A common problem in many waterflooded oil reservoirs is early water breakthrough with high water cut through highly conductive thief zones. Thermally active polymer (TAP), which is an expandable submicron particulate of low viscosity, has been successfully used as an in-depth conformance to improve sweep efficiency of waterfloods.This paper describes the workflow to evaluate technical feasibility of this conformance technology for proper pilot-project designs supported with detailed simulation studies. Two simulation approaches have been developed to model properties of this polymer and its interaction with reservoir rock. Both methods include temperature-triggered viscosification and adsorption/retention effects. Temperature profile in the reservoir is modeled by energy balance to accurately place this polymer at the optimum location in the thief zone. The first method considers a single chemical component in the water phase. The second method is based on chemical reactions of multiple chemical components. Both simulation approaches are compared and discussed.Results show that temperature-triggered polymers can increase oil recovery by viscosification and chemical adsorption/retention, which reduces thief-zone permeability and diverts flow into unswept zones. Sensitivity analyses suggest that ultimate oil recovery and conformance control depend on the thief-zone temperature, vertical-to the horizontal-permeability ratio (K v /K h ), thief-zone vertical location, injection concentration and slug size, oil viscosity, and chemical adsorption and its reversibility, among other factors. For high-flow-capacity thief zones and mobility ratios higher than 10, oil recoveries can be improved by increasing chemical concentration or slug size of treatments, or both. Reservoirs with low K v /K h (< 0.1) and high permeability contrast generally shows faster incremental recoveries than reservoirs with high K v /K h and strong water segregation.The presented workflow is currently used to perform in-depth conformance treatment designs in onshore and offshore fields and can be used as a reference tool to evaluate benefits of the TAP in waterflooded oil reservoirs.Gholamreza Garmeh is a Reservoir Engineer at TIORCO. He is responsible for modeling and design of chemical-flooding and conformance-improvement projects. His research interests are chemical and miscible gas EOR techniques and numerical reservoir simulation. He holds a BS degree from the Petroleum University of Technology in Iran and MS and PhD degrees from the University of Texas at Austin, all in petroleum engineering. He serves as peer-reviewer for SPEREE and SPE Journal.Mehdi Izadi is a Senior Reservoir Engineer at TIORCO. He has more than 9 years of experience in reservoir simulation and EOR techniques. He is responsible for modeling and design of chemical-flooding projects and support of post-treatment

A common problem in many waterflooded oil reservoirs is early water breakthrough with high water cut through highly conductive thief zones. Thermally active polymer, which is an expandable sub-micron particulate of low viscosity, has been successfully used as an in-depth conformance to improve sweep efficiency of waterfloods. This paper describes the workflow to evaluate technical feasibility of this conformance technology for proper pilot project designs supported with detailed simulation studies. Two simulation approaches have been developed to model properties of this polymer and its interaction with reservoir rock. Both methods include temperature triggered viscosification and adsorption/retention effects. Temperature profile in the reservoir is modeled by energy balance to accurately place this polymer at the optimum location in the thief zone. The first method considers a single chemical component in the water phase. The second method is based on chemical reactions of multiple chemical components. Both simulation approaches are compared and discussed. Results show that temperature-triggered polymers can increase oil recovery by viscosification and chemical adsorption/retention, which reduces thief zone permeability diverting flow into unswept zones. Sensitivity analyses suggest that ultimate oil recovery and conformance control depends on the thief zone temperature, vertical to horizontal permeability ratio (Kv/Kh), thief zone vertical location, injection concentration and slug size, oil viscosity, chemical adsorption, and its reversibility, among others. For high flow capacity thief zones and mobility ratios higher than 10, oil recoveries can be improved by increasing chemical concentration or slug size of treatments, or both. Low Kv/Kh (&lt; 0.1) and high permeability contrast generally shows faster incremental recoveries than high Kv/Kh with strong water segregation reservoirs. The presented workflow is currently used to perform in-depth conformance treatment designs in on-shore and off-shore fields and can be used as a reference tool to evaluate benefits of the thermally active polymer in waterflooded oil reservoirs.

Summary Mixing of miscible gas with oil in a reservoir decreases the effective strength of the gas, which can adversely affect miscibility and recovery efficiency. The level of true mixing that occurs in a reservoir, however, is widely debated and often ignored in reservoir simulation in which very large grid blocks are used. Large grid blocks create artificially large mixing that can cause errors in predicted oil recovery. This paper examines mixing that occurs in porous media by solving for single-phase flow in a connected network of pores. We differentiate between true mixing that can reduce the effective strength of a miscible gas or surfactant from apparent mixing caused by convective spreading. This work differs from network models in that we directly solve the Navier-Stokes equation and the convection-diffusion equation to determine the velocities and concentrations at any location within the pores. Flow in series and layered heterogeneous porous media are modeled through use of many grains in different arrangements. We consider slug, continuous, and partial injection as well as echo tests (single-well tracer tests) and transmission tests (interwell tracer tests). We match the concentrations from the pore-scale simulations to the analytical convection-dispersion solution that includes both transverse- and longitudinal-dispersion coefficients. The results show that for flow in series and in layers, echo- and transmission-longitudinal dispersivities become equal and reach an asymptotic value if complete mixing over a cross section perpendicular to flow has occurred. In practice, the asymptotic value of dispersivity may never be reached, depending on pattern-scale heterogeneity and well spacing. Transverse-dispersion coefficients also are scale dependent, but they decrease with traveled distance. We further demonstrate that the classical Perkins-Johnston relationship between longitudinal-dispersion coefficient and fluid velocity is obtained. We conclude that echo dispersivities are reliable indicators of true mixing in porous media.

Mixing of miscible gas with oil in a reservoir decreases the effective strength of the gas, which can adversely affect miscibility and recovery efficiency. The level of true mixing that occurs in a reservoir, however, is widely debated and often ignored in reservoir simulation where very large grid blocks are used. Large grid blocks create artificially large mixing that can cause errors in predicted oil recovery. This paper examines the mixing that occurs in porous media by solving for single-phase flow in a connected network of pores. This work differs from network models in that we directly solve the Navier-Stokes equation and the convection-diffusion equation to determine the velocities and concentrations at any location within the pores. Flow in series and layered heterogeneous porous media are modeled by using many grains in different arrangements. We consider both slug, continuous, and partial injection as well as echo tests (single-well tracer tests) and transmission tests (interwell tracer tests). We match the concentrations from the pore-scale simulations to the analytical convection dispersion solution that includes both transverse and longitudinal dispersion coefficients. The results show that for flow in series and in layers, echo and transmission longitudinal dispersivities become equal and reach an asymptotic value if complete mixing over a cross section perpendicular to flow has occurred. In practice, the asymptotic value of dispersivity may never be reached depending on pattern-scale heterogeneity and well spacing. Transverse dispersion coefficients also are scale dependent, but they decrease with traveled distance. We further demonstrate that the classical Perkins-Johnston relationship between longitudinal dispersion coefficient and fluid velocity is obtained. We conclude that echo dispersivities are reliable indicators of true mixing in porous media. Introduction Oil recovery from miscible gas floods is highly dependent on the magnitude of mixing at the field or pattern scale.1–4 Mixing acts to drive the composition route further into the two-phase region and away from the critical locus in multicontact miscible floods. Because the composition route moves further away from the critical locus and deeper into the two-phase region, the local displacement efficiency is reduced, in some cases, by nearly half of incremental oil recovery (recovery post waterflood).3–4 If reservoir mixing is large, good recovery efficiency may require operating at pressures well above the minimum miscibility pressure (MMP) or beyond the minimum enrichment for miscibility (MME).3–5 Numerical dispersion is also present in reservoir simulations, which can significantly increase mixing when large grid-block sizes are used. Methods that achieve low mixing, such as those used in streamline simulation, may reduce the level of mixing below that which is expected at reservoir scale. Streamline simulations may also not adequately include crossflow between streamlines. It is important to determine the appropriate level of dispersion at reservoir scale so that we can attempt to model it correctly. Mixing in a reservoir is primarily caused by molecular diffusion of solute (or gas) from one stream line to the next within the pores. Mixing causes dilution of the gas, which can decrease oil recovery. Reservoir mixing is enhanced by any mechanism that increases the area of contact between the gas and the oil, thereby allowing the effects of diffusion to be magnified. This is in essence the cause of scale-dependent dispersion. The longer the distance traveled of a solute the greater the area exposed to diffusion and the longer time diffusion has to work. The contact area grows primarily because of variations in streamlines and their velocities around grains and through layers of various permeabilities (heterogeneity). Crossflow, such as that caused by gravity, can also allow for greater mixing when a fluid of different density than the reservoir oil is injected. Mixing can also be enhanced by the effects of other neighboring wells (fluid drift), and by differences in chemical potentials between components in different phases, that is, by phase mass transfer.

Inaccurate modeling of reservoir mixing by using large grid blocks in compositional simulation can significantly affect recoveries in miscible gas floods and lead to inaccurate predictions of recovery performance. Reservoir mixing or dispersion is caused by diffusion of particles across streamlines; mixing can be significantly enhanced if the surface area of contact between the reservoir and injected fluid are increased as fluids propagate through the reservoir. A common way to convert geological models into simulation models is to upscale permeabilities based on reservoir heterogeneity. Upscaling affects the degree of mixing that is modeled, but the importance of reservoir mixing in upscaling is largely ignored. This paper shows how to estimate the level of mixing in a reservoir and how to incorporate mixing into the upscaling procedure.We derive the key scaling groups for first-contact miscible (FCM) flow and show how they impact reservoir mixing. We examine only local mixing, not apparent mixing caused by variations in streamline path lengths (convective spreading). Local mixing is important because it affects the strength of the injected fluid, and can cause an otherwise multicontact miscible (MCM) flood to become immiscible. Over 800 2-D numerical simulations are carried out using experimental design to estimate dispersivity as a function of the derived scaling groups.We show that reservoir mixing is enhanced owing to fluid propagation through heterogeneous media. Because mixing is dependent on heterogeneities, upscaling is an iterative process where the level of mixing in both the longitudinal and transverse directions must be matched from the fine to coarse scale. The most important groups that affect mixing are the mobility ratio, dispersion number, correlation lengths, and the Dykstra-Parson's coefficient. Large dispersion numbers yield greater dispersivities away from the injection well. We show through simulations of both FCM and multi-contact miscible (MCM) floods that grid-block size can be significantly increased when reservoir mixing is large. Heterogeneous reservoirs with large longitudinal correlation lengths can be upscaled to larger grid blocks than reservoirs with random permeability fields. This paper shows how to determine a priori the maximum grid-block size allowed in both the x-and z-directions to predict accurately the oil recovery from miscible gas floods. SPE 124000traveled. Convective spreading, therefore, causes an apparently large level of mixing not representative of actual mixing in the reservoir. In this paper, we are concerned only with actual mixing, which we label as local dispersion.Mixing is relatively small at the scale of a slim-tube experiment because of the homogeneity of the media used, and the relatively short distances involved. Dispersivities measured in core-flood experiments are caused by molecular diffusion across streamlines associated with microscopic heterogeneities and tortuosity of the permeable media (Bear 1961; Freeze and Cherry 1997;Sternberg et al. 1996)...

A comprehensive laboratory study was performed to look at a thermally activated polymer (TAP) for conformance correction applications. The focus of study was to see if BrightWater® (a TAP polymer) could perform in high permeability porous media by creating flow resistance to injected fluid, hence enhancing the sweep efficiency. Furthermore, the possibility of enhancing the TAP performance by increasing the solution concentration was investigated. A set of 20-inch long slimtubes packed with acid-washed quartz sand were used to evaluate the performance of two TAP grades at 85°C in a range of 1 to 5 Darcy. Additionally, another set of short slimtubes were used to examine the performance of two low-temperature activation TAP grades at 30°C in the range of 200 to 1300 md. Results showed that residual resistance factor (RRF) values of 2 to 12 could be achieved at 5000 ppm active concentration for the range of permeability tested here. RRF values increased by increasing the concentration to 10,000 ppm active polymer. Low-temperature activation polymers showed RRF values of 10 to 50 depending on the permeability of the short sandpacks tested at 30°C. TAP simulation approaches are also described.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractMixing of miscible gas with oil in a reservoir decreases the effective strength of the gas, which can adversely affect miscibility and recovery efficiency. The level of true mixing that occurs in a reservoir, however, is widely debated and often ignored in reservoir simulation where very large grid blocks are used. Large grid blocks create artificially large mixing that can cause errors in predicted oil recovery.This paper examines the mixing that occurs in porous media by solving for single-phase flow in a connected network of pores. This work differs from network models in that we directly solve the Navier-Stokes equation and the convectiondiffusion equation to determine the velocities and concentrations at any location within the pores. Flow in series and layered heterogeneous porous media are modeled by using many grains in different arrangements. We consider both slug, continuous, and partial injection as well as echo tests (single-well tracer tests) and transmission tests (interwell tracer tests). We match the concentrations from the pore-scale simulations to the analytical convection dispersion solution that includes both transverse and longitudinal dispersion coefficients.The results show that for flow in series and in layers, echo and transmission longitudinal dispersivities become equal and reach an asymptotic value if complete mixing over a cross section perpendicular to flow has occurred. In practice, the asymptotic value of dispersivity may never be reached depending on pattern-scale heterogeneity and well spacing. Transverse dispersion coefficients also are scale dependent, but they decrease with traveled distance.We further demonstrate that the classical Perkins-Johnston relationship between longitudinal dispersion coefficient and fluid velocity is obtained. We conclude that echo dispersivities are reliable indicators of true mixing in porous media.

A common problem of waterflooded oil reservoirs is the premature water breakthrough bypassing high remaining oil saturation in unswept zones that are risky targets for infill and sidetrack drilling. Early water breakthrough can be caused by reservoir heterogeneity and unfavorable mobility ratios of oil and injected water. There are several IOR/EOR technologies that can be used to reduce water production and increase sweep efficiency. Polymer gels ("Conformance treatments"), polymer flooding and Colloidal Dispersion Gels (CDG) are some of the technologies most commonly used during the last few decades. However, the applicability of a given technology will depend on the problem (e.g., water channeling, adverse mobility, etc.) and its applicability under given reservoir conditions (e.g., temperature, salinity, lithology, and injection and fracturing pressures, among others).The purpose of this paper is to describe screening criteria for thermally-activated polymer (TAP) flooding technology implementation before starting detailed project evaluations. Based on the suggested screening criteria and evaluation approach, it is possible to rank patterns or asset candidates for in-depth conformance treatments to improve sweep efficiency or delay premature water breakthrough. This is especially important for projects in remote areas or in offshore conditions where water handling is costly.Based on field experiences, laboratory experiments, and new simulation approaches that are being continually improved, indepth conformance treatments are carefully designed before pilot or asset implementation.The proposed screening methodology was used to evaluate and rank temperature-triggered polymer applicability in more than 20 Russian oil fields. Results show how to identify good or poor candidates to evaluate the technology, which increases the probability for successful implementation. In some other instances the combination of technologies might be required to maximize ultimate recoveries.