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We report here a simplification of the capillary-rise/vanishing interfacial tension (IFT) method to measure minimum miscibility pressure (MMP) based on only requiring knowledge of when the interfacial tension approaches zero. Simply measuring the height of the crude oil in a capillary at several pressures from ambient to near the MMP pressure and extrapolating the oil height versus pressure plot to zero oil height yields the MMP without the need of the additional instrumentation and labor required to perform actual IFT measurements. A total of 2–4 MMP values can be determined per day with only one experimental apparatus, and the method greatly reduces the initial cost and complexity of the required instrumentation. The use of three capillaries having different inner diameters allows for triplicate determinations of MMP from each experiment. Because the actual MMP pressure need not be reached during the experiment, MMP values that exceed the pressure ratings of the equipment can be reasonably estimated (e.g., MMPs using pure nitrogen). The method was used to determine the MMP pressure for crude oil samples from a conventional Muddy Formation reservoir in the Powder River Basin [American Petroleum Institute (API) gravity of 35.8°] and an unconventional Bakken Formation reservoir in the Williston Basin (API gravity of 38.7°). The method is reproducible [typically <4% relative standard deviation (RSD)], and the method gave good agreement for a “live” Bakken oil with the results from a slim tube test of a commercial laboratory. Approximately 80 MMP values were measured using pure CO2, methane, and ethane as well as 0–100% mole ratios of methane/CO2 and methane/ethane. For both oil samples, ethane MMPs were ca. one-half those with CO2, while methane MMPs were ca. double or triple those with CO2. MMPs with mixed methane/CO2 showed a linear increase with mole percent methane for both crude oils, while both oils showed an exponential increase in MMP with mole percent methane in ethane, with a little increase in MMP until ca. 20 mol % methane in ethane.

Minimum miscibility pressures (MMPs) were measured at reservoir temperatures using a capillary-rise vanishing interfacial tension (VIT) technique for four crude oils collected from different formations in the deep/hot Bakken Petroleum System and the shallow/cool Cut Bank field. Potential injection fluids tested were pure CO2, methane, ethane, propane, and hydrocarbon gas mixtures typical of the rich gas produced from tight shale formations like the Bakken Petroleum System (ca. 7/2/1 mol ratios of methane/ethane/propane). Depending on the oil and test temperature, MMPs were achieved with the fluids in the gas, liquid, or supercritical states. Regardless of the physical state of the test fluids at MMP, propane achieved MMP at the lowest pressure with all four crude oils, followed by ethane, then CO2 and produced gas, and finally methane requiring the highest pressures. For the Bakken (110 °C) and Three Forks crudes (127 °C), MMPs dropped from 29 to 31 MPa with methane from 16.2 to 18.7 MPa with CO2 or produced gas, and further lowered from 9.2 to 10 MPa with ethane, and from 3.8 to 4.3 MPa with propane. Changes in the MMPs with the different fluids were even more dramatic for the Madison and Cut Bank crude oils (both at 28 °C) with methane MMPs about 28–29 MPa, produced gas at 10–10.6 MPa, CO2 at 8.3–8.7 MPa, ethane at 4.2–4.5 MPa, and propane only requiring 1.3–1.4 MPa to achieve MMP. Enriching produced gas by adding either ethane or propane showed approximately linear decreases in the MMPs with the Bakken crude oil. For example, increasing propane in produced gas from 6.7 to 25 mol % reduced the Bakken crude oil’s MMP from 18 to 12.7 MPa, while increasing ethane from 13.5 to 68 mol % reduced the MMP from 18.6 to 11.4 MPa. The results of this experimental study show that injecting produced rich gas may be as effective as injecting CO2 for enhancing oil recovery and that enriching produced gas with ethane or propane may be superior to CO2 for EOR in both shallow/cool and deep/hot reservoirs.

Summary Compared with a conventional reservoir, the ultralow permeability in the Bakken Formation makes it very challenging to perform normal waterflooding or gasflooding operations. “Permeability-jail” effects cause low injectivity and prevent injected fluids from sweeping oil out of the matrix efficiently. Two distinguishable flow regimes have been identified in fractured, hydrocarbon-rich shale formations: viscous flow in high-permeability fracture networks and diffusion-dominated flow in the low-permeability matrix with high oil saturation. Improving hydrocarbon transport (and technically recoverable resources) in unconventional reservoirs relies on our ability to enhance diffusion-dominated flow from the oil-saturated matrix to the natural- or induced-fracture network, which is the focus of this study. To unlock the unproduced Bakken and Three Forks oil, high-pressure carbon dioxide (CO2) may be used to enhance the diffusion-dominated flow in the matrix and keep the viscous flow in the fractures under reservoir temperature and pressure conditions (e.g., 230°F and 5,000 psi). Core samples were collected from two Bakken wells, including all oil-bearing intervals: Upper Bakken (UB), Middle Bakken (MB), and Lower Bakken (LB) Members and the Three Forks (TF) Formation. Detailed core analyses were performed to measure petrophysical properties and characterize these units. Ten samples were selected for pore-size-distribution measurement and 21 samples (11-mm-diameter rods) were used for 24-hour CO2 exposures and hydrocarbon-recovery experiments. These experiments were conducted as CO2 “bathing” at reservoir conditions (rather than “flow through” tests) and were aimed at increasing our understanding of the microstructure and diffusion-dominated-flow ability within these tight geologic formations. CO2-exposure and hydrocarbon-extraction experimental results clearly showed the improvement of diffusion-dominated flow in all the Bakken members. The UB and LB samples, characterized by generally high total-organic-carbon (TOC) content (10–15 wt%) and small pore size (approximately 3–7 nm), yielded approximately 60% of the present mature hydrocarbon at the end of the 24-hour exposure. The MB and TF samples, characterized by lower TOC content (&lt;0.5 wt.%) and moderate pore size (approximately 8–80 nm), provided more-favorable flow conditions for CO2 and hydrocarbons, yielding approximately 90% of the mature-hydrocarbon content. Because all experiments were conducted at reservoir conditions, the results demonstrate that diffusion plays a significant role in the mobilization of oil in tight reservoirs. CO2 greatly enhances the diffusion process to improve hydrocarbon transport in the tight matrix. This observation is especially useful for densely fractured shale-oil formations (high surface-area/volume ratio) where CO2 has greater areal contact with the reservoir, enabling CO2 diffusion into the matrix and hydrocarbon diffusion out of the matrix to occur more efficiently (increasing recoverable reserves), and where the fracture networks assist in alleviating potential injectivity challenges.

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