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An enhanced-oil-recovery (EOR) pilot test has multiple goals, among them to demonstrate oil recovery, verify the properties of the EOR agent in-situ, and provide the information needed for scale-up to an economic process. Given the complexity of EOR processes and the inherent uncertainty in the reservoir description, it is a challenge to discern the properties of the EOR agent in-situ in the midst of geological uncertainty. We propose a general workflow and present a case study to illustrate this challenge: a polymer EOR process in a 2D layer-cake reservoir. The polymer is designed to have a viscosity of 60 cp in-situ. There is uncertainty in the reservoir description, represented here by a range of values of Dykstra Parsons coefficient and different spatial arrangements of layers. We allow that the polymer process might fail in-situ and viscosity could be 20% of that intended. We test whether the signals of this difference at injection and production wells would be statistically significant in the midst of the geological uncertainty. Specifically, we compare the deviation caused by loss of polymer viscosity to the scatter caused by the geological uncertainty using the statistical 95% confidence interval. Among the signals considered, the ‘rate of rise in injection pressure with polymer injection’ and ‘maximum injection pressure in the injector’ give the most reliable indications of whether a polymer viscosity was maintained in-situ. If unintended and uncontrolled fracturing of the injection well is considered likely during polymer injection, however, injection pressure may be an unreliable indicator of in-situ polymer viscosity. In that case a diagnostic fracture-injection/falloff test could produce the needed indication of polymer viscosity in-situ. ‘Polymer breakthrough time’ and ‘cumulative oil production at the end of process’ give indications of polymer in-situ loss in some of the cases. With a more severe viscosity loss, e.g. 90% or worse, these signals give a statistically significant indication of loss of polymer viscosity in all of the cases. [ABSTRACT FROM AUTHOR]

An integrated full-field reservoir simulation study has been performed to determine the reservoir management and production strategies in a mature sandstone reservoir. The reservoir is a candidate for an enhanced oil recovery process or otherwise subject to abandonment. Based on its charateristics, the reservoir was found to be most suited for a surfactant/polymer (SP) flood. The study started with a large data gathering and the building of a full-field three-dimensional geological model. Subsequently, a full field simulation model was built and used to history match the water flood. The history match of the water flood emphasizes the areas with remaining high oil saturations, establishes the initial condition of the reservoir for an SP flood, and generates a forecast of reserves for continued water flood operations. A sector model was constructed from the full field model and then used to study different design parameters to maximize the project profitability from the SP flood. An economic model, based on the estimated recovery, residual oil in-place, oil price, and operating costs, has been implemented in order to optimize the project profitability. The study resulted in the selection of surfactant and polymer concentrations and slug size that yielded the best economic returns when applied in this reservoir. The study shows that, in today’s oil prices, surfactant/polymer flood when applied in this reservoir has increased the ultimate oil recovery and provide a significant financial returns.

An integrated full-field reservoir simulation study has been performed to determine the reservoir management and production strategies in a mature sandstone reservoir. The reservoir is a candidate for an enhanced oil recovery process or otherwise subject to abandonment. Based on its charateristics, the reservoir was found to be most suited for a surfactant/polymer (SP) flood. The study started with a large data gathering and the building of a full-field three-dimensional geological model. Subsequently, a full field simulation model was built and used to history match the water flood. The history match of the water flood emphasizes the areas with remaining high oil saturations, establishes the initial condition of the reservoir for an SP flood, and generates a forecast of reserves for continued water flood operations. A sector model was constructed from the full field model and then used to study different design parameters to maximize the project profitability from the SP flood. An economic model, based on the estimated recovery, residual oil in-place, oil price, and operating costs, has been implemented in order to optimize the project profitability. The study resulted in the selection of surfactant and polymer concentrations and slug size that yielded the best economic returns when applied in this reservoir. The study shows that, in today's oil prices, surfactant/polymer flood when applied in this reservoir has increased the ultimate oil recovery and provide a significant financial returns. [ABSTRACT FROM AUTHOR]

Abstract: We investigate four different types of surfactants for effectiveness in tertiary oil recovery (TOR). The selected surfactant formulations were tested for enhanced oil recovery using coreflood tests on Berea sandstones. In addition to the corefloods, one sandpack surfactant flood was performed. The porous media were conditioned to residual waterflood oil saturation prior to surfactant slug injection. This was followed by polymer drive slug injection, and incremental oil recovery was measured against time. The tested formulations were selected after an extensive research effort including measuring interfacial tensions (IFT) and adsorption behavior on kaolinite clay. Effective were low 1-naphthol concentrations dissolved in 1-butanol in alkyl polyglycoside surfactant formulations which led to significant additional incremental oil recovery (40% TOR) due to dramatic reductions in IFT. Three other types of surfactants in this study include: [•] a di-tridecyl sulfosuccinic acid ester, [•] coconut diethanolamide, and [•] alkylpropoxy sulfate sodium salts which led to TOR of 15%, 75% and 35–50%, respectively. These results indicate that a wide variety of surfactants can meet the technical requirements as enhanced oil recovery (EOR) agents. [Copyright &y& Elsevier]

Abstract: Alkaline flooding appears to be a promising process for enhancing heavy oil recovery after primary or secondary production from those reservoirs where thermal processes are not applicable. However, due to the heterogeneity of the reservoirs, the injected chemical solutions may flow to the producing wells through the high permeable channels and bypass the residual oil, resulting in poor volumetric sweep efficiency. Thus, evaluating the chemical blends and the injection strategies through laboratory tests with proper heterogeneous physical models can substantially reduce the risks of field application of this process. In this study, a new experimental method, channelled-sandpack flooding test, is designed to simulate the channeling phenomenon of actual heavy oil reservoirs during the chemical flooding process. The channelled-sandpacks are used to re-evaluate the effectiveness of chemical blends screened through the homogeneous sandpack flood tests. It is found that the effectiveness of the best blend obtained through homogeneous sandpack flood tests is significantly reduced in the channelled-sandpack flood tests. This demonstrates that using heterogeneous physical model, rather than the conventional homogeneous sandpack flood tests, to screen the chemical blends is necessary for designing the chemical flooding process in heterogeneous heavy oil reservoirs. With further experiments carried out for the modified blends with the channelled-sandpack flood tests, an optimal chemical blend can be determined for certain heterogeneous reservoirs. The optimal chemical blend can selectively block the high permeability zones and improve the sweep efficiency for a particular heterogeneous sandpack, thereby significantly enhancing the tertiary oil recovery. The new developed channelled-sandpack flood test should facilitate the optimization, design and implementation of chemical flooding and other enhanced heavy oil recovery processes. [Copyright &y& Elsevier]

Surfactant loss is one of the major concerns with chemical oil recovery processes in which surfactant is one of the components of the chemical formula. Surfactant loss due to adsorption on the reservoir rocks weakens the effectiveness of the injected chemical slug in reducing oil–water interfacial tension (IFT) and makes the process uneconomical. Adsorption-related interfacial tension behavior and its effect on oil recovery has not been understood completely.This paper reports the investigation of oil–water IFT behavior when the chromatographic separation of the surfactant mixture occurs during surfactant/alkaline corefloods. In this work, surfactant and alkaline concentrations in the effluent of corefloods and oil–water interfacial tension were determined under different injection strategies. It was found that, in an extended waterflood following an alkaline-surfactant slug injection, surfactant desorbed into the water phase. This desorption of surfactant lasted for a long period of the waterflood. Although the concentration of the desorbed surfactant in the extended waterflood was very low, an ultra-low oil–water IFT was obtained by using a suitable alkaline concentration. Coreflood results showed that an additional 13% of the initial oil in place (IOIP) was recovered after the alkaline–surfactant injection by the synergism of the desorbed surfactant and alkaline. This result indicates that the efficiency and economics of a chemical flood could be improved by utilizing the desorbed surfactant during extended waterflood processes. [Copyright &y& Elsevier]