Shale swelling during drilling is attributed to osmotic pressure, where low-salinity water enters the shale pores to cause swelling. Low-salinity water injected into high-salinity Bakken formation could similarly enter the matrix pores to displace oil by counter-current flow observed in core experiments. As a result, we believe, low-salinity water can potentially enhance oil recovery from oil-wet Bakken formation.In this paper, we report experimental and numerical modeling studies we conducted to evaluate the potential of lowsalinity waterflooding in Bakken. For laboratory experiments, we used horizontal core plugs drilled parallel to the bedding plane.The mathematical included osmotic pressure, gravity and capillary effects. In the mathematical model, the osmotic pressure mass transfer equations were calibrated by matching time-dependent salinities in a published laboratory osmotic pressure experiment. We also modeled oil recovery for a Bakken core using our osmotic pressure mass transport model. The results indicate that osmotic pressure promotes counter-current flow of oil from both the water-wet and oil-wet segments of the core.
Summary Production of tight oil from shale reservoirs in North America reduces oil imports and has better economics than natural gas. Currently, there is a strong interest in oil production from Bakken, Eagle Ford, Niobrara, and other tight formations. However, oil-recovery fraction for Bakken remains low, which is approximately 4–6% of the oil in place. Even with this low oil-recovery fraction, a recent United States Geological Survey study stated that the Bakken and Three Forks recoverable reserves are estimated to be 7.4 billion bbl; thus, a large volume of oil will remain unrecovered, which was the motivation to investigate the feasibility of enhanced oil recovery (EOR) in liquid-rich shale reservoirs such as Bakken. In this paper, we will present both laboratory and numerical modeling of EOR in Bakken cores by use of carbon dioxide (CO2), methane/ethane-solvent mixture (C1/C2), and nitrogen (N2). The laboratory experiments were conducted at the Energy and Environmental Research Center (EERC). The experiments recovered 90+% oil from several Middle Bakken cores and nearly 40% from Lower Bakken cores. To decipher the oil-recovery mechanisms in the experiments, a numerical compositional model was constructed to match laboratory-oil-recovery results. We concluded that solvent injection mobilizes matrix oil by miscible mixing and solvent extraction in a narrow region near the fracture/matrix interface, thus promoting countercurrent flow of oil from the matrix instead of oil displacement through the matrix. Specifically, compositional-modeling results indicate that the main oil-recovery mechanism is miscible oil extraction at the matrix/fracture interface region. However, the controlling factors include repressurization, oil swelling, viscosity and interfacial-tension (IFT) reduction, diffusion/advection mass transfer, and wettability alteration. We scaled up laboratory results to field applications by means of a compositional numerical model. For field applications, we resorted to the huff ’n’ puff protocol to assess the EOR potential for a North Dakota Middle Bakken well. We concluded that long soak times yield only a small amount of additional oil compared with short soak times, and reinjecting wet gas, composed of C1, C2, C3, and C4+, produces nearly as much oil as CO2 injection.
Production of tight oil from shale reservoirs in North America reduces oil imports and has better economics than natural gas. Consequently, there is a strong interest in oil production from Bakken, Eagle Ford, and Niobrara. However, oil recovery factor for Bakken remains low, which is about four to six percent of the oil in place. Even with this low oil recovery factor, Bakken recoverable reserves are estimated to be 7.4 billion barrels; thus, a large volume of oil will remain unrecovered. This low level of oil recovery was the motivation to investigate the feasibility of enhanced oil recovery (EOR) in liquid-rich shale reservoirs such as Bakken. In this paper, we will present both laboratory and numerical modeling of EOR in Bakken cores using CO2, C1-C2 mixture, and N2. The laboratory experiments were conducted at the Energy and Environmental Research Center (EERC). The experiments recovered 90+ percent oil from several Middle Bakken cores and nearly 40 percent from Lower Bakken cores. To decipher the oil recovery mechanisms in the experiments, a numerical compositional model was constructed to match laboratory oil recovery results. We concluded that solvent injection mobilizes matrix oil by miscible mixing and solvent extraction in a narrow region near the fracture-matrix interface, thus promoting counter-current flow of oil from the matrix instead of oil displacement through the matrix. Specifically, compositional modeling results indicate that the main oil recovery mechanism is miscible oil extraction at the matrix-fracture interface region. However, the controlling factors include re-pressurization, oil swelling, viscosity and interfacial tension reduction, diffusion-advection mass transfer, and wettability alternation. We scaled up laboratory results to field applications via a compositional numerical model. For field applications, we resorted to the huff-and-puff protocol to assess the EOR potential for a North Dakota Middle Bakken well. We concluded that long soak times yields only a small additional oil compared to short soak times, and re-injecting wet gas, composed of C1,C2, C3, and C4+, produces nearly as much oil as CO2 injection.
The discovery of significant reserves in the Middle Bakken of the Elm Coulee Field in 2000 changed the development of Bakken Formation in the Williston Basin. In 2006 the Elm Coulee success led to the exploration of other fields in the Williston Basin, such as Parshall and Sanish fields in North Dakota. Thousands of Middle Bakken wells have been drilled and produced in the primary production mode, yet there is likely significant potential for enhanced oil recovery, which prompted this multi-facetted research study. First, the physical properties of the reservoir brine, oil, and gas of fluid samples from different Middle Bakken geographic locations are presented to emphasize significant physical property differences across North Dakota. This information is essential to understand the impact of fluid properties on primary production and potential for oil recovery at different locations. Second, we identified reservoir connectivity by combining petrographic analysis, scanning electron microscopy, and permeability measurements. The permeability measurements included core-based steady-state permeability and unsteady-state water-oil relative permeability. The selected cores were characterized using X-ray diffraction mineralogy, thin section petrology, and scanning electron microscopy (SEM) to correlate flow capacity to the petrophysical properties. The conclusion is that interconnected microfractures make current production possible in successful wells. Finally, the high salinity formation water compared to the low salinity of fracturing and IOR fluids was investigated by performing spontaneous imbibition using both low and high salinity brines. It was concluded that in the oil-wet environment of the Bakken, the low salinity injection fluids can enter part of the reservoir because of osmotic pressure while high salinity makes the clay surface extremely hydrophobic and causes local oil-wetness.
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