Drainage and Imbibition Relative Permeability Relationships for Supercritical CO2/Brine and H2S/Brine Systems in Intergranular Sandstone, Carbonate, Shale, and Anhydrite Rocks
- Brant Bennion (Hycal Energy Research Laboratories Ltd.) | Stefan Bachu (Alberta Energy and Utilities Board)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- June 2008
- Document Type
- Journal Paper
- 487 - 496
- 2008. Society of Petroleum Engineers
- 5.5.8 History Matching, 5.8.3 Coal Seam Gas, 6.5.7 Climate Change, 1.2.3 Rock properties, 5.4 Enhanced Recovery, 1.8 Formation Damage, 1.6.9 Coring, Fishing, 5.5.2 Core Analysis, 1.14 Casing and Cementing, 4.1.2 Separation and Treating, 5.1 Reservoir Characterisation, 4.3.4 Scale, 5.2.1 Phase Behavior and PVT Measurements, 5.3.2 Multiphase Flow, 5.4.2 Gas Injection Methods, 5.5 Reservoir Simulation, 4.1.5 Processing Equipment, 5.2 Reservoir Fluid Dynamics, 5.1.1 Exploration, Development, Structural Geology, 4.2.3 Materials and Corrosion, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 5.3.1 Flow in Porous Media
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Disposal of acid gas, made of carbon dioxide (CO2) and hydrogen sulfide (H2S), in deep underground formations is a means for reducing atmospheric emissions of toxic and greenhouse gases produced from sour-gas reservoirs that has been practiced for 18 years in North America and that is currently being considered in other regions, such as the Middle East and central Asia. Acid-gas-injection operations constitute a commercial-scale commercial analogue to CO2 injection in geological media as a climate-change mitigation measure. Deep saline aquifers provide a very large capacity for the sequestration of acid and greenhouse gases, being ubiquitous in all sedimentary basins around the world. Proper understanding of the relative-permeability-displacement character of such systems is essential in ascertaining gas injectivity and migration, and in assessing the suitability, containment, and safety of prospective injection sites.
Pure CO2 and H2S represent the compositional end-members of acid and greenhouse gases, thus, the interest in measuring their displacement properties. This paper presents the detailed experimental equipment and protocols, and the results of a series of relative permeability measurements conducted at full reservoir conditions using supercritical pure CO2 and H2S on samples of intercrystaline sandstone, carbonate, shale, and anhydrite rocks from the Wabamun and Zama areas in Alberta, Canada, where large CO2 sources and several acid-gas-injection operations exist. Results of the relative permeability measurements are presented for each fluid and rock type. The results provide a valuable dataset for the evaluation and simulation of acid gas disposal and CO2 sequestration projects.
Deep gas reservoirs in Rocky Mountain foreland basins in Canada and the United States contain H2S and CO2 that has to be removed in order to meet safety and market requirements. These gases are separated from the produced gas at gas plants usually using an amine-based process that results in sweet gas, which is sent to markets, and a concentrated stream of acid gas (a mixture of H2S and CO2 with other hydrocarbon gases present in small concentrations). Because incineration of the acid gas is costly, and desulphurizing the acid gas is uneconomic in a weak depressed sulphur market and sulphur stored on site constitutes a liability, an increasing number of upstream and midstream companies in North America are turning to acid-gas disposal by injection into deep depleted oil or gas reservoirs, or saline aquifers (Connock 2001). Provincial regulatory constraints in Canada that, since 1989, do not allow flaring of acid gas from gas plants with an output greater than 1 t/d, combined with economic conditions, led to an increase in the number of acid-gas injection operations in western Canada from one in 1990 to close to 50 today. Dry acid gas is injected in a dense-fluid (liquid or supercritical) state at depths that vary between approximately 1000 and 3400 m in both carbonate and sandstone formations whose porosity is generally less than 12% and permeability in the order of milliDarcies to tens of milliDarcies. In approximately 60% of these cases, the acid gas is injected into deep aquifers, whose salinity ranges from 20,000 ppm to 340,000 ppm. A detailed characterization of these operations is provided elsewhere (Bachu and Gunter 2005; Bachu and Haug 2005). Similarly, more than 20 acid-gas injection operations are currently active in the United States, most of them in Wyoming, Oklahoma, and Texas, with the largest operation in the world being operated by ExxonMobil at the LaBarge field in Wyoming. As sour reservoirs are being produced in the Arabian Gulf and central Asia, producers in Iran, U.A.E., and Kazakhstan are also turning to acid-gas disposal by deep injection, and it is likely that this practice will increasingly be used around the world. Additionally, geological sequestration in hydrocarbon reservoirs and deep saline aquifers of CO2 captured at large plants has been recently recognized as a possible climate-change mitigation measure with large potential for reducing atmospheric emissions of greenhouse gases this century (International Energy Agency 2004; Intergovernmental Panel on Climate Change 2005). Geological storage in deep saline aquifers of CO2 produced from gas reservoirs occurs already at Sleipner in the North Sea (operated by Statoil) (Torp and Gale, 2003) and at In Salah in Algeria (operated by BP) (Riddiford et al. 2003), and is planned at several other places around the world such as the Gorgon project on Barrow island in northwestern Australia (operated by Chevron).
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