Real-Time Evaluation Sheds Light on CO2 Production and Sequestration in a Gas Field
- Adam Wilson (JPT Editorial Manager)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- July 2012
- Document Type
- Journal Paper
- 109 - 110
- 2012. International Petroleum Technology Conference
- 2 in the last 30 days
- 47 since 2007
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This article, written by Editorial Manager Adam Wilson, contains highlights of paper IPTC 14600, "Real-Time Evaluation of CO2 Production and Sequestration in a Gas Field," by M. Aschehoug, SPE, and C.S. Kabir, SPE, Hess, prepared for the 2011 International Petroleum Technology Conference, Bangkok, Thailand, rescheduled to 7-9 February 2012. The paper has not been peer reviewed.
Production of a substantial fraction of carbon dioxide (CO2) in any hydrocarbon-gas stream poses a significant challenge in terms of separation and sequestration. Both environmental concerns and economic incentives motivate operators to search for safe, cost-effective ways to dispose of CO2. A case study examines CO2 separation at surface and its disposal in a saline aquifer close to its source. The use of real-time data allowed a comprehensive assessment of in-place volumes for the source gas and the capacity of the aquifer. Injection of supercritical CO2 suggests that the terminal aquifer pressure has been reached by encountering less-than-expected storage volume and by a lowering of the fracture-pressure gradient.
The merits of sequestering greenhouse gas have been discussed widely in the literature. Some studies have probed the feasibility of separation of CO2 from a natural-gas stream to allow processing in a liquefied-natural-gas plant. Flow-simulation studies showed that the gas/water relative permeability hysterisis effect and trapping are plausible mechanisms for storage.
To reduce atmospheric emissions in a producing gas field, the authors of the case study probed the injection of supercritical CO2 with 99% purity into a saline aquifer with standard analytical tools. In this field, approximately 5% CO2 is produced to surface with the hydrocarbon gas. At surface, it is stripped out of the hydrocarbon stream in a CO2-removal unit. The unit delivers a stream containing 99% CO2, while the hydrocarbons are processed further. This high-purity CO2 is injected into the deep, water-bearing sandstone formation through one dedicated injector. The overlying impermeable formation provides a seal between the CO2-receiving and hydrocarbon-bearing units.
Geologic Setting. A deep, water-bearing sandstone formation receives the injected CO2, designated as Unit A in Fig. 1. The 360-ft-thick formation consists of interconnected channels of Jurassic age. Well D is a vertical openhole injector with perforations in three different intervals. The average permeability is estimated at 400 md in the upper intervals and approximately 2,000 md in the lowermost perforations. 4D time-lapse-seismic data corroborate that most of the fluid injection occurs in the lowest interval. Above Unit A lies Unit C, a 260-ft-thick sandstone formation containing hydrocarbon gas. The estimated average gas saturation is 85%. Between those two formations lies Unit B, a tight 260-ft-thick sandstone formation. Therefore, Unit B constitutes a vertical hydraulic barrier between Unit A and Unit C. While CO2 is injected into Unit C in the northern part of the field, gas is produced from Unit A in a separate fault block. The two blocks are separated by a fault, which is anticipated to be sealing; thus, one would not foresee lateral communication between the formations.
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