Water shut-off & conformance - Placement Concepts

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.

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.

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.

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 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.

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.

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.