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Alkaline flooding has been purported to be a promising process for enhancing heavy-oil recovery, while alkaline/polymer (AP) and alkaline/surfactant/polymer (ASP) injection represent commercial flooding strategies for lighter oils. The alkali in an ASP flood can reduce adsorption of surfactants and react with acids in the oil to form soaps. Polymers increase the viscosity of water and control mobility ratio. The addition of an alkali to a straight polymer flood can further increase the efficiency in polymer flooding. The alkali can react with the rock and polymer to reduce polymer adsorption and decrease polymer-solution viscosity to allow higher injectivity.We report results of core experiments for polymer, alkali, and AP tertiary floods. The conditions tested correspond to Wyoming's Minnelusa sandstone reservoirs. Berea cores were waterflooded to residual-oil saturation, and then a tertiary injection of a polymer, alkali, or AP solution was run, followed by waterflooding. We also show results of polymer-solution viscosity with varying alkali concentration. Polymer-adsorption results from dynamic and static experiments with and without alkali are reported. Numerical history match of coreflooding results was performed using CMG-STARS.Results show that a tertiary alkali injection produces negligible oil recovery and pressure-drop increase. Straight polymer injection produces considerable oil recovery with a significant increase in pressure drop that may not be favorable for field designs. The injection of the AP solution also produced considerable oil recovery, but the increase in pressure drop was less than that of the straight polymer flood. The effects of alkali on polymer and rock surface lead to a significant impact on recovery factor, resistance factors, and also residual resistance factors.Results of this study demonstrate one of the benefits of adding alkalis in polymer flooding-namely, the improvement in injectivity-in addition to the known reduction in polymer losses because of adsorption on the rock surface. The modeling strategy should help with alkali-enhanced polymer-flooding designs.

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Alkali-surfactant-polymer (ASP) flooding is a commercially viable enhanced oil recovery method. The complexity of chemical interactions, multi-phase flow, emulsification, capillary number changes and upscaling issues, especially in highly heterogeneous reservoir, make field designs difficult to extrapolate from coreflood measurements. In this work, two representaions of low interfacial tension conditions in chemical flooding were evaluated to determine the impact of model formulation on scaling-up from lab data to field situations. The first one is a mechanistic model based on interpolation of relative permeability curves parametrized with respect to the local capillary number. The second model requires tracking a thermodynamically stable phase known to exist at water-oil ultralow interfacial tension, namely a microemulsion. To perform this analysis, two sets of chemical coreflooding results were history matched and then the tuned models were utilized for field-scale predictions. For ASP flooding, a sensitivity analysis was implemented to show the importance of microemulsion phase on ASP upscaled (field scale) forecast. In this study, coreflooding experiments were performed using three different crude oils, case I: heavy oil with high acid number, case II: medium oil with high acid number and finally, case III: light oil with very low acid number. Predictions between the two modeling approaches are shown to diverge from each other upon upscaling of core-scale history matched models. This discrepancy is mostly attributed to the need to track a microemulsion phase behavior as well as its properties. Effects are more pronounced for heavier oil with high acid number. The results of this analysis should be useful to constrain field projections of any field design of surfactant-assisted EOR projects. Additionally, this study provides guidelines to understand existing uncertainties in current chemical flooding simulation regarding our ability to accurately predict the results of such a chemical flood design.

In recent years, the United States (US) has experienced a resurrection in hydrocarbon recovery owing to the extraction of oil and gas from unconventional resources. Due to the ultra-low permeability nature of these reservoirs and their oil-wet characteristics, oil production declines are steep and oil recoveries remain very low (< 12% of OOIP). This challenge endures even with the assistance of hydraulic fracturing advancements and well spacing optimizations. The billions of barrels of remaining oil is a good target for chemical enhanced oil recovery (EOR) technologies. In this study, after comprehensive laboratory testing, a series of customized chemical formulations was developed to improve oil recovery under the challenging conditions of the Middle Bakken and Niobrara formations (temperature >110 °C, salinity>220,000 ppm, and hardness>15,000 ppm). To examine the performance of the selected formulation in the field-scale, a single well enhancement trial was carried out. A detailed review of the lab and field data (pre-and post- treatment) is discussed in this study. Oil rate decline analysis and numerical simulations were used to obtain more insight about the true effectiveness of the chemical treatments. The results of this field trial reveal that injecting a proper wettability altering agent can improve oil recovery from shale oil reservoirs by up to 25% of the estimated ultimate recovery (EUR). The results of numerical simulations also show that the additional oil recovered in this field trial cannot be achieved by either well shut-in or straight water injection. The lessons learned from this study provide practical information to optimize similar field trial designs leading to more profitable projects. The concepts and information here can be also translated to other unconventional basins and gas condensate or wet/dry gas reservoirs.

Colloidal Dispersion Gels (CDG's) have been successfully tested in Argentina, China, USA, and recently in Colombia. However, questions remain whether CDG's can be injected in large volumes and propagate deep into the formation without reducing injectivity and also improve sweep efficiency. This paper summarizes 31 implemented and ongoing CDG projects in Argentina, Colombia and the U.S. since 2005. Project summary review includes main reservoir properties, operating conditions, pore volume of chemical injected, general project performance, and especially, a detailed analysis of injection logs addressing the injectivity of CDG. Additionally, a general approach for history matching CDG floods is described. CDG injection volumes in projects reviewed vary from a few thousand barrels to hundreds of thousands of barrels. Projects evaluated did not show injectivity reduction even after more than 600,000 barrels injected in one well. Polymer concentration and polymer: crosslinker ratios ranged from 250 to 1,200 ppm and 20:1 to 80:1, respectively. Aluminum citrate is the most common crosslinker used in field projects. However, chromium triacetate has been used in high salinity and hardness conditions. Key variables to sustain the injection of large volumes of CDG below maximum operating pressure are polymer: crosslinker ratios, polymer concentration, and injection rates to a lesser extent. CDG projects have evolved from small to large treatment volumes showing a positive impact on oil recoveries. Despite large volumes of CDG injected production of polymer in offset producers has rarely been detected. Wellhead pressure response, CDG viscosity, and adsorption/retention (RRF) represents the most important variables needed to match CDG floods. This study provides the status of the technology and field evidence that CDG's can be injected in large volumes and can propagate into the reservoir without injectivity constraints. This review will also provide guidance to successfully design and evaluate CDG pilot projects. Lessons learned from operating and modeling CDG projects will also be presented.

Alkaline flooding, either for enhancing heavy oil recovery, or in alkaline-polymer (AP) and alkaline-surfactant-polymer (ASP) flooding for lighter oils, represents an important EOR strategy. Injection of alkaline solutions leads to mineral dissolution and precipitation with likely resulting changes in permeability and porosity of reservoirs, which in turn alter solution pH. Accurate prediction of pH, alkali consumption and aqueous chemistry changes are required to design suitable chemical flooding blends.Excessive consumption of alkali can result in degradation of flood performance and lower than expected oil recovery.We report results of state-of-the-art geochemical simulations for sandstone reservoir mineral assemblages and alkali solutions (NaOH, Na 2 CO 3 , and NaBO 2 ) employed in AP and ASP formulations. The strategy has been tested for conditions of the State of Wyoming in Minnelusa reservoir and Berea sandstones. Single-phase high-pH floods were completed in the lab to calibrate and validate geochemical simulations.Results show that rock-fluid interactions are a strong function of mineral type and amount, alkaline solution injection flowrate, and composition of injected and formation water. It is found that anhydrite has a significant impact on pH buffering capacity, water chemistry changes and permeability damage against conventional alkali agents in chemical flooding particularly in the case of Na 2 CO 3 , but no significant pH buffering is observed during NaBO 2 flooding. Experimental data and model results show that the pH-buffering effect is maintained even after several pore volumes of alkaline solution are injected, if a sufficient fraction of relevant minerals are present. Comparison between linear core and field flooding simulations show that short reaction times tend to minimize these effects and may lead to conclusions that cannot be readily transferred to field cases.By applying reaction-transport modeling, the design of chemical flooding can be improved and formulation effectiveness losses caused by reservoir mineralogy can be avoided, even in cases where traditional laboratory screening procedures would indicate a suitable formulation for chemical flooding.