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Collaborating Authors
Rutledge, Jeffrey M.
Abstract Unconventional oil reservoirs such as the Eagle Ford have had tremendous success over the last decade, but challenges remain as flow rates drop quickly and recovery factors are low; thus, enhanced oil recovery methods are needed to increase recovery. Interest in cyclic gas injection has risen as a number of successful pilots have been reported; however, little information is available on recovery mechanisms for the process. This paper evaluates oil swelling caused by diffusion and advection processes for gas injection in unconventional reservoirs. To accurately evaluate gas penetration into the matrix, the surface area of the hydraulic fractures needs to be known, and in this work, three different methods are used to estimate the area: volumetrics, well flow rates and linear fluid flow equations. Fick's law is used to determine the gas penetration depth caused by diffusion, and the linear form of Darcy's law is used to find the amount from advection. Then, with the use of swelling test information from lab tests, we are able to approximate the amount of oil recovery expected from cyclic gas injection operations. During the gas injection phase, gas from the fractures can enter the matrix by both advection (Darcy driven flow) and diffusion. We estimate that over 200 million scf of gas can enter the matrix during a 100 day injection/soak period. Using typical reservoir and fluid parameters, it appears that 40% is due to diffusion and 60% is due to advection. Sensitivity analysis shows that these numbers vary considerable based on the parameters used. Analytical models also show that during a 100 day production timeframe, over 14,000 stock tank barrels (STB) of oil can be produced due to huff-n-puff gas injection. Both gas injection and oil recovery amounts are compared to recent Eagle Ford gas injection pilot data, and the model results are consistent with the field pilot data. By determining the relative importance of the different recovery mechanisms, this paper provides a better understanding of what is happening in unconventional reservoirs during cyclic gas injection. This will allow more efficient injection schemes to be designed in the future.
- North America > United States > Texas (0.68)
- Europe > United Kingdom > North Sea > Central North Sea (0.25)
- Geology > Petroleum Play Type > Unconventional Play (0.68)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.67)
- Geology > Rock Type > Sedimentary Rock (0.47)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (28 more...)
Abstract Pore diameters for shale reservoirs are on the order of few nanometers which become even smaller during production because of rock deformation. This dynamic interaction between pore fluid pressure and rock stress affects the phase behavior in unconventional reservoirs. In this paper, a new mathematical formulation of fully-coupled geomechanics and compositional dual-porosity model was used to determine the impact of rock deformation and confinement on the nanopore fluids as well as their effect on the production performance of Eagle Ford formation. The formulation presented was derived from our multiphase poroelasticity model which was an extension to the single-phase, single-porosity Biot's linear poroelasticity theory allowing to characterize the rock deformation and pore diameter reduction using the bulk modulus of the matrix-fracture system. Changes in reservoir pore pressure and rock deformation that cause the pore diameter to reduce increases the capillary pressure in the pores which affects the bubble-point pressure suppression and significant shift in the phase envelope, favoring longer period of single-phase production. It was observed that not taking rock deformation into account will lead to over estimation of production, whereas ignoring the effect of pore confinement would underestimate the production forecast. In an example field study based on Eagle Ford reservoir, an increase of around eight percent in cumulative oil production was achieved when the effect of rock deformation and confinement was included in the compositional model compared to the case where only the rock deformation was included. On the other hand, if only pore confinement effect was included in the simulation runs, four percent of increase was achieved.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.62)
- North America > United States > North Dakota > Williston Basin > Bakken Shale Formation > Middle Bakken Shale Formation (0.99)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.98)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.98)
- (16 more...)