Laboratory Investigation Targets EOR Techniques for Organic-Rich Shales
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Commercial production from light oil, organic-rich shales in the Permian Basin has largely come from a solution-gas-drive recovery mechanism as a result of horizontal drilling and multistage hydraulic fracturing. These onshore, capital-intensive developments feature steep production declines and low expected ultimate recoveries. This paper involved laboratory experiments introducing miscible gases into core samples to investigate enhanced oil recovery (EOR) mechanisms for Permian Basin shales to provide information to design field tests for a huff ’n’ puff (HNP) recovery process.
The average recovery factor in the unconventional resources is typically less than 10% with very steep decline rates, indicating enormous potential for EOR. In recent years, research efforts and field pilots of unconventional EOR have targeted the Bakken and Eagle Ford shales. Most focused on miscible-gas (either CO2 or produced gas) injection, while others investigated water-based chemical injection. This paper provides EOR fluid and core analyses in Permian Basin organic-rich shale, an unconventional hydrocarbon growth play with different geological, rock, and fluid properties from those of the Bakken and Eagle Ford plays. The experimental results from this paper were used to calibrate the operator’s unconventional EOR reservoir simulation and field pilot design.
Fluid properties such as equation-of-state (EOS) and minimum miscibility pressure (MMP) are extremely important because they are the fundamental designing parameters for any gas EOR project. In this study, oil and gas samples were collected in the well from perforations inside the Wolfcamp formation of the Permian organic-rich shale. A gas/oil ratio (GOR) of 1230 scf/bbl was chosen to recombine the separator oil and gas on the basis of observed solution GOR values before any increase caused by the flowing bottomhole pressure falling below the bubblepoint pressure.
The pressure/volume/temperature (PVT) laboratory-testing program consisted of a constant-composition-expansion (CCE) test and a series of swelling tests with CO2. Using the recombined reservoir fluid (with a GOR of 1230 scf/bbl), a CCE test was performed at the reservoir temperature of 162°F to measure the bubblepoint pressure, single-phase oil density, and compressibility. The swelling test results were performed to tune an EOS to be used to calculate oil properties with increasing CO2 concentration during a CO2 flood.
An EOS model was generated to match the CCE data, viscosity data, and CO2 swelling-test data. To use this EOS for CO2 reservoir simulation, the reported system components were grouped, but the CO2 component was left ungrouped. Otherwise, it would be grouped with component C2. The minor component N2 was grouped with C1. All C4s and C5 were grouped together, as were the C6s. The C7+ components were divided into three pseudocomponents.
Binary interaction coefficients between C1 and the heavy pseudocomponents were tuned to match the bubblepoint pressure. To match the oil density, volume shift parameters for the heavy pseudocomponents were adjusted. Oil viscosity was calculated using the Lohrenz-Bray-Clark model. Viscosity matching was achieved by adjusting the critical properties of only the heavy pseudocomponents. In comparing the respective laboratory-measured relative volume, oil density, and viscosity data with the EOS-calculated values, it is noted that the latter match the laboratory data very well.
The match for the swelling-test saturation pressure as a function of CO2 concentration added is reasonable, except for the last point, the 60 mol% CO2/oil mixture. The oil density, swelling factor, and viscosity data all match well.
Oil Miscibility Experiments
In addition to the routine PVT tests, MMP was estimated with C1, produced separator gas, and CO2 using a rising-bubble apparatus (RBA). The produced gas composition was taken from gas chromatographic analysis with 67 mol% C1, 14 mol% C2, 15 mol% C3+, and 4 mol% N2. RBA, a reliable, fast, and simple alternative to conventional slimtube experiments, consists of a flat glass tube filled with reservoir oil at the desired pressure and temperature. The test procedure involves introducing injection gas bubbles at the bottom of the tube and visually observing the gas bubble’s shape and behavior as it rises to the top. At or above MMP, the gas bubble should disappear before reaching the top.
Fig. 1 shows the C1 bubble and the CO2 bubble at different pressures. The methane bubble retains its spherical shape until it reaches the top, showing that it is not exhibiting first-contact miscibility. However, the bubble size almost reduces to zero when it reaches the top, suggesting that it is close to methane’s MMP at 3,850 psi. The CO2 bubble cannot hold its shape immediately after contacting the oil at 3,600 psi, indicating that first-contact miscibility was achieved. The bubblepoint pressure of this oil is approximately 3,500 psi; no RBA tests were run at pressures lower than 3,600 psi.
Fig. 1—Rising bubbles of methane (left) and CO2 (right) at different pressures.
After the PVT and RBA experiments, core-extraction experiments were conducted to test the HNP process in the laboratory to estimate EOR performance. The core-plug sample from the Wolfcamp formation exhibited an average porosity of 7%. The oil saturation was also measured using high-frequency nuclear magnetic resonance (NMR).
The two selected core plug samples (1‑in. diameter×2-in. length) were encapsulated with Berea sandstone end plugs, heat-shrink tubing, and ceramic beads before loading into the core holder for testing. The ceramic beads were used to increase the surface area for gas cycling. The Berea sandstone end plugs were used to create a permeable surface for hydrocarbon collection.
Overburden and CO2 pore pressures were controlled using syringe pumps. A heating jacket was used to keep the core holder at a stable elevated temperature (160°F). The confining pressure was raised to 5,100 psi, and the system temperature was elevated to reservoir temperature. Once stability was reached, the injection gas was introduced and the pressure increased to the designed operating pressure. After 4 days of soaking, the system was depressurized in steps using the metering value to a system pressure of 500 psi. A flushing step was introduced to further remove the hydrocarbon located in the Berea sandstone end plugs. A weighed, clean, dry collection vial with a sealed septum was attached to the metering valve outlet and immersed in a cold trap filled with an acetone/dry-ice mixture. At the end of the depressurization cycle, the vial was removed and weighed, and the weight of the oil collected was recorded. A small aliquot was then injected into a gas chromatograph programmed to perform a simulated distillation. From the resultant chromatogram, the density of the oil fraction was calculated, allowing the volume of oil recovered to be calculated given its measured weight. After the first cycle, multiple cycles were repeated until no further fluid could be extracted from the process.
Hydrocarbon fluids were recovered during multiple HNP experiments. As expected, the highest amount of oil recovered (0.25 g) was achieved in the first cycle. The HNP process can also recover significant additional oil with additional cycles for the Permian organic-rich shales. Approximately 0.035 g of oil was recovered even in Cycle 6. The fluid collected in Cycle 7 was too small for further analysis. The multicycle incremental recovery—even at the small core-plug scale—suggests the significant potential for multiple HNP EOR cycles for future unconventional EOR project design.
The effluent hydrocarbon compositions of the first four cycles were analyzed. It appears that more light ends of the hydrocarbon were recovered in the first two cycles because it is easier for light ends to vaporize, while the heavier ends were recovered in the later cycle.
Some EOR lab studies in the literature used a computerized-tomography (CT) scanner and analyzed the CT images to visualize how CO2 changed the oil saturation in the core. This study applied a different noninvasive technology: NMR saturation measurement. Before contacting CO2, the core plugs were scanned using a 20-MHz high-frequency NMR spectrometer. The purpose of the NMR is to measure fluid saturation along the as-received core samples to determine their EOR potential. The 20-MHz NMR was used instead of the low-frequency 1- to 2-MHz NMR because of its ability to capture fast-relaxing NMR components. After seven cycles, the core plug was tested again using the same NMR measurement procedure. Oil saturation was significantly reduced after CO2 HNP, while the water saturation remained almost the same. This is consistent with the effluent analyses, which showed that almost all the effluent liquids were hydrocarbons.
- A reasonable EOS was generated for Wolfcamp organic shale in the Permian Basin, and it was tuned to match gas and CO2 swelling-test data.
- RBA was used to estimate the MMP of three different proposed injection gases for Wolfcamp. CO2 was found to be the best solvent for the Wolfcamp oil.
- HNP core extraction shows that significant oil was recovered by CO2 at the designed pressure.
- Incremental oil was produced in multiple CO2 HNP cycles in Wolfcamp shale, even at the core-plug scale.
- Effluent hydrocarbon composition changes with multiple cycles. More light components are recovered in the first two cycles.
- High-frequency NMR can be used as a noninvasive saturation-measurement tool. This technique confirmed the oil-extraction efficiency in the multicycle CO2 HNP process in Wolfcamp cores.
Laboratory Investigation Targets EOR Techniques for Organic-Rich Shales
01 July 2019
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