In contrast to near-wellbore conformance control applications, polymer gels are applied in injector wells for reservoir scale applications for in-depth fluid diversion (IFD). Novel gel systems include weak gels, sequential injection for in-situ gels, colloidal dispersion gels, preformed gels, and microgels. The objective of an IFD process is to modify the prevailing reservoir inflow profile by gel treating the reservoir to significantly reduce effective permeability of high permeability zones that would otherwise dominate the water uptake. The weak gels or gel particles are treated as a flowing fluid and are custommade for reservoirs with fractures or high permeability zones. The very weak gels form near the wellbore region, but continue to propagate into the reservoir. The gels eventually stop propagating deeper into reservoir due to the variation in pressure gradients and pore structures. The subsequent injection of fluids, water or chemical solutions, will redirect predominate flow paths to unswept reservoir zones, which improves oil sweep efficiency by waterflood (or chemical flood); thus, leading to enhanced oil recovery. The technology presents distinctive advantages to high-salinity and high-temperature reservoirs as compared to polymer flooding due to stability of cross-linked gel structures.This paper presents a state-of-the-art review of IFD technologies including weak gels, sequential injection for in-situ gels, colloidal dispersion gels (CDG), microgels, and preformed particle gels (PPG). Moreover, a solution to the challenges of IFD applications in high-salinity and high-temperature reservoirs is presented.

Summary The extreme heterogeneity of carbonate in the form of fracture corridors and superpermeability zones challenges the efficient sweep of oil in both secondary- and tertiary-recovery operations. In such reservoirs, conformance control is crucial to ensure injected water and any enhanced-oil-recovery (EOR) chemicals optimally contact the remaining oil with minimal throughput. Gel-based conformance control has been successfully applied on both sandstone and carbonate reservoirs. Achieving effective deep conformance control in high-temperature reservoirs, however, remains a challenge because of severe gel syneresis and significant reduction in gelation time. The first step to improve the performance of gel in these challenging environments is the accurate understanding of the gel-conformance-control mechanism inside reservoir rocks. In this work, a laboratory study was conducted to evaluate a polyacrylamide/chromium gel system for application in a high-temperature/high-salinity carbonate reservoir. Oil-displacement experiments on carbonate-core samples, combined with nuclear-magnetic-resonance (NMR) measurements, were performed to demonstrate oil-recovery improvement using gel treatment and to illustrate the mechanisms of the improvement. In these tests, the gel solution was injected into specially prepared heterogeneous carbonate-composite-core samples, in which different configurations of high-permeability channels were created. Gel treatment was conducted after waterflooding and was followed by chase waterflooding. Oil-recovery improvement by gel treatment was 18% of original oil in core (OOIC) in the composite core with high-permeability channels extending midway through the composite, whereas the improvement was 38% of OOIC in the composite core with channels extending all the way through the composite. Detailed spatial fluid variations inside the core samples before and after gel treatment were closely monitored using low-field NMR techniques. Heavy water (D2O) was used in place of water to enhance the contrast between oil and brine for NMR by eliminating the protons in the aqueous phase. NMR measurements indicated that the bypassed oil during waterflooding was effectively recovered after gel treatment. Results in this study demonstrate the potential of the studied gel system and its favorable effect on the sweep-efficiency-improvement application in high-temperature/high-salinity carbonate reservoirs. The NMR study enhances our understanding of how gel helps improve the sweep efficiency of subsequent floods through blocking/reducing the permeability of highly conductive zones.

Water flooding typically recovers about 50% of the original oil in place leaving much oil in the reservoir. Recovery efficiency in fractured reservoirs can be dramatically lower in comparison to conventional reservoirs because water channels selectively from injector to producer leaving considerable oil within the matrix and uncontacted by injected water. An enhanced recovery process is needed to access such oil held in the reservoir matrix. Addition of aqueous surfactants to injection water dramatically reduces oil/water interfacial tension and surfactant may adsorb to oil-wet rock surfaces inducing a shift in wettability that improves the imbibition of water. At the pore level, capillary forces are responsible for oil trapping and generally dominate over viscous and gravitational forces. Because of the reduction in interfacial tension between oil and water with the addition of surfactant, the role of capillary forces on fluid flow can be minimized. When gravity parameters are large enough to give a Bond number (ratio of gravity to capillary forces) greater than 10, gravitational forces become more dominant and oil held with rock matrix by capillarity may be released as a result of buoyancy. In this work, we use experiments conducted in two-dimensional micromodels to investigate the effect of gravity at low interfacial tension. The micromodels have the geometrical and topological characteristics of sandstone and the network is etched into silicon. Porelevel mechanics are observed directly via a reflected-light microscope. A screening study of sulfonate and sulfate surfactants was conducted to choose an appropriate system compatible with the light crude oil (27°API). A variety of flow behavior through the microscope is investigated including forced and spontaneous imbibition. Results are illustrated via pore-level photo and image analysis of microscopic pictures of the micromodel. Forced displacements are conducted at realistic flow rates to maintain a 1 m/day Darcy velocity and at surfactant concentrations of 0.9% to 1.25%. Forced displacement with a horizontal or vertical positioning of the micromodel yields dramatic improvement of recovery for surfactant injection cases. Most of the oil retained after a waterflood was recovered by tertiary injection of surfactant solution. In comparison, about 25% oil saturation remained after a waterflood.

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Summary Oil recovery by waterflood is usually small in fractured carbonates because of selective channeling of injected water through fractures toward producers, leaving much of the oil trapped in the matrix. One option to mitigate the low recovery is to reduce fracture uptake by increasing the viscosity of the injected fluids by use of polymers or foams. Another option, that is the objective of this work, is to inject surfactant solutions to reduce capillary effects responsible for trapping oil and allow gravity to segregate oil by buoyancy. Analysis of gravity and capillary forces suggests that such segregation is achievable in the laboratory, provided that cores are moderately long and oriented vertically. Besides investigating the role of gravity on oil recovery, the effect of surfactant-flood mode (secondary-flood mode and tertiary-flood mode) on the ultimate recovery (UR) was also investigated. To investigate the predictions of this analysis, coreflood experiments were conducted by use of carbonate cores and monitored by an X-ray computed-tomography (CT) scanner featuring true vertical positioning to quantify fluid saturation history in situ. Novel aspects of this work include cores that are oriented both horizontally and vertically to maximize gravitational effects as well as a special core holder that mimics aspects of fractured systems by use of the whole core. This paper discusses the contrast in experimental results in vertical and horizontal orientation with and without surfactant. To study gravity effects, surfactant reduced interfacial tension (IFT) from 40 to 3 mN/m. For this mode of recovery, ultralow IFT is not preferred because some capillary action is needed to aid injectant transport into the matrix. The vertical experiment showed that gravity has the potential of improving oil recovery at low IFT. Another surfactant was used to study the flood-mode effect; this surfactant reduced IFT from 40 to 0.001 mN/m (ultralow IFT). In this study, two experiments were conducted: a tertiary-surfactant-flood experiment and a secondary-surfactant-flood experiment. The secondary-flood experiment showed an improvement in recovery with the early implementation of the surfactant flood relative to the tertiary-flood experiment. This work highlights the importance of gravity at low IFT in terms of mobilizing trapped oil and also the effect of flood mode on UR. Moreover, this work emphasizes the use of surfactant solutions as a method of enhancing oil recovery in fractured resources not necessarily because of wettability alteration but mainly because of gravity effects. Experimental results are presented primarily as 1D and 3D reconstructions of in-situ oil- and water-phase saturation obtained by use of X-ray CT.