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Collaborating Authors
Results
Enhanced Oil Recovery Experiments in Wolfcamp Outcrop Cores and Synthetic Cores to Assess Contribution of Pore-Scale Processes
Kamruzzaman, Asm (Colorado School of Mines) | Kazemi, Hossein (Colorado School of Mines) | Kneafsey, Timothy J (Lawrence Berkeley Laboratory) | Reagan, Matthew T (Lawrence Berkeley Laboratory)
Abstract This paper assesses the pore- and field-scale enhanced oil recovery (EOR) mechanisms by gas injection for low permeability shale reservoirs. We performed compression-decompression laboratory experiments in ultratight outcrop cores of the Permian Basin as well as in ceramic cores using n-dodecane for oil. The EOR assessment strategy involved determining the quantity of oil produced after injection of helium (He), nitrogen (N2), methane (CH4), and methane/carbon dioxide (CH4/CO2) gas mixtures into unfractured and fractured cores followed by depressurization. Using the oil recovery volumes from cores with different number of fractures, we quantified the effect of fractures on oil recoveryโboth for Wolfcamp outcrop cores and several ceramic cores. We observed that the amount of oil recovered was significantly affected by the pore-network complexity and pore-size distribution. We conducted laboratory EOR tests at pore pressure of 1500 psia and temperature of 160ยฐF using a unique coreflooding apparatus capable of measuring small volumes of the effluent oil less than 1 cm. The laboratory procedure consisted of (1) injecting pure n-dodecane (n-C12H26) into a vessel containing a core which had been moistened hygroscopically and vacuumed, and raising and maintaining pressure at 1500 psia for several days or weeks to saturate the core with n-dodecane; (2) dropping the vessel pressure and temperature to laboratory ambient conditions to determine how much oil had entered the core; (3) injecting gas into the n-dodecane saturated core at 1500 psia for several days or weeks; (4) shutting in the core flooding system for several days or weeks to allow gas in the fractures to interact with the matrix oil; (5) finally, producing the EOR oil by depressurization to room pressure and temperature. Thus, the gas injection EOR is a โhuff-and-puffโ process. The primary expansion-drive oil production with no dissolved gas from fractured Wolfcamp cores was 5% of the initial oil in place (IOIP) and 3.6% of IOIP in stacked synthetic cores. After injecting CH4/CO2 gas mixtures, the EOR oil recovery by expansion-drive in Wolfcamp core was 12% of IOIP and 8.2% of IOIP in stacked synthetic cores. It is to be noted that the volume of the produced oil from Wolfcamp cores was 0.27 cm while it was 6.98 cm in stacked synthetic cores. Thus, while synthetic cores do not necessarily represent shale reservoir cores under expansion drive and gas-injection EOR, these experiments provide a means to quantify the oil recovery mechanism of expansion-drive in shale reservoirs. The gas injection EOR oil recovery in Wolfcamp cores with no fractures yielded 7.1% of IOIP compared to the case of one fracture and two fractures which produced 11.9% and 17.6% of OIP, respectively. Furthermore, in the no-fracture, one-fracture, and two-fracture cores, more EOR oil was produced by increasing the CO2fraction in the injection gas mixture. This research provides a basis for interpreting core flooding oil recovery results under expansion drive and gas injection EORโboth in presence and absence of interconnected micro- and macro-fractures in the flow path. Finally, the CO2 injection results quantify the CCUS efficacy in regard to the amount of sequestered CO2 from pore trapping in the early reservoir life. For the long-term CO2 trapping, one needs to include the chemical interaction of CO2 with the formation brine and rock matrix.
- North America > United States > Texas (1.00)
- North America > United States > New Mexico (0.89)
- Overview (0.67)
- Research Report (0.46)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline (1.00)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- (31 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
Abstract Foam is a promising means to assist in the permanent, safe subsurface sequestration of CO2, whether in aquifers or as part of an enhanced-oil-recovery (EOR) process. Here we review the advantages demonstrated for foam that would assist CO2 sequestration, in particular sweep efficiency and residual trapping, and the challenges yet to be overcome. CO2 is trapped in porous geological layers by an impermeable overburden layer and residual trapping, dissolution into resident brine, and conversion to minerals in the pore space. Over-filling of geological traps and gravity segregation of injected CO2 can lead to excessive stress and cracking of the overburden. Maximizing storage while minimizing overburden stress in the near term depends on residual trapping in the swept zone. Therefore, we review the research and field-trial literature on CO2 foam sweep efficiency and capillary gas trapping in foam. We also review issues involved in surfactant selection for CO2 foam applications. Foam increases both sweep efficiency and residual gas saturation in the region swept. Both properties reduce gravity segregation of CO2. Among gases injected in EOR, CO2 has advantages of easier foam generation, better injectivity, and better prospects for long-distance foam propagation at low pressure gradient. In CO2 injection into aquifers, there is not the issue of destabilization of foam by contact with oil, as in EOR. In all reservoirs, surfactant-alternating-gas foam injection maximizes sweep efficiency while reducing injection pressure compared to direct foam injection. In heterogeneous formations, foam helps equalize injection over various layers. In addition, spontaneous foam generation at layer boundaries reduces gravity segregation of CO2. Challenges to foam-assisted CO2 sequestration include the following: 1) verifying the advantages indicated by laboratory research at the field scale 2) optimizing surfactant performance, while further reducing cost and adsorption if possible 3) long-term chemical stability of surfactant, and dilution of surfactant in the foam bank by flow of water. Residual gas must reside in place for decades, even if surfactant degrades or is diluted. 4) verifying whether foam can block upward flow of CO2 through overburden, either through pore pathways or microfractures. 5) optimizing injectivity and sweep efficiency in the field-design strategy. We review foam field trials for EOR and the state of the art from laboratory and modeling research on CO2 foam properties to present the prospects and challenges for foam-assisted CO2 sequestration.
- North America > United States > Texas (1.00)
- Europe (1.00)
- North America > United States > Oklahoma (0.68)
- Geology > Rock Type > Sedimentary Rock (1.00)
- Geology > Geological Subdiscipline > Geomechanics (0.66)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (43 more...)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Conformance improvement (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)