Disproportionate Permeability Reduction (DPR) / Relative Permeability Modifiers (RPM)

X-ray computed microtomography (XMT) was used to establish why pore-filling Cr(III)-acetate-HPAM gels reduced permeability to water much more than to oil. Our results suggest that permeability to water was reduced to low values because water must flow through gel itself, whereas oil pressing on the gel in Berea sandstone or porous polyethylene forced pathways by dehydration—leading to relatively high permeability to oil. In very permeable sandpacks, data from other researchers support ripping or extrusion mechanisms for creating oil pathways.

Our XMT studies provide interesting insights into imbibition and drainage processes in water-wet and oil-wet porous media even before gel placement. Many of our observations were consistent with conventional wisdom. However, some were unexpected. Residual wetting-phase (water) saturations in Berea were surprisingly low-valued in small pores. We attribute this to surface roughness caused by clay coating on Berea’s pore walls, which allowed efficient water drainage from small pores during oil injection.

X-ray computed microtomography (XMT) was used to investigate why gels reduce relative permeability to water more than that to oil in strongly water-wet Berea sandstone. XMT allows saturation differences to be monitored for individual pores during various stages of oil, water, and gelant flooding. The method also characterizes distributions of pore size, aspect ratio, and coordination number for the porous media. We studied a Cr(III) acetate–HPAM gel that reduced permeability to water (at Sor) by a factor 80–90 times more than that to oil (at Swr). In Berea, the gel caused disproportionate permeability reduction by trapping substantial volumes of oil that remained immobile during water flooding (i.e., 43.5% Sor before gel placement versus 78.7% Sor after gel placement). With this high trapped oil saturation, water was forced to flow through narrow films, through the smallest pores, and through the gel itself. In contrast, during oil flooding, oil pathways remained relatively free from constriction by the gel.

X-ray computed microtomography was used to investigate why gels reduce permeability to water more than that to oil in strongly water-wet Berea sandstone and in an oil-wet porous polyethylene core. Although the two porous media had very different porosities (22% vs. 40%), the distributions of pore sizes and aspect ratios were similar. A Cr(III)-acetate-HPAM gel caused comparable oil and water permeability reductions in both porous media. In both cores, the gel reduced permeability to water by a factor 80 to 90 times more than that to oil. However, the distributions of water and oil saturations (vs. pore size) were substantially different before, during, and after gel placement. This paper examines the mechanism for the disproportionate permeability reduction in the two porous media.

Disproportionate permeability reduction (DPR) refers to the phenomenon where polymer solutions and gels reduce permeability to water more than to oil/gas. This study investigates DPR mechanisms via core- and micro-model-scale experiments using Cr(III)-acetate-HPAM gels. Core-scale NMR detected changes in trapped/free water during oil and water flooding, while micro-model tests recorded oil/gas invasion behavior visually. Results show that gel-displacement initiates oil flow paths, followed by gel dehydration under pressure gradients. During water flooding, gel rehydration blocks channels, significantly reducing water permeability. Mechanisms contributing to DPR include channel segregation, gel rehydration, residual oil effects, and gel’s intrinsic low permeability to water.

Pore-scale X-ray computed microtomography (XMT) images were obtained at various oil (hexadecane) throughput values after placing a pore-filling Cr(III)-acetate-HPAM gel in cores. Studies were performed in both water-wet Berea sandstone and hydrophobic porous polyethylene cores. In polyethylene, gel was quickly destroyed in the smallest and largest pores, while oil saturations rose more gradually in intermediate-size pores (~10⁻⁴ mm³). In Berea sandstone, oil saturation increased uniformly across all pore sizes, indicating uniform gel dehydration. The study explains these differences by wettability and surface roughness, noting Berea’s kaolinite coatings enabled uniform drainage and gel dehydration.

Many polymers and gels can reduce the permeability to water more than they can the permeability to oil or gas. However, the mechanism of this disproportionate permeability reduction is not clear. This paper considers a promising potential explanation that is based on a combined “wall-effect” and “gel-droplet” model. Many aspects of the disproportionate permeability reduction can be explained by a wall-effect model if the gelant is prepared from or matches the wetting phase, and by a gel-droplet model if the gelant is prepared from or matches the nonwetting phase. The combined model predicts that disproportionate permeability reduction should increase with increasing residual nonwetting-phase saturation. New experimental results support this prediction.

Several previous researchers reported that polymers or gels can reduce permeability to water more than to oil. However, a plausible explanation for the phenomenon is not yet available. This property is critical to the success of gel treatments in production wells if zones cannot be isolated during gel placement. We examined how different types of gels reduce oil and water permeabilities in Berea sandstone. The gel formulations that we investigated included (1) resorcinol-formaldehyde, (2) Cr³⁺(chloride)-xanthan, (3) Cr³⁺(acetate)-polyacrylamide, and (4) colloidal silica. Several new methods were applied to obtain a better understanding of why gels can reduce water permeability more than oil permeability. First, before gel placement in cores, multiple imbibition and drainage cycles were performed in both flow directions. Results from these studies established that hysteresis of oil and water relative permeabilities was not responsible for the behavior observed during our subsequent gel studies. Second, several gels clearly reduced water permeability significantly more than oil permeability. Whereas previous literature reported this phenomenon for polymers and “weak” polymer-based gels, we also observed the disproportionate permeability reduction with a monomer-based gel (resorcinol-formaldehyde), as well as with both “weak” Cr³⁺ (chloride)-xanthan and “strong” Cr³⁺(acetate)-HPAM gels. In contrast, a colloidal-silica gel reduced water and oil permeabilities by about the same factor. Residual resistance factors for several gels were found to erode during multiple cycles of oil and water injection. In spite of this erosion, the disproportionate permeability reduction persisted through the cycles for most of the gels. Studies using both oil and water tracers provided insight into the fraction of the pore volume occupied by gel. The strongest gels appeared to encapsulate the original residual oil saturation—thus rendering the residual oil inaccessible during subsequent oil flooding.

Improved network flow models require the incorporation of increasingly accurate geometrical characterization of the microscale pore structure as well as greater information on fluid–fluid interaction (interfaces) at pore scales. We report on three dimensional (3D) pore scale medium characterization, absolute permeability computations for throat structures, and pore scale residual fluid distribution in a Berea core. X-ray computed microtomography combined with X-ray attenuating dopants is used to obtain 3D images of the pore network and to resolve phase distributions in the pore space.

We present results on pore characterization, including distributions for pore volume, pore surface area, throat surface area, and principal direction diameters for pores and throats. Lattice Boltzmann computations are used to predict absolute permeabilities for individual throats reconstructed from the images. We present results on oil and water distribution in the pore space at residual conditions. We also consider the effects on residual fluid distribution due to the injection and gelation of a water-based gel. In extensive studies of Berea cores it has been observed that introducing water-based gels in the displacement process reduces permeability to water more than to oil. Our results provide supporting evidence for the involvement of gel compaction (dehydration) and oil trapping, while discounting gel blockage in throats, as mechanisms contributing to this effect.

© 2006 Elsevier Ltd. All rights reserved.

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(III)-xanthan gel, (4) a Cr(III)-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.

This paper provides guidance on when and where relative-permeability-modification/disproportionate-permeability-reduction (RPM/DPR) water-shutoff (WSO) treatments can be successfully applied for use in either oil or gas production wells. When properly designed and executed, these treatments can be successfully applied to a limited range of oilfield excessive-water-production problems. When these treatments are applicable, they may be placed using bullhead injection (not requiring mechanical zone isolation)—a very favorable feature. However, there are a substantial number of limitations and possible pitfalls relating to the successful application of RPM/DPR WSO treatments. First-time application by an inexperienced operator should be considered a somewhat high-risk undertaking. In order to successfully treat unfractured production wells (i.e., radial flow through matrix rock into the well) that are fully drawn down, the oil and water zones should not be in pressure communication and the oil-producing zone(s) must be producing at 100% oil cut (dry oil). When treating unfractured and multizoned production wells that are not fully drawn down, the well’s long-term oil-production rate can be increased if the post-treatment drawdown is increased substantially. Treatments that promote short-term (transient) decreased water/oil ratios can, in principle, be applied to many unfractured production wells (that are not totally watered out) in matrix-rock reservoirs. However, these latter treatments must be custom designed and engineered on a well-by-well basis. Furthermore, for most wells, the performance and the economics of such transient WSO treatments are generally marginal. An attractive application of RPM/DPR WSO treatments is the use of robust pore-filling gels in the matrix reservoir rock that is adjacent to a fracture(s) when oil and water is being co-produced into the treated fracture.

In this paper, we investigate why some gels can reduce the permeability to water much more than to oil. This property is critical to the success of chemical-based water-shutoff treatments in production wells if hydrocarbon-productive zones cannot be protected during placement. We first briefly review previous findings and the validity of several possible explanations for this disproportionate permeability reduction. Next, we describe experiments that test the validity of a promising mechanism—the segregated pathway theory. This theory speculates that on a microscopic scale, aqueous gelants follow water pathways more than oil pathways. Our experimental results in cores support this mechanism for oil-based gels, but not for water-based gels. We also explore another interesting mechanism that involves a balance between capillary and elastic forces. Results from our experiments support this mechanism for flow in tubes and micromodels, but not in porous rock. Other mechanisms are also discussed.

An idealistic goal of water-shutoff technology is that of identifying materials that can be injected into any production well (without zone isolation) and that will substantially reduce the water productivity without significantly impairing hydrocarbon productivity. Although many polymers and gels reduce permeability to water more than to oil or gas, several factors currently limit widespread field applications of this disproportionate permeability-reduction property. Chromium (III)-acetate-hydrolyzed polyacrylamide [Cr(III)-acetate-HPAM] pore-filling gels were investigated to overcome these limitations. For porous media with pregel kw (at Sor) ranging from 120 to 6,500 md, one pore-filling gel consistently reduced kw to about 0.24 md (ranging from 0.12 to 0.37 md). In contrast, in Berea sandstone with kw (at Sor) ranging from 222 to 363 md, a commercially available relative-permeability modifier (i.e., a suspension of gel particles) exhibited a much wider range of post-polymer kw values—from 0.75 to 202 md. Thus, pore-filling gels can provide greater reliability and behavior that is insensitive to the initial rock permeability.

A simple mobility-ratio model was used to predict cleanup times for both fractured and unfractured production wells after a gel treatment. The time to restore productivity to a gel-treated oil zone (1) was similar for radial vs. linear flow, (2) varied approximately with the cube of distance of gel penetration, (3) varied inversely with pressure drawdown, (4) varied inversely with the kw at Sor in the gel-treated region, and (5) was not sensitive to the final ko at Swr. Although ko at Swr (after gel placement) had no effect on the cleanup time, it strongly affected how much of the original oil productivity was ultimately regained.