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.
This paper discusses the analysis of production data from hydraulically fractured horizontal wells in shale reservoirs. The stimulated volume around the well is simulated by a naturally fractured region. A semianalytical model incorporating the key features of reservoir heterogeneity and the details of hydraulic fracture and wellbore flow is used to present production-decline characteristics in terms of transient-productivity index. Production-decline analysis of fractured horizontal wells in shale-oil and shale-gas formations by transient-productivity index is explained and demonstrated by field applications.
As unconventional reservoir development progresses, tighter well spacing improves recovery at the risk of an increase in well-to-well hydraulic fracture interference. During stimulation, fractures dilate along preferential planes of weakness that extend into an existing offset well"s producing volume. This can result in water penetration and stress reorientation. The objective is to show how to analyze pressure and rate responses from fracture interference data to impact operations, adjust field development, and identify future upside potential. The methodology starts with identifying whether fracture interference during hydraulic stimulation is beneficial (positive frac interference) or detrimental (negative frac interference) to offset producers. The impact of hydraulic fracture interference is then quantified by performing multi-phase production data analysis. The system alteration is measured by calculating the changes in well productivity and estimating incremental loss or gained volume for the pre-existing producer due to a frac interference event. This information is utilized to build full field development scenarios by modifying the drilling and completion schedule and well spacing so that the most profitable strategy is obtained. We identify that the drivers of fracture interference consists of (1) areal variation of reservoir properties, (2) pressure depletion due to the initial generation of wells, and (3) distance between producer and infill wells. The first development scenario evaluates the impact of deferred or gained production due to a frac interference event for different geological areas. The following case high-grades acreage based on areal variation of reservoir properties by delaying the development of deferred or lost production areas due to a negative frac interference event. The last scenario captures the opportunity for a tighter well spacing in areas with positive frac interference event. Based on the learnings derived from each scenario, the most profitable development strategy is presented for a typical unconventional reservoir. Furthermore, a new re-stimulation selection criteria is proposed to capitalize on the benefits of fracture interference. Conclusions are drawn from analyzing multiple multi-stage horizontal wells from the South Texas Eagle Ford and North Dakota and Montana Bakken reservoirs. In this paper, our results extend beyond retrospective studies by quantifying reservoir changes using a multi-phase approach and utilizing these results to impact development. Prior studies limited the classification of fracture interference as negative consequences of development. However, our investigation indicates that with improved understanding, we relate the impact of these events to development scheduling, confirmation of well spacing, and high-grading acreage to mitigate risks and harness the benefits of fracture interference as a mechanism of passive re-stimulation.
The success of oil production in North Dakota Bakken should be credited to advanced completion and stimulation techniques. The abundance of data on well production, core analyses and flooding, geologic reservoir characterization, and pressure transient testing has enhanced reservoir evaluation. Understanding matrix and fracture contribution to daily oil production is the key to identifying reservoir drivers affecting the lifelong well productivity. In this paper, we will present an application of core flooding, mini-frac and pressure build-up tests, decline curve analysis and reservoir simulation history matching to achieve reliable long-term reservoir performance predictions. This approach could lead to developing an integrated workflow for determining the performance drivers in the greater Bakken. Information presented in this paper includes well performance data from several Bakken fields, displacement results on selected cores, mini-frac and pressure transient analyses, and history matching using decline curve analysis and numerical simulation. Specifically, the matrix permeability from core measurements is on the order of 10-4 md while the permeability from well testing is on the order of 10-2 md. The latter represents the combined contributions of micro-fractures and matrix permeability. Reservoir simulation also shows that a single-porosity system, using only the matrix permeability from the core analysis, is not sufficient for matching well production performance without having a secondary permeability and porosity (micro-fractures). The dual-porosity nature of the reservoir was confirmed by a long-term pressure build-up test.
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