Use of In-Situ CO2 Generation in Liquid-Rich Shale
- Onyekachi Ogbonnaya (University of Oklahoma, Norman, Oklahoma, USA) | Shuoshi Wang (Southwest Petroleum University, Chengdu, China) | Benjamin Shiau (University of Oklahoma, Norman, Oklahoma, USA) | Jeffrey Harwell (University of Oklahoma, Norman, Oklahoma, USA)
- Document ID
- Society of Petroleum Engineers
- SPE Improved Oil Recovery Conference, 31 August - 4 September, Tulsa, Oklahoma, USA
- Publication Date
- Document Type
- Conference Paper
- 2020. Society of Petroleum Engineers
- 5.3.2 Multiphase Flow, 5.8.4 Shale Oil, 2.5.2 Fracturing Materials (Fluids, Proppant), 4.1.2 Separation and Treating, 1.6 Drilling Operations, 5.4.2 Gas Injection Methods, 5.8 Unconventional and Complex Reservoirs, 5 Reservoir Desciption & Dynamics, 2 Well completion, 4.1 Processing Systems and Design, 1.6.9 Coring, Fishing, 2.4 Hydraulic Fracturing, 4 Facilities Design, Construction and Operation, 5.4 Improved and Enhanced Recovery, 5.4.10 Microbial Methods, 5.4 Improved and Enhanced Recovery, 5.8.2 Shale Gas
- Unconventional Reservoirs, CO2, Wettability Alteration, Shale, Enhanced Oil Recovery
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Modified 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.
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