A Laboratory Study of CO2 Interactions Within Shale and Tight Sand Cores - Duvernay, Montney and Wolfcamp Formations
- Murray Reynolds (Ferus Inc.) | Derek Britten (Ferus Inc.) | Xiaojun Cui (Trican Geological Solutions Ltd.) | Cory Twemlow (Trican Geological Solutions Ltd.) | Mike Cook (Trican Geological Solutions Ltd.)
- Document ID
- Society of Petroleum Engineers
- SPE Canada Unconventional Resources Conference, 13-14 March, Calgary, Alberta, Canada
- Publication Date
- Document Type
- Conference Paper
- 2018. Society of Petroleum Engineers
- 5.4 Improved and Enhanced Recovery, 5.4 Improved and Enhanced Recovery, 4 Facilities Design, Construction and Operation, 5.7.2 Recovery Factors, 4.1 Processing Systems and Design, 2.5.2 Fracturing Materials (Fluids, Proppant), 2 Well completion, 5.7 Reserves Evaluation, 3 Production and Well Operations, 5 Reservoir Desciption & Dynamics, 4.1.2 Separation and Treating, 1.6 Drilling Operations, 5.1.1 Exploration, Development, Structural Geology, 5.1 Reservoir Characterisation, 6.5.2 Water use, produced water discharge and disposal, 1.6.9 Coring, Fishing
- CO2 as a fracture fluid, CO2 - Unconventional core interactions, CO2 as an EOR agent, Permeability regain after CO2 flooding, CO2 sequestration
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The most commonly used technology for development of unconventional reservoirs is horizontal wells combined with large multi-stage hydraulic fracture treatments. However, even with these technological advancements, primary recovery factors are generally less than 10 percent of the hydrocarbon in place. Water is currently the primary fracturing fluid used in most commercial developments. There is growing interest in non-aqueous (e.g. CO2) fluid systems not only to reduce water usage, but to increase well productivity and recovery factors.
Use of carbon dioxide (CO2) as a fracturing fluid and an enhanced oil recovery (EOR) agent is also attractive from an environmental point-of-view. Organic rich shale reservoirs can be targets for carbon storage, due to their high CO2 adsorptive abilities and multiple mechanisms for gas storage. Therefore, use of CO2 can have both economic (increased recovery) and environmental (sequestration) benefits.
This laboratory study investigates the interactions of CO2 with various cores from three formations (Duvernay, Montney, and Wolfcamp). Multiple core plugs were prepared from each of the three reservoirs. The mineralogy of the samples was measured with x-ray diffraction (XRD), and total organic carbon (TOC) and thermal maturity were determined with a SRA (Source Rock Analyzer). Porosity was also measured under as-received conditions and cleaned and dried conditions with a helium pycnometer. For each sample, its initial baseline permeability to helium was tested under a full cycle of net confining pressures (1,500 psia → 4,500 psia → 1,500 psia) with pressure steps of 1,000 psia using the pressure pulse-decay method. Subsequently the sample was vacuumed for 12 hours, and was then soaked with CO2 for more than 48 hours. Afterwards, the permeability to CO2 was measured under another cycle of confining pressures. Finally, the sample was vacuumed again and the regain permeability to helium was measured.
Results indicate that the permeability to helium is generally recovered after CO2 soaking stages for tight-sand samples (e.g., Montney) and may be elevated for some samples enriched in organic matter and clay minerals (e.g., Wolfcamp). Overall the study shows favorable interaction between rock and organic material and CO2, which supports the use of CO2 as a fracturing or EOR fluid in these three reservoirs.
|File Size||2 MB||Number of Pages||18|
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