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Collaborating Authors
Results
Use of In-Situ CO2 Generation in Liquid-Rich Shale
Ogbonnaya, Onyekachi (University of Oklahoma, Norman, Oklahoma, USA) | Wang, Shuoshi (Southwest Petroleum University, Chengdu, China) | Shiau, Benjamin (University of Oklahoma, Norman, Oklahoma, USA) | Harwell, Jeffrey (University of Oklahoma, Norman, Oklahoma, USA)
Abstract Modified in situ CO2 generation was explored as an improved tool to deliver CO2 indirectly to the target liquid rich shale formations. Once injected, the special CO2- generating compound, urea, decomposes deep in fractures at the elevated temperature conditions, and releases significant amounts of CO2. For field implementation, the minimum surface facility is required other than simple water injection equipment. Injection of urea solution may be easier and cheaper than most gas injection approaches. In this effort, in situ CO2 treatment and designs were carried out on a group of Woodford shale core samples. The oil saturated shale cores were soaked in different urea solutions kept in pressurized (1500 and 4000 psi) and heated extraction vessels at temperature of 250 °F. The adopted treatment step closely simulates the huff-and-puff technique. A series of experiments were run with various ingredients, including brine only, brine plus surfactant, brine plus urea and ternary mixture of brine/surfactant/urea. In addition, the extraction experiments were tested at below and above MMP conditions to decipher the principal recovery mechanism. Based on our preliminary observations, the sample cores did not lose their stability after an extended period of oil extraction with in situ CO2 treatment. The urea only case could recover up to 24% of the OOIP compared to about 6% for the brine only case and 21% for the surfactant only case. Also adding a pre-selected surfactant to the urea slug did not have any benefit. There was no significant difference in oil recovery when the test pressure was below or above MMP. The main recovery mechanisms were oil swelling, viscosity reduction, low interfacial tension and wettability alteration in this effort. Multiple researchers reported successful lab scale CO2 gas extraction EOR experiments for liquid rich shale like upper, middle and lower Bakken reservoir. The best scenario could recover 90% of the OOIP from the shale core samples. The evidences of this effort offer a strong proof of concept of in situ CO2 generation potential for liquid rich shale reservoirs.
- North America > United States > Oklahoma (1.00)
- Europe (0.93)
- 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)
- (26 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- (5 more...)
Abstract Mixing of an asphaltenic oil with light gases (e.g., CO2) and/or depressurizing such a crude oil can lead to phase separation in which a second liquid phase L2 -highly concentrated in asphaltene- is formed. Asphaltene may precipitate or deposit out of the second liquid phase. This causes formation damage, wettability alteration, and recovery reduction. While asphaltene phase behavior have been studied under static conditions (where equilibrium is imposed), the behavior of asphaltene under dynamic flow conditions is relatively unexplored. Here, we investigate the coupling of asphaltene phase behavior and flow in porous media. As such, two asphaltenic crudes are characterized using the PC-SAFT equation-of- state. The fluid models were then used to fit the experimental asphaltene deposition data under static conditions. Subsequently, asphaltene flow and deposition was studied during miscible gas flooding where four phases (water, oil L1, gas, and second liquid L2) are present. Our results show that (i) wettability alteration increases the mixing zone and decreases both the displacement and sweep efficiencies; (ii) asphaltene deposition, hence wettability alteration and formation damage are maximal near the producer.
- North America > United States > Oklahoma (0.28)
- North America > Canada > Alberta (0.28)
- Asia > Middle East > UAE (0.28)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
- North America > Canada > Saskatchewan > Williston Basin > Midale Field > Midale Formation (0.99)
- North America > Canada > Saskatchewan > Williston Basin > Midale Field > Charles Formation (0.99)
- North America > Canada > Saskatchewan > Williston Basin > Weyburn Field > Mission Canyon Formation (0.97)
- (3 more...)
Abstract Carbonate rocks are typically heterogeneous at many scales; hence foams have the potential to improve both oil displacement efficiency and sweep efficiency in carbonate rocks. However, foams have to overcome two adverse conditions in carbonates: oil-wettability and low permeability. This study evaluates several foam formulations that combine wettability alteration and foaming in low permeability oil-wet carbonate cores. Contact angle experiments were performed on oil-wet calcite plates to evaluate the wettability altering capabilities of the surfactant formulations. Static foam stability tests were conducted to evaluate their foaming performance in bulk. Finally, oil displacement experiments were performed using Texas Cream and Estaillades Limestone cores with crude oil. Two different injection strategies were studied in this work: alternating gas-surfactant-gas injection and co-injection of wettability alteration surfactant with gas at a constant foam quality. Cationic surfactants DTAB and BTC altered the wettability of the oil-wet calcite plate to water-wet, but were ineffective in forming foam. The addition of a non-ionic surfactant Tergitol NP helped in the foaming ability of these formulations. In-house developed Gemini cationic surfactant GC 580 was able to alter the wettability from oil-wet to water-wet and also formed strong bulk foam. Static foam tests showed increase in bulk foam stability with the addition of zwitterionic surfactants to GC 580. Oil displacement experiments in oil-wet carbonate cores revealed that tertiary oil-recovery with injection of a wettability-altering surfactant can recover a significant amount of oil (about 20–25% OOIP) over the secondary water flood and gas flood. The foam rheology in the presence of oil suggested propagation of only weak foam in oil-wet low permeability carbonate cores.
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (1.00)
- Geology > Mineral (1.00)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/7 > Snorre Field > Statfjord Group (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/7 > Snorre Field > Lunde Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/4 > Snorre Field > Statfjord Group (0.99)
- (9 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (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)
- (2 more...)