel, (4) a Cr(II1)-acetate-HPAM gel, and (5) a colloidal-silica gel. For all gels, extensive coreflood experiments were performed to assess the permeability-reduction characteristics and the stability to repeated water-alternating-gas (WAG) cycles. Studies were performed at pressures up to 1,500 psi using either nitrogen or carbon dioxide as the compressed gas. We developed a coreflood apparatus with an inline high-pressure spectrophotometer that allowed tracer studies to be performed without depressurizing the core. We noted several analogies between the results reported here and those observed during a parallel study of the effects of gel on oil and water permeabilities