We conducted a study at Stratton Field, a large Frio gas‐producing property in Kleberg and Nueces Counties in South Texas, to determine how to best integrate geophysics, geology, and reservoir engineering technologies to detect thin‐bed compartmented reservoirs in a fluvially deposited reservoir system. This study documents that narrow, meandering, channel‐fill reservoirs as thin as 10 ft (3 m) and as narrow as 200 ft (61 m) can be detected with 3-D seismic imaging at depths exceeding 6000 ft (1800 m) if the 3-D data are carefully calibrated using vertical seismic profile (VSP) control. Even though the 3-D seismic images show considerable stratigraphic detail in the interwell spaces and indicate where numerous thin‐bed compartment boundaries could exist, the seismic images cannot by themselves specify which stratigraphic features are the flow barriers that create the reservoir compartmentalization. However, when well production histories, reservoir pressure histories, and pressure interference tests are incorporated into the 3-D seismic interpretation, a compartmentalized model of the reservoir system can be constructed that allows improved development drilling and reservoir management to be implemented. This case history illustrates how realistic, thin‐bed, compartmented reservoir models result when geologists, engineers, and geophysicists work together to develop a unified model of a stratigraphically complex reservoir system.
The relative amounts of oil and gas produced in prolific plays like the Eagle Ford are affected by the oil bubble point. The oil and kerogen (organic matter) are found in the same rock and the oil may remain in contact with the kerogen. Bulk experiments and molecular simulations clearly show that kerogen preferentially absorbs hydrocarbons. The absorbed oil phase remains in multi‐component equilibrium with the expelled oil produced at the surface. Results from a model proposed to calculate the bubble points (at 400 K) of in situ oils (absorbed + free) in the presence of kerogen indicate suppression of about 4150–16,350 kPa from the original value of 28,025 kPa of produced Eagle Ford oil. These calculations depend on the type and level of maturity of kerogen. The prediction of accurate saturation pressures has key implications on volumes of recovery and rates of production from liquid rich shales. © 2017 American Institute of Chemical Engineers AIChE J, 63: 3083–3095, 2017
In liquid rich shale plays, the hydrocarbons may remain associated with the parent kerogen. During catagenesis of kerogen in the geologic history, the kerogen is converted to hydrocarbons. A fraction of the generated hydrocarbons is expelled from the residual kerogen matrix, while the rest is retained within the kerogen matrix. In liquid rich shale plays, the hydrocarbons retained within the kerogen plays a key role in estimated ultimate recovery (EUR). However, the vapor-liquid equilibrium between oil and gas in shales is affected by the presence of kerogen. The conventional compositional simulators ignore this kerogen-fluid interaction in calculation of pressure-volume-temperature (PVT) properties which leads to vastly different results.The swelling of kerogen in the presence of solvents has been experimentally studied in previous works. These experiments suggest that the hydrocarbons expelled from the kerogen structure remain in a multicomponent equilibrium with the kerogen matrix. Molecular Dynamics Simulations (MDS) techniques have been used in the current paper to confirm the swelling behavior of kerogen in presence of solvents. The retained hydrocarbons stay in the dissolved form within the kerogen matrix. Considering the cross-linked nature of kerogen, there have been studies of the equilibrium behavior between the kerogen matrix and the expelled hydrocarbons using an extended Flory-Rehner Regular Solution theory model. The effect of this equilibrium between the expelled fluids and the kerogen matrix on PVT properties has been studied in the current paper. The vapor liquid equilibrium between oil and gas in the expelled hydrocarbons has been solved together with the kerogen-expelled hydrocarbons equilibrium.The kerogen-fluid interaction in liquid rich shales affects important reservoir fluid properties such as saturation pressures, gas oil ratios (GOR) and formation volume factors leading to changes in produced GOR. A thermodynamic model has been proposed in the current study to calculate changes in above properties due to the kerogen-fluid interaction. The PVT properties calculated with the proposed model account for the kerogen-fluid interaction and will significantly change the predicted recoveries from liquid rich shale plays
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