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Chapter 5: Underground geological storage 219 Box 5.7 The Allison Unit CO2-ECBM Pilot. The Allison Unit CO2-ECBM Recovery Pilot Project, located in the northern New Mexico portion of the San Juan Basin, USA, is owned and operated by Burlington Resources. Production from the Allison field began in July 1989 and CO2 injection operations for ECBM recovery commenced in April 1995. Carbon dioxide injection was suspended in August 2001 to evaluate the results of the pilot. Since this pilot was undertaken purely for the purposes of ECBM production, no CO2 monitoring programme was implemented. The CO2 was sourced from the McElmo Dome in Colorado and delivered to the site through a (then) Shell (now Kinder- Morgan) CO2 pipeline. The Allison Unit has a CBM resource of 242 million m3 km–2. A total of 181 million m3 (6.4 Bcf) of natural CO2 was injected into the reservoir over six years, of which 45 million m3 (1.6 Bcf) is forecast to be ultimately produced back, resulting in a net storage volume of 277,000 tCO2. The pilot consists of 16 methane production wells, 4 CO2 injection wells and 1 pressure observation well. The injection operations were undertaken at constant surface injection pressures on the order of 10.4 MPa. The wells were completed in the Fruitland coal, which is capped by shale. The reservoir has a thickness of 13 m, is located at a depth of 950 m and had an original reservoir pressure of 11.5 MPa. In a study conducted under the Coal-Seq Project performed for the US Department of Energy (www.coal-seq.com), a detailed reservoir characterization and modelling of the pilot was developed with the COMET2 reservoir simulator and future field performance was forecast under various operating conditions. This study provides evidence of significant coal-permeability reduction with CO2 injection. This permeability reduction resulted in a two-fold reduction in injectivity. This effect compromised incremental methane recovery and project economics. Finding ways to overcome and/or prevent this effect is therefore an important topic for future research. The injection of CO2 at the Allison Unit has resulted in an increase in methane recovery from an estimated 77% of original gas in place to 95% of the original gas in place within the project area. The recovery of methane was in a proportion of approximately one volume of methane for every three volumes of CO2 injected (Reeves et al., 2004). An economic analysis of the pilot indicated a net present value of negative US$ 627,000, assuming a discount rate of 12% and an initial capital expenditure of US$ 2.6 million, but not including the beneficial impact of any tax credits for production from non-conventional reservoirs. This was based on a gas price of 2.09 US$ GJ-1 (2.20 US$/MMbtu) (at the time) and a CO2 price of 5.19 US$ t–1 (0.30 US$/Mcf). The results of the financial analysis will change, depending on the cost of oil and gas (the analysis indicated that the pilot would have yielded a positive net present value of US$2.6 million at today’s gas prices) and the cost of CO2. It was also estimated that if injectivity had been improved by a factor of four (but still using 2.09 US$ GJ-1 (2.20 US$/MMbtu)), the net present value would have increased to US$ 3.6 million. Increased injectivity and today’s gas prices combined would have yielded a net present value for the pilot of US$ 15 million or a profit of 34 US$/tCO2 retained in the reservoir (Reeves et al., 2003). of methane and CO2 (Reeves et al., 2004). If the coal is never mined or depressurized, it is likely CO2 with fractures through which CO2 will leak unless there is a suitable caprock. Nonetheless, basalt may have some potential for mineral trapping of CO2, because injected CO2 may react with silicates in the basalt to form carbonate minerals (McGrail et al., 2003). More research is needed, but in general, basalts appear unlikely to be suitable for CO2 storage. 5.3.5.2 Oil or gas rich shale Deposits of oil or gas shale or organic-rich shale, occur in many parts of the world. The trapping mechanism for oil shale is similar to that for coal beds, namely CO2 adsorption onto organic material. Carbon dioxide-enhanced shale-gas production (like ECBM) has the potential to reduce storage costs. The potential for storage of CO2 in oil or gas shale is currently unknown, but the large volumes of shale suggest that storage capacity may be significant. If site-selection criteria, such as minimum depth, are developed and applied to these shales, then volumes could be limited, but the very low permeability of these shales is likely to preclude injection of large volumes of CO2. will be stored for geological time, but, as with any geological storage option, disturbance of the formation could void any storage. The likely future fate of a coal seam is, therefore, a key determinant of its suitability for storage and in storage site selection and conflicts between mining and CO2 storage are possible, particularly for shallow coals. 5.3.5 Other geological media Other geological media and/or structures – including basalts, oil or gas shale, salt caverns and abandoned mines – may locally provide niche options for geological storage of CO2. Flows and layered intrusions of basalt occur globally, with large volumes present around the world (McGrail et al., 2003). Basalt commonly has low porosity, low permeability and low pore space continuity and any permeability is generally associated 5.3.5.1 BasaltsPDF Image | CARBON DIOXIDE CAPTURE AND STORAGE
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