Water shut-off & conformance - Placement Concepts

Many different materials have been proposed to reduce channeling of fluids through fractures and high-permeability streaks, including gels, particulates, precipitates, microorganisms, foams, and emulsions. This paper compares their placement and permeability reduction properties. Comparisons focus on selectivity in entering high-permeability rock preferentially over low-permeability rock, and ability to reduce permeability more in high-permeability water-saturated zones than in low-permeability oil-saturated zones. Concepts are identified that may lead to blocking agents with placement or permeability-reduction properties superior to those of conventional gels

When production wells stimulated by hydraulic fracturing unintentionally break into water zones, substantially increased water production results. This paper develops an engineering basis for designing and sizing gelant treatments in hydraulically fractured production wells. Gelant penetrates a short distance from the fracture face into porous rock associated with both water and hydrocarbon zones. Success requires that the gel reduce permeability to water much more than to hydrocarbons. A simple 11-step procedure for sizing these gelant treatments was developed and incorporated into user-friendly graphical-user-interface software. Prior to this work, gelant volume sizing was strictly empirical with no engineering basis.

This paper investigates whether foams can show placement properties superior to those of gels and gelants when used as blocking agents for conformance control. Specifically, whether the concept of limiting capillary pressure can be exploited to form a persistent, low-mobility foam in high-permeability zones while preventing foam from entering and damaging low-permeability zones. Using a C14-16 alpha-olefin sulfonate and nitrogen, foam mobilities were measured in cores with permeabilities from 7.5 to 900 md at 750 psig back pressure and 104°F, with foam qualities from 50% to 95% and Darcy velocities from 0.5 to 100 ft/d. Residual resistance factors during brine injection after foam placement were also extensively characterized.

This study explores the influence of diffusion, dispersion, and viscous fingering during placement of gels for injection profile modification. 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. The study evaluates the effect of each phenomenon across a range of permeability contrasts and well types.

Two theoretical models determine water injection profiles before and after gel placement in anisotropic reservoirs where effective permeability or pressure gradient is greater in one horizontal direction than another. The primary question: how anisotropic must an unfractured reservoir be for acceptable gel placement and profile modification during unrestricted gelant injection? Both analytical and numerical methods were applied. Permeability anisotropy (most-permeable direction divided by least-permeable direction) must exceed 1,000 — and usually exceed 10,000 — before anisotropy can be exploited for acceptable gel placement in unfractured wells. No unfractured reservoir is likely to have this level of anisotropy. In contrast, fractures provide the linear flow geometry and extreme permeability contrast needed to aid gel placement substantially.

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 oil-productive zones are extremely high, oil productivity will be damaged even if the gel reduces water permeability without affecting oil permeability. Capillary pressure does not prevent gelant penetration into oil-productive zones in field applications. An explanation is provided for the occurrence of successful gel applications in fractured wells produced by bottomwater drive. With the right properties, gels could significantly increase the critical rate for water influx in fractured bottomwater-drive wells.

This paper examines reservoir variables that affect the severity of channeling and the potential of gel treatments for reducing channeling through naturally fractured reservoirs. Tracer and gel placement studies were performed with two different simulators. Gel treatments have the greatest potential when fractures aligned with direct flow between injector-producer pair have conductivities at least 10 times greater than off-trend fractures. Gel treatments also have the greatest potential in reservoirs with moderate to large fracture spacing. Tracer transit times from interwell tracer studies can estimate the conductivity of the most direct fracture. Gel treatment effectiveness is insensitive to fracture spacing for on-trend fractures but increases with increased fracture spacing for off-trend fractures.

This study investigates how flow profiles in injection wells are modified when zones are not isolated during placement of gelling agents. Mathematical models examine gel penetration and injectivity loss in zones of different permeability. Key conclusions: zone isolation is far more likely to be needed in unfractured wells than in fractured wells; productive zones in unfractured wells may be seriously damaged without isolation; gel placement causes least damage when (a) gelant resistance factor is low, (b) water-oil mobility ratio is high, (c) the most-permeable layers are watered-out, and (d) water fronts are not close to the production well in productive zones. Parallel linear corefloods overestimate the degree of profile modification achievable in radial systems. Chemical retention, dispersion and diffusion will probably not significantly mitigate injectivity losses from gelant penetration into low-permeability zones.

This study investigates whether the non-Newtonian rheology of gelling agents can be exploited to eliminate the need for zone isolation during gel placement in injection wells. Eight different rheological models were applied 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 (unfractured wells). This finding has important implications for field gel treatment design.

This paper studies gel placement in stratified reservoir systems where communication exists between layers (crossflow). Gel placement details are strongly affected by the level of interlayer communication, characterized by proximity to vertical equilibrium (VE) conditions. In systems close to VE, viscous crossflow can cause considerable volumes of gelant injected into the high-permeability layer to flow into low-permeability layers, where subsequent gel formation can seriously reduce subsequent waterflood performance. Results from experimental displacements in layered beadpacks and supporting numerical simulations demonstrate the central role of viscous crossflow in gel treatment outcomes for heterogeneous reservoirs.