No abstract

Summary Gas-aided gravity drainage is a common oil-recovery technique in anticline-shaped oil reservoirs. If the permeability is low and the reservoir is oil-wet, the remaining oil saturation can be quite high. The goal of this work is to mobilize a part of this oil by surfactant injection. An anionic-surfactant formulation was developed to alter wettability and lower interfacial tension (IFT) for a gasflooded, carbonate reservoir. Different coreflood strategies, including gas/water/surfactant/water (GWSW), gas/surfactant/gas (GSG), gas/surfactant/water (GSW), and gas/surfactant/water/gas (GSWG) floods, were investigated. GSG, GWSW, and GSWG corefloods conducted in limestone cores recovered an additional 40–50% of the original oil in place (OOIP) because of the injection of surfactant. GSW corefloods conducted in a vuggy dolomite recovered less: an approximately 20%-of-OOIP incremental recovery. Numerical simulation was used to match GSG and GSW corefloods and estimate multiphase-flow functions. A 2D conceptual simulation model using these functions was built for an anticline reservoir for gas and surfactant-solution injection. GSG flooding using wettability-altering surfactant exhibited high oil recovery at the field scale. IFT reduction, wettability alteration, and foam formation contributed to enhanced oil recovery (EOR).

Currently many lean gas EOR pilot projects are implemented in Eagle Ford shale. The major component of lean gas is methane. From the field feedback, there is always large discrepancy between production forecast (or reservoir simulation) and the field results. The natural fracture system is complex and the communication between natural fracture, matrix and hydraulic fractures is even more complicated. Comparing connecting natural fracture between wells with short and low fracture conductivity, the well interference and the resulted optimal well spacing significantly change. In this study, according to field feedback, some connecting natural fractures with high fracture conductivity are mapped between wells to better represent the field geology and production status. A composition reservoir simulation model is built for Eagle Ford shale. Typical production curve of Eagle Ford shale is matched for the first three years of primary production, lean gas Huff and Puff (HNP) process is simulated for the next three years for the parent wells and child wells. As the main composition of lean gas is methane, different methane adsorption effects are quantified between wells to investigate its influence on production. For lean gas Huff and Puff process, normally the Minimum Miscibility Pressure (MMP) is above 4000 psi. During lean gas cycling process, methane is adsorbed and desorbed, and the effective methane amount used to enhance miscibility between gas and oil phases is reduced, thus the reservoir pressure is not elevated to as high as no gas adsorption case. The methane adsorption effect significantly affects the oil and gas production. Relative permeability hysteresis and capillary pressure hysteresis (gas trapping effect) are the first time systematically studied to quantify the gas EOR performance in pad level production of unconventional reservoirs. Considering gas trapping effects, the cumulative gas injection amount and production amount is much better matched to the field pilot results. The oil incremental benefit of gas Huff and puff process considering gas trapping effect is quantified. To our best knowledge, this is the first time that both methane adsorption and gas trapping effects are studied for pad level Huff and Puff process with the realistic connecting natural fractures between wells. Better matching of the production data with pilot results confirms the successful application of these two mechanisms. Considering the realistic complex natural fracture effects also greatly contributes to the correct production forecast and efficient design of gas EOR project for unconventional reservoirs such as Eagle Ford shale and other major basins.

US unconventional resource production has developed tremendously in the past decade. Currently, the unconventional operators are trying many strategies such as refracturing, infill drillings and well spacing optimization to improve recovery factor of primary production. They are also employing big data and machine learning to explore the existed production data and geology information to screen the sweet spot from geology point of view. However, current recovery factor of most unconventional reservoirs is still very low (4~10%). A quick production rate decline pushes US operator to pursue gas EOR for unconventional reservoirs, lifting the ultimate recovery factor to another higher level. The goal of this work is to improve oil recovery by implementing gas Huff and Puff process and optimizing injection pattern for one of the US major tight oil reservoirs - Eagle Ford basin. Gas diffusion is regarded as critical for gas Huff and Puff process of tight oil reservoirs. Utilizing the dual permeability model, gas diffusion effect is systematically analyzed and compared with the widely used single porosity model to justify its importance. Transport in natural fractures is proved to be dominated recovery mechanism using dual permeability model. Uncertainty studies about reservoir heterogeneity and nature fracture permeability are performed to understand their influences on well productivity and gas EOR effectiveness. Moreover, three alternative gas injectant compositions including rich gas, lean gas and nitrogen are investigated in gas Huff and Puff processes for Eagle Ford tight oil fractured reservoir. The brief economic evaluation of Huff and Puff project is conducted for black oil region of the Eagle Ford basin.

Gas aided gravity drainage is a common oil recovery technique in anticline-shaped oil reservoirs. If the permeability is low and the reservoir is oil-wet, the remaining oil saturation can be quite high. The goal of this work is to mobilize a part of this oil by surfactant injection. Different coreflood strategies including Gas-Surfactant-Gas (GSG), Gas-Water-Surfactant-Water (GWSW), Gas-Surfactant-Water (GSW), and Gas-Surfactant-Water-Gas (GSWG) floods were investigated. GSG, GWSW and GSWG corefloods conducted in limestone cores recovered about 40-50% of the original oil in place (OOIP) due to the injection of surfactant. GSW corefloods conducted in a vuggy dolomite recovered less, about 20% OOIP incrementally. A 2D conceptual simulation model was built for an anticline reservoir for gas and surfactant solution injection. GSG flooding using wettability altering surfactant exhibited high oil recovery at the field-scale. IFT reduction, wettability alteration, and foam formation contributed to enhanced oil recovery.