Conformance & Water Shut-Off – Fundamentals & Examples
Excessive water production is a major challenge in mature fields and can drastically reduce the profitability and lifespan of oil wells. Understanding its root causes is critical for selecting the appropriate conformance control or water shut-off (WSO) strategy.
Water can enter the well from various sources. A common culprit is reservoir heterogeneity—the presence of layers or zones with contrasting permeabilities. During waterflooding or natural drive, injected or formation water preferentially flows through high-permeability “thief zones,” bypassing tighter oil-bearing intervals. This results in uneven displacement, early water breakthrough, and low sweep efficiency.
Another frequent cause is aquifer encroachment. In reservoirs with a strong water drive, water can rise from below or move laterally into the oil zone as pressure declines, eventually reaching the wellbore. This is particularly problematic in reservoirs with thin oil columns or where production rates outpace pressure support.
Mechanical failures can also lead to unwanted water production. Casing leaks, poor cement jobs, or faulty packers can create flow paths from water-bearing formations into the production string. In deviated or multilateral wells, completion design issues may further aggravate zonal isolation problems.
Fractures, whether natural or induced (e.g., from stimulation), can connect water-rich intervals directly to the wellbore or facilitate crossflow between layers. Over time, such paths become dominant water conduits, further increasing the water cut.
Each of these scenarios requires a tailored response. Conformance and WSO treatments—ranging from mechanical plugs to polymer gels, resins, or relative permeability modifiers—are applied to isolate, block, or divert water inflow.
On this page, we outline the key mechanisms of water entry, diagnostic workflows to identify the source, and field-proven technologies to mitigate the problem. Our goal is to help you restore production efficiency and prolong field life through smart conformance control.
You can also check our YouTube channel for additional videos and podcasts and navigate the Polymer Flooding Guide for more content or our Academy for online courses.
Table of Contents
Podcast - WSO & Conformance with Randy Seright
In this podcast episode featuring Randy Seright, we discuss the basic (yet important) concepts behind water shut-off and conformance technologies:
- Differences between conformance and water shut-off
- Water-cut: How did I decide there was a problem?
- What did I do to diagnose the problem – the importance of diagnostic
- When gel treatments apply best
- Sizing, implementation, success in fractures
- Conformance technologies: microgels, nanogels, etc.
Water Shut-Off - Randy Seright's Training Course
We provide the slides of Randy’s Training Course on Water Shut-Off.
Generalities - Water Shut-Off & Conformance
We propose a list of publications discussing the technical details behind successful WSO & conformance treatments.
This paper provides an introduction to the topic of water shutoff and conformance improvement. After indicating the volumes of water produced during oilfield operations, a strategy is provided for attacking excess water production problems. Problem types are categorized, typical methods of problem diagnosis are mentioned, and the range of solutions is introduced for each problem type. In the third section of the paper, the concept of disproportionate permeability reduction is introduced—where polymers and gels may reduce permeability to water more than to oil or gas. When and where this property is of value is discussed. The fourth section describes the properties of formed gels as they extrude through fractures and how those properties can be of value when treating conformance problems caused by fractures. Section 5 covers the efficiency with which gels block fractures after gel placement—especially, the impact of fluids injected subsequent to the gel treatment.
A new model was developed to describe water leakoff from formed Cr(III)-acetate-HPAM gels during extrusion through fractures. This model is fundamentally different from the conventional filter-cake model used during hydraulic fracturing. Even so, it accurately predicted leakoff during extrusion of a guar-borate gel. Thus, the new model may be of interest in hydraulic fracturing. Contrary to the conventional one, the new model correctly predicted the occurrence of wormholes and stable pressure gradients during gel extrusion through fractures.
This paper describes a straightforward strategy for diagnosing and solving excess-water-production problems. The strategy advocates that the easiest problems should be attacked first and that diagnosis of water production problems should begin with the information already at hand. A listing of water-production problems is provided, along with a ranking of their relative ease of solution. Although a broad range of water-shutoff technologies is considered, the major focus of the paper is when and where gels can be effectively applied for water shutoff.
For stratified reservoirs with free crossflow and where fractures do not cause severe channeling, improved sweep is often needed after water breakthrough. For moderately viscous oils, polymer flooding is an option for this type of reservoir. However, in recent years, an in-depth profile-modification method has been commercialized in which a block is placed in the high-permeability zone(s). This sophisticated idea requires that (1) the blocking agent have a low viscosity (ideally a unit-mobility displacement) during placement, that (2) the rear of the blocking-agent bank in the high-permeability zone(s) outrun the front of the blocking-agent bank in adjacent less-permeable zones, and that (3) an effective block to flow form at the appropriate location in the high-permeability zone(s). Achieving these objectives is challenging but has been accomplished in at least one field test. This paper investigates when this in-depth profile-modification process is a superior choice over conventional polymer flooding.
Using simulation and analytical studies, we examined oil-recovery efficiency for the two processes as a function of (1) permeability contrast, (2) relative zone thickness, (3) oil viscosity, (4) polymer-solution viscosity, (5) polymer- or blocking-agent-bank size, and (6) relative costs for polymer vs. blocking agent. The results reveal that in-depth profile modification is most appropriate for high permeability contrasts (e.g., 10:1), high thickness ratios (e.g., less-permeable zones being 10 times thicker than high-permeability zones), and relatively low oil viscosities. Because of the high cost of the blocking agent relative to conventional polymers, economics favours small blocking-agent-bank sizes (e.g., 5% of the pore volume in the high-permeability layer). Even though short-term economics may favour in-depth profile modification, ultimate recovery may be considerably less than from a traditional polymer flood.
Placement Concepts
We propose a list of publications discussing the placement concepts for successful WSO & conformance treatments.
Often, when production wells are stimulated by hydraulic fracturing, the fracture unintentionally breaks into water zones causing substantially increased water production. To correct this problem, we developed an engineering basis for designing and sizing gelant treatments in hydraulically fractured production wells. In these treatments, gelant penetrates a short distance from the fracture face into the porous rock associated with both water and hydrocarbon zones. Success for a given treatment requires that the gel reduce permeability to water much more than that to hydrocarbon. We present a simple 11-step procedure for sizing these gelant treatments. This procedure was incorporated in user-friendly graphical-user-interface software.
In this paper, we investigate whether foams can show placement properties that are superior to those of gels, when used as blocking agents. Specifically, we examine whether the concept of limiting capillary pressure can be exploited to form a persistent, low-mobility foam in high-permeability zones while preventing foam production and formation damage in low-permeability zones. Using a C14-16 α-olefin sulfonate, we measured mobilities of a nitrogen foam in cores with permeabilities from 7.5 to 900 md (750 psig back pressure, 104°F), with foam qualities ranging from 50% to 95%, and with Darcy velocities ranging from 0.5 to 100 ft/d. We also extensively studied the residual resistance factors provided during brine injection after foam placement. The results from our experimental studies were used during numerical analyses to establish whether foams can exhibit placement properties that are superior to those of gelants. This study found that compared with water-like gelants, the foam showed better placement properties when the permeabilities were 7.5 md or less in the low-permeability zones and 80 md or more in the high-permeability zones.
This study investigates how flow profiles in injection wells are modified when zones are not isolated during placement of gelling agents. Mathematical models are used to examine the degree of gel penetration and injectivity loss in zones of different permeability. Several conclusions are drawn that apply to reservoirs in which crossflow between layers does not occur. First, zone isolation is far more likely to be needed during placement of gels in unfractured wells than in fractured wells. Productive zones in unfractured wells may be seriously damaged if zones are not isolated during gel placement. Second, gel placement without zone isolation should cause the least damage to productive zones in unfractured wells when (a) the gelling formulation exhibits a low resistance factor during placement, (b) the water-oil mobility ratio is relatively high, (c) the most-permeable layer(s) are watered-out, and (d) the waterfronts are not close to the production well in the productive zones. Third, parallel linear corefloods overestimate the degree of profile modification that can be attained in radial systems. Fourth, chemical retention, dispersion and diffusion will probably not significantly mitigate injectivity losses caused by gel penetration into low-permeability zones. Finally, a need exists to determine the permeability and velocity dependencies of gelling-agent resistance factors and of gel residual resistance factors.
A key issue in gel technology is how to place gels in thief zones without damaging oil-productive zones. This study explores the influence of diffusion, dispersion, and viscous fingering during placement of gels to modify injection profiles. These phenomena usually will not eliminate the need for zone isolation during gel placement in unfractured injection wells. During gel placement in parallel laboratory corefloods, diffusion and dispersion can cause one to conclude erroneously that zone isolation is not needed in field applications. Gel treatments are more likely to improve sweep efficiency in wells where fractures are the source of the channeling problem.
This paper is concerned with the proper placement of gels to reduce fluid channeling in reservoirs. Previous work demonstrated that an acceptable gel placement is much more likely to be achieved in a linear flow geometry (e.g., vertically fractured wells) than in radial flow. In radial flow, oil-productive zones must be protected (e.g., using zone isolation) during gel placement to prevent damage to oil productivity. In this study, two theoretical models were developed to determine water injection profiles before and after gel placement in anisotropic reservoirs—where the effective permeability and/or the pressure gradient are greater in one horizontal direction than in another direction. The primary question addressed in this work is, how anisotropic must an unfractured reservoir be to achieve an acceptable gel placement and profile modification during unrestricted gelant injection? Both analytical and numerical methods were applied to solve the problem. The analyses showed that the permeability ratio must exceed 1,000 (and usually 10,000) before anisotropy can be exploited effectively in unfractured wells.
This paper considers some of the reservoir variables that affect the severity of channeling and the potential of gel treatments for reducing channeling through naturally fractured reservoirs. We performed extensive tracer and gel placement studies using two different simulators. We show that gel treatments have the greatest potential when the conductivities of fractures that are aligned with direct flow between an injector-producer pair are at least 10 times the conductivity of off-trend fractures. Gel treatments also have their greatest potential in reservoirs with moderate to large fracture spacing. Produced tracer concentrations from interwell tracer studies can help identify reservoirs that are predisposed to successful gel applications. Our simulation studies also show how tracer transit times can be used to estimate the conductivity of the most direct fracture. The effectiveness of gel treatments should be insensitive to fracture spacing for fractures that are aligned with the direct flow direction. The effectiveness of gel treatments increases with increased fracture spacing for fractures that are not aligned with the direct flow direction.
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.
This study investigates whether rheology can be exploited to eliminate the need for zone isolation during gel placement. Eight different rheological models were used to represent the properties of existing non-Newtonian gelling agents. Gel placement was examined in linear and radial parallel corefloods and in fractured and unfractured injection wells. The analysis indicates that, compared with water-like gelling agents, existing non-Newtonian gelling agents will not reduce the need for zone isolation during gel placement in radial-flow systems.
Early water breakthrough can be a serious problem during waterflooding of heterogeneous reservoir formations. One possible remedy to this problem is to place a gel block in the high-permeability layer, thus diverting displacing brine into the less-permeable layers in order to sweep the remaining oil from these zones. In such a treatment, the gelant material must be placed in the correct location within the reservoir so that gel does not impair reservoir performance. In this paper, we study the dynamics of gel placement in heterogeneous (stratified) reservoir systems. The details of the gel placement are strongly affected by the level of communication between reservoir layers, which is characterized by the closeness of the system to vertical equilibrium (VE) conditions. We show that in viscous-stable injection of gelant in systems close to vertical equilibrium, considerable volumes of injected material can crossflow into the low-permeability layers, and subsequent gel formation can seriously reduce the performance of the continuing waterflood. Results from a range of experimental displacements in well characterized layered beadpacks are presented, along with supporting numerical simulations, which help to understand the mechanisms and benefits when performing gel treatments in reservoir systems with free crossflow. The central role of viscous crossflow in such systems is demonstrated. Since we consider only viscous forces in this work, the layered experimental packs are scaled only by the viscosity ratio (displacing to displaced), the geometry of the packs, the aspect ratio and the degree of vertical communication (closeness to VE). Thus the conclusions from the experimental and simulation results are directly applicable to similarly scaled viscous-dominated systems at the reservoir scale. Some analysis is also presented of the mechanism of disruption of slugs by viscous fingering in layered systems.
Many different materials have been proposed to reduce channeling of fluids through fractures and streaks of very high permeability. These materials include gels, particulate, precipitates, microorganisms, foams and emulsions. In this paper, we compare the placement and permeability reduction properties of these different types of blocking agents. Comparisons were made of their selectivity in entering high-permeability rock in preference to low-permeability rock. We also examined their ability to reduce permeability to a greater extent in high-permeability, water-saturated zones than in low-permeability, oil-saturated zones. Concepts are identified that may lead to blocking agents with placement and/or permeability-reduction properties that are superior to those of gels.
Gel Treatments in Fractures
We propose a list of publications discussing the gel placement concepts for treating fractures.
Crosslinked polymers extrude through fractures during placement of many conformance-improvement treatments, as well as during hydraulic fracturing. Dehydration of polymer gel during extrusion through fractures has often been observed and was extensively investigated during recent decades. Injection of highly viscous gel increases the pressure in a fracture, which promotes gel dehydration by fluid leakoff into the adjacent matrix. The present comprehension of gel behavior dictates that the rate of fluid leakoff will be controlled by the gel and fracture properties and, to a lesser extent, be affected by the properties of an adjacent porous medium. However, several experimental results, presented in this work, indicate that fluid leakoff deviates from expected behavior when oil is present in the fracture-adjacent matrix. We investigated fluid leakoff from chromium (Cr)(III)-acetate hydrolyzed polyacrylamide (HPAM) gels during extrusion through oil-saturated, fractured core plugs. The matrix properties were varied to evaluate the effect of pore size, permeability, and heterogeneity on gel dehydration and leakoff rate. A deviating leakoff behavior during gel propagation through fractured, oil-saturated core plugs was observed, associated with the formation of a capillary driven displacement front in the matrix. Magnetic resonance imaging (MRI) was used to monitor water leakoff in a fractured, oil-saturated, carbonate core plug and verified the position and existence of a stable displacement front. The use of MRI also identified the presence of wormholes in the gel, during and after gel placement, which supports gel behavior similar to the previously proposed Seright filter-cake model. An explanation is offered for when the matrix affects gel dehydration and is supported by imaging. Our results show that the properties of a reservoir rock might affect gel dehydration, which, in turn, strongly affects the depth of gel penetration into a fracture network and the gel strength during chase floods.
This work investigated the blockage performance of a Cr(III)-acetate-hydrolyzed polyacrylamide (HPAM) gel after placement in open fractures, with emphasis on the effect of gel maturity during placement. Polymer gel is formed through a chemical reaction between a polymer and a crosslinking agent (in a gelant solution) that occurs during the gelation time. In field applications, gelant is generally pumped from the surface, but gelation may occur during injection because of high-temperature conditions and longer pumping times; hence, partially or fully mature gel may exit the wellbore during polymer-gel injection in a fractured reservoir.
This paper investigates washout of mature Cr(III)-acetate-HPAM gels from fractures. After gel placement, the pressure gradient for gel washout during brine or oil flow was similar to the pressure gradient observed during gel placement. The mechanism of gel failure involved the displacement of relatively mobile gel from wormholes. Generally, only a small fraction of the gel (<5%) was displaced during the washout process. Resistance to washout can be increased by injecting a more concentrated gel. However, this approach exhibits significantly higher pressure gradients during gel placement. The presence of a constriction in a fracture inhibited gel washout during the first pulse of brine flow after gel placement. However, during subsequent brine flow, gel erosion occurred upstream of the constriction to the same extent as downstream.
Using wide ranges of gel age, gel velocity, and fracture conductivity or tube diameter, Cr(III)-acetate-HPAM gels were studied as they extruded through fractures and tubes. Gels exhibited shear-thinning behavior in fractures and tubes that correlated with the gel superficial velocity and the fracture width or tube diameter. In fractures with sufficiently small widths, gels dehydrated during extrusion, thus reducing the rate of gel propagation. This effect was more pronounced as the fracture width decreased. Using the experimental results, a numerical study was conducted to compare placement of preformed gels and water-like gelants.
This paper investigates whether gel behavior in rheometers correlates with that examined during extrusion through fractures. Although qualitative similarities were noted, the pressure gradients during gel extrusion through fractures were substantially greater than the values expected from rheological measurements. Also, the pressure gradient for gel extrusion through fractures varied in an unexpected manner with fracture width.
A laboratory study has shown improved performance for fracture-problem water-shutoff polymer gels that are formulated with a combination of high- and low-molecular-weight (MW) polymers. These gels are intended for application to fractures or other high-permeability anomalies that are in direct contact with petroleum production wells. More specifically, we focused on evaluating the mechanical strength and improved performance of these water-shutoff gels for use when exceptionally large fracture apertures or large drawdown pressures are encountered.
Polymer gel is frequently used for conformance control in fractured reservoirs, where it is injected to reside in fractures or high-permeability streaks to reduce conductivity. With successful polymer-gel conformance control in place, increased pressure gradients across matrix blocks may be achieved during chase floods, diverting water, gas, or enhanced oil recovery (EOR) chemicals into the matrix to displace oil. Knowledge of gel behavior during placement and chase floods is important because it largely controls the success of subsequent injections. Polymer-gel behavior is often studied in corefloods, where differential pressure and effluents from fracture and matrix outlets give information about gel deposition during placement and flow paths during chase floods.
The work presented in this paper uses complementary positron emission tomography (PET) chromatographic tomography (CT) imaging to quantify the behavior and blocking capacity of Cr(III)-acetate hydrolyzed polyacrylamide (HPAM) gel during chase waterflooding. In-situ imaging provides information about changes that may not be extracted from pressure measurements and material balance only, such as changes in local fluid saturations and dynamic spatial flow within the fracture and within the structure of the gel network.
This experimental study investigates how Cr(III)-acetate-HPAM gels propagate through fractures. Key findings show that gels extrude as concentrated plugs without progressive plugging or increasing pressure gradients. Water leakoff into surrounding porous rock causes gel dehydration along the fracture, but gel composition remains stable. Pressure gradients were found to be independent of porous media permeability and varied inversely with the square of fracture width. The work supports a model where gels move as semisolids with limited internal viscous dissipation, leading to stable placement behavior under appropriate conditions.
This study demonstrates that low-salinity chase water can enhance the performance of Cr(III)-acetate-HPAM gels in fractured reservoirs by inducing gel swelling. Using coreflood experiments, the authors show that low-salinity brines increase differential pressure and reduce flow through reblocked fractures. In some cases, blocking capacity exceeded the original gel performance. The results were stable and reproducible across both sandstone and carbonate cores, making this a promising approach in integrated EOR (IEOR).
This paper examines several factors that can have an important effect on gel placement in fractured systems, including gelant viscosity, degree of gelation, and gravity. For an effective gel treatment, the conductivity of the fracture must be reduced and a viable flow path must remain open between the wellbore and mobile oil in the reservoir. During placement, the gelant that “leaks off” from the fracture into the rock plays an important role in determining how well a gel treatment will reduce channeling. For a given volume of gelant injected, the distance of gelant leakoff is greater for a viscous gelant than for a low-viscosity gelant (other factors being equal).
Gel Treatments in Matrix
We propose a list of publications discussing the gel placement concepts for treating matrix.
This paper describes an experimental investigation of the effects of rock permeability and lithology on the performance of several gels, including those formed from resorcinol-formaldehyde, colloidal silica, Cr³⁺(chloride)-xanthan, and Cr³⁺(acetate)-polyacrylamide. 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.
Resorcinol/formaldehyde gels are used to show that gel performance in porous rocks depends critically on the pH at which gelation occurs. The gels generally reduced the permeability of low-permeability sandstone more than in high-permeability sandstone. However, residual resistance factors can be greater in sandstones than in less permeable carbonate cores. A simple mathematical model is used to assess whether pH effects can be exploited to optimize gel placement in injection wells.
This work investigates dehydration of polymer gel by capillary imbibition of water bound in gel into a strongly water-wet matrix. Polymer gel is a crosslinked-polymer solution of high water content, where water can leave the gel and propagate through porous media, whereas the large 3D polymer-gel structures cannot. In fractured reservoirs, polymer gel can be used for conformance control by reducing fracture conductivity. Dehydration of polymer gel by spontaneous imbibition (SI) contributes to shrinkage of the gel, which may open parts of the initially gel-filled fracture to flow and significantly reduce the pressure resistance of the gel treatment. SI of water bound in aged Cr(III)-acetate-hydrolyzed-polyacrylamide (HPAM) gel was observed and quantified. Oil-saturated chalk-core plugs were submerged in gel, and the rate of SI was measured. Two boundary conditions were tested: all faces open (AFO) and two-end-open oil-water (TEO-OW), where one end was in contact with the imbibing fluid (gel or brine) and the other was in contact with oil. The rate of SI was significantly slower in gel compared with brine, and was highly sensitive to the ratio of matrix volume to surface open to flow, decreasing with increasing ratios. The presence of a dehydrated gel layer on the core surface lowered the rate of imbibition; continuous loss of water to the core increased the gel layer concentration and thus the barrier to flow between the core and fresh gel. Severe gel dehydration and shrinkage up to 99% were observed in the experiments, suggesting that gel treatments may lose efficiency over time in field applications where a potential for SI exists. The implications of gel dehydration by SI, and its relevance in field applications, are discussed for both gel and gelant field treatments.
Aqueous solutions of xanthan gum are used to reduce water mobility in oilfields and are known to undergo rheological changes when crosslinked with Cr³⁺ ions. The objective of this study is to investigate how Cr³⁺ affects the flow behavior of xanthan solutions in porous media, particularly with regard to apparent viscosity and flow resistance. Laboratory experiments were performed using core plugs of varying permeabilities, and the flow characteristics were measured with and without the presence of Cr³⁺. The results show that Cr³⁺ addition significantly increases the resistance factor and apparent viscosity, indicating stronger retention and shear thickening at low flow rates. The implications for in-situ gelation and profile modification treatments are discussed.
Disproportionate Permeability Reduction (DPR) / Relative Permeability Modifiers (RPM)
We propose a list of publications discussing the gel placement concepts for RPM/DPR
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
In-Depth Diversion
We propose a list of publications discussing in-depth diversion technologies and their placement.
This paper examines literature that claims, suggests, or implies that floods with “colloidal dispersion gels” (CDGs) are superior to polymer floods for oil recovery. The motivation for this report is simple. If CDGs can propagate deep into the porous rock of a reservoir, and at the same time, provide resistance factors or residual resistance factors that are greater than those for the same polymer formulation without the crosslinker, then CDGs should be used in place of polymer solutions for most/all polymer, surfactant, and ASP floods. In contrast, if the claims are not valid, (1) money spent on crosslinker in the CDG formulations was wasted, (2) the mobility reduction/mobility control for CDG field projects was under-designed, and (3) reservoir performance could have been damaged by excessive loss of polymer, face-plugging by gels, and/or excessive fracture extension.
From this review, the clear answer is that there is no credible evidence that colloidal dispersion gels can propagate deep into the porous rock of a reservoir, and at the same time, provide resistance factors or residual resistance factors that are greater than those for the same polymer formulation without the crosslinker.
CDGs have been sold using a number of misleading and invalid arguments. Very commonly, Hall plots are claimed to demonstrate that CDGs provide higher resistance factors and/or residual resistance factors than normal polymer solutions. However, because Hall plots only monitor injection pressures at the wellbore, they reflect the composite of face plugging/formation damage, in-situ mobility changes, and fracture extension. Hall plots cannot distinguish between these effects—so they cannot quantify in situ resistance factors or residual resistance factors.
Laboratory studies—where CDG gels were forced through short cores during 2–3 h—have incorrectly been cited as proof that CDGs will propagate deep (hundreds of feet) into the porous rock of a reservoir over the course of months. In contrast, most legitimate laboratory studies reveal that the gelation time for CDGs is a day or less and that CDGs will not propagate through porous rock after gelation. A few cases were noted where highly depleted Al and/or HPAM fluids passed through cores after one week of aging. However, unless these particular formulations/experiments were sparse statistical outliers, they still do not support the hypothesis that CDGs will work in field projects as claimed.
In recent years, operators have increasingly turned to polymer flooding and in-depth gel placement as cost-effective means to improve sweep efficiency in waterfloods. However, questions persist about which method is more effective under various reservoir conditions. This paper presents a framework for comparing the two technologies in terms of cost, oil recovery, injectivity, and operational complexity. Laboratory data and field case studies are examined to show under what circumstances each technique has yielded superior results. The work emphasizes that a clear understanding of reservoir heterogeneity and waterflood behavior is essential for making the right choice. A key conclusion is that polymer flooding is often preferable for improving volumetric sweep when reservoir heterogeneity is not extreme, whereas in-depth gelation may be more suitable for severe channeling problems in fractured or high-permeability streaked reservoirs.
In this published discussion and reply, Seright critiques the conclusions drawn in Chang et al. (2006) regarding the claimed superiority of colloidal dispersion gels (CDGs) over conventional polymer flooding. Seright challenges the assertion that CDGs penetrate deeply and offer higher resistance factors than HPAM polymers, citing contrary evidence from three university labs. The reply by Chang and co-authors defends their field-scale CDG/polymer results from the Daqing oil field, emphasizing that CDGs can complement polymer flooding by delaying water cut increases and extending project life. Both sides agree on the need for more research to understand the mechanisms of CDG behavior.
Annual Reports - Department of Energy - Randy Seright
We propose the annual DOE reports published by Randy Seright on different aspects of conformance and water shutoff.
This report describes work performed during the third and final year of the project, “Using Chemicals to Optimize Conformance Control In Fractured Reservoirs.” This research project had three objectives. The first objective was to develop a capability to predict and optimize the ability of gels to reduce permeability to water more than that to oil or gas. The second objective was to develop procedures for optimizing blocking agent placement in wells where hydraulic fractures cause channeling problems. The third objective was to develop procedures to optimize blocking agent placement in naturally fractured reservoirs. This research project consisted of three tasks, each of which addressed one of the above objectives. Our work was directed at both injection wells and production wells and at vertical, horizontal, and highly deviated wells.
This report describes work performed during the second year of the project, “Using Chemicals to Optimize Conformance Control In Fractured Reservoirs.” This research project has three objectives. The first objective is to develop a capability to predict and optimize the ability of gels to reduce permeability to water more than that to oil or gas. The second objective is to develop procedures for optimizing blocking agent placement in wells where hydraulic fractures cause channeling problems. The third objective is to develop procedures to optimize blocking agent placement in naturally fractured reservoirs. This research project consists of three tasks, each of which addresses one of the above objectives. Our work is directed at both injection wells and production wells and at vertical, horizontal, and highly deviated wells.
This report describes work performed during the first year of the project, “Using Chemicals to Optimize Conformance Control In Fractured Reservoirs.” This research project has three objectives. The first objective is to develop a capability to predict and optimize the ability of gels to reduce permeability to water more than that to oil or gas. The second objective is to develop procedures for optimizing blocking agent placement in wells where hydraulic fractures cause channeling problems. The third objective is to develop procedures to optimize blocking agent placement in naturally fractured reservoirs. This research project consists of three tasks, each of which addresses one of the above objectives. Our work is directed at both injection wells and production wells and at vertical, horizontal, and highly deviated wells.
This final technical progress report summarizes work performed the project, “Use of Polymers to Recover Viscous Oil from Unconventional Reservoirs.” The objective of this three-year research project was to develop methods using water soluble polymers to recover viscous oil from unconventional reservoirs (i.e., on Alaska’s North Slope). The project had three technical tasks. First, limits were re-examined and redefined for where polymer flooding technology can be applied with respect to unfavorable displacements. Second, we tested existing and new polymers for effective polymer flooding of viscous oil, and we tested newly proposed mechanisms for oil
displacement by polymer solutions. Third, we examined novel methods of using polymer gels to improve sweep efficiency during recovery of unconventional viscous oil.
This technical progress report describes work performed from October 1, 2009, through September 30, 2010, for the second year of the project, “Use of Polymers to Recover Viscous Oil from Unconventional Reservoirs.” For HPAM (partially hydrolyzed polyacrylamide) solutions with a sufficiently low salinity (i.e., tap water or distilled water) and/or sufficiently high polymer concentration, shear thinning can be observed in porous media at moderate to low fluxes. However, under practical conditions where HPAM is used for EOR, the degree of shear thinning is slight or non-existent, especially compared to the level of shear thickening that occurs at high fluxes. Xanthan solutions are well known to exhibit shear thinning both in viscometers and in porous media. Contrary to recent suggestions in the literature, shear thinning by polymer solutions is shown not to be a significant liability for vertical sweep efficiency. The overall viscosity (resistance factor) of the polymer solution is of far greater relevance than the rheology.
Contrary to earlier claims, permeability reduction associated with polymers is shown not to benefit vertical sweep efficiency during polymer flooding.
This technical progress report describes work performed from October 1, 2008, through September 30, 2009, for the project, “Use Of Polymers To Recover Viscous Oil From Unconventional Reservoirs.” Fractional flow calculations were performed to examine the potential of polymer flooding for a range of characteristics in viscous oil reservoirs (especially relevant to the North Slope of Alaska). Using these recovery results, a simple economic analysis was performed to make a preliminary assessment of the potential for polymer flooding in reservoirs with viscous oils. The analysis indicated that over a significant range of throughput values, polymer flooding can provide a higher relative profit than waterflooding. The results emphasize that maximizing injectivity of polymer solutions may be key to economic implementation of polymer flooding for recovery of viscous oils.
This report describes work performed during the third year of the project Improved Techniques for Fluid Diversion in Oil Recovery. 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 pf fluid-diversion processes are being compared, including those using gels, foams, emulsions and particulates. The second objective 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 second year of the project Improved Techniques for Fluid Diversion in Oil Recovery. 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 pf fluid-diversion processes are being compared, including those using gels, foams, emulsions and particulates. The second objective 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 Improved Techniques for Fluid Diversion in Oil Recovery. 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 pf fluid-diversion processes are being compared, including those using gels, foams, emulsions and particulates. The second objective 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 third and final period of the project, “Improved Methods for Water Shutoff.” This project had three general 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 without “screening out” or developing excessive pressure gradients and (b) at a predictable and controllable time, become immobile and resist 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). We also wanted to identify conditions that maximize this phenomenon.
This report describes work performed during the second period of the project, “Improved Methods for Water Shutoff.” This project has three general objectives. The first objective is to identify chemical blocking agents that will (a) during placement, flow readily through fractures without penetrating significantly into porous rock and without “screening out” or developing excessive pressure gradients and (b) at a predictable and controllable time, become immobile and resist breakdown upon exposure to moderate to high pressure gradients. The second objective is to identify schemes that optimize placement of the above blocking agents. The third objective is 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). We also want to identify conditions that maximize this phenomenon.
This report describes work performed during the first period of the project, “Improved Methods for Water Shutoff.” This project has three general objectives. The first objective is to identify chemical blocking agents that will (a) during placement, flow readily through fractures, small casing leaks, and narrow channels behind pipe without penetrating significantly into porous rock and without “screening out” or developing excessive pressure gradients and (b) at a predictable and controllable time, become immobile and resist breakdown upon exposure to moderate to high pressure gradients. The second objective is to identify schemes that optimize placement of the above blocking agents. The third objective is 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). We also want to identify conditions that maximize this phenomenon.
This report describes progress made during the second year of the three-year project, “Fluid Diversion and Sweep Improvement with Chemical Gels in Oil Recovery Processes.” The objectives of this project are to identify the mechanisms by which gel treatments divert fluids in reservoirs and to establish where and how gel treatments are best applied. Several different types of gelants are being examined. This research is directed at gel applications in water injection wells, in production wells, and in high-pressure gasfloods. The work examines how the flow properties of gels and gelling agents are influenced by permeability, lithology, and wettability. Other goals include determining the proper placement of gelants, the stability of in-place gels, and the types of gels required for the various oil recovery processes and for different scales of reservoir heterogeneity.
This report describes progress made during the first year of the three-year project, “Fluid Diversion and Sweep Improvement with Chemical Gels in Oil Recovery Processes.” The objectives of this project are to identify the mechanisms by which gel treatments divert fluids in reservoirs and to establish where and how gel treatments are best applied. Several different types of gelants are being examined, including a monomer-based gelant, several polymer-based gelants, and a colloidal silica gelant.
This report describes progress made during the third and final year of the three-year project, “Fluid Diversion and Sweep Improvement with Chemical Gels in Oil Recovery Processes.” Our experimental work focused on four types of gels:
(1) resorcinol-formaldehyde,
(2) colloidal silica,
(3) Cr³⁺(chloride)-xanthan, and
(4) Cr³⁺(acetate)-polyacrylamide.
All experiments were performed at 41°C. During injection of gelants that contained Cr³⁺, chromium propagation was significantly more rapid when the counterion was acetate rather than chloride. For a given counterion, chromium propagation was much more rapid in Berea sandstone cores than in Indiana limestone cores. It is doubtful that unbuffered chromium-chloride gelants can propagate through carbonate reservoirs.
This report describes work performed during the second year of the project, “Conformance Improvement Using Gels.” The project has two objectives. The first objective is to identify gel compositions and conditions that substantially reduce flow through fractures that allow direct channeling between wells, while leaving secondary fractures open so that high fluid injection and production rates can be maintained. The second objective is to optimize treatments in fractured production wells, where the gel must reduce permeability to water much more than that to oil.
Pore-level images from X-ray computed microtomography were re-examined for Berea sandstone and porous polyethylene. This analysis suggests that oil penetration through gel-filled pores occurs by a gel-dehydration mechanism, rather than a gel-ripping mechanism. This finding helps to explain why aqueous gels can reduce permeability to water more than to oil.
This report describes work performed during the first year of the project, “Conformance Improvement Using Gels.” The project has two objectives. The first objective is to identify gel compositions and conditions that substantially reduce flow through fractures that allow direct channeling between wells, while leaving secondary fractures open so that high fluid injection and production rates can be maintained. The second objective is to optimize treatments in fractured production wells, where the gel must reduce permeability to water much more than that to oil.
This technical progress report describes work performed from October 1, 2005, through September 30, 2006, for the project, “Aperture-Tolerant, Chemical-Based Methods to Reduce Channeling.”
This technical progress report describes work performed from October 1, 2004, through September 30, 2005, for the project, “Aperture-Tolerant, Chemical-Based Methods to Reduce Channeling.”
Field Cases
We propose a list of publications summarizing WSO & conformance field cases.
Advancement in design and implementation of polymer gel water shutoff treatments in horizontal wells that penetrate fractures or faults have come from empirical improvements in the field and synergism between monitored field treatments and independent laboratory research. One case history will be detailed, followed by a summary of several other treatments. Simple calculations can give at least a rudimentary indication of the width of the fracture or fault that causes excess water production. Using laboratory data coupled with field data collected before, during, and after gel injection, the calculations can also give an indication of how far the gel has actually penetrated into the fracture. Our analyses reveal critical measurements that should be made during field applications and where additional laboratory research is needed.
This paper demonstrates the connection between laboratory measurements and field results from gelant treatments in production wells at the naturally fractured Motatan field in Venezuela. Using a HPAM polymer with an organic crosslinker, laboratory corefloods revealed that under reservoir conditions, the gel provided oil and water residual resistance factors of 20 and 200, respectively. This gel was placed in several production wells in the Motatan field. In Well P-47, 1,000 bbl of this gel reduced the water cut from 97% to 64% and increased the oil production rate by 36%. The success of these treatments depends on the distance of gelant leakoff from the fracture face and the in situ residual resistance factors in the oil and water zones. Analyses were performed to determine these parameters, based on formation permeabilities, porosities, fluid saturations, fluid properties, fluid production rates, and pressure drops before, during, and after gelant placement. Accurate pressure drops before, during, and after gelant placement were particularly important. Sensitivity studies were performed to demonstrate their significance and the impact of measurement errors. A methodology is presented for optimizing the volume of gelant injected for these applications.
Previously published field results were examined to determine if they reveal usable guidelines for the selection of wells as candidates for gel treatments. Views of seven gel vendors and experts from eight major oil companies were also examined concerning the selection and implementation of gel treatments in injection and production wells.
This study demonstrates that gel treatments have been applied over a remarkably wide range of conditions. Unfortunately, the success rates for these projects have been very sporadic. Our analysis indicates that the producing water/oil ratio was usually the only criterion used to select candidate wells.
To improve the success rate for future gel applications, the source and nature of the water production problem must be adequately identified. Results from interwell tracer studies and simple injectivity and productivity calculations can be especially useful in this diagnosis. Recovery calculations should indicate that considerable mobile oil remains that could be recovered more cost-effectively if a blocking agent could be realistically placed in the proper location.
Improvements are needed in the methods used for sizing gel treatments. The method of sizing should be tailored to the type of channeling problem encountered. Five different types of channeling problems are discussed.
Conformance & Water Shut-Off: Concepts & Technology Overview
This document provides a synthesis of ideas, concepts and guidelines to help you diagnose the problem and choose the best fix to address excessive water production issues.
Conformance during polymer floods
In this presentation, I focus on conformance and water shut-off implementation during polymer flooding projects and how it differs from water floods.