Joel Sminchak

Determining carbon sequestration injection potential at a site-specific location within the Ohio River Valley region

Publisher Summary This chapter presents results from the initial field investigations from the site-characterization effort. Depending upon the geology and the reservoir characteristics, the ultimate objective for this project is to progress towards demonstration of CO2 injection in deep geological reservoirs in the region. Towards this objective, an effort was made to ensure that, if a decision is made to proceed to an injection phase, the current test well will be able to meet the relevant regulatory criteria. The results given in the chapter pertain to the assessment of the injectivity and the storage capacity. Containment evaluation is also a part of the assessment. The research presented here provides a protocol for similar characterization in deeper sedimentary basin elsewhere in the world, especially those where pre-existing information is sparse. While many of the techniques used are similar to those used in oil and gas exploration, it is noteworthy that the testing objectives are very different, with a greater emphasis on the evaluation of containment and injection potential, rather than on the presence and quantification of oil/gas reserves, and on ensuring that the drilling, testing, and well design comply with underground injection regulations. There is also a greater emphasis on collecting information that may be needed for allaying possible stakeholder concerns about the risks from carbon sequestration technologies.

Assessment of CO2 injection at the mountaineer power plant site using scalable numerical simulation

Publisher Summary Numerical simulations of carbon dioxide (CO 2 ) injection are conducted as a part of a comprehensive program to assess the potential for geologic sequestration in deep geologic reservoirs at the American Electric Powers (AEPs) Mountaineer Power Plant site in West Virginia. Initial assessments of the site geology indicated two potential injection reservoirs—the Rose Run and Lower Marysville formation. The Rose Run formation is simulated, considering the dolomite confining and interbedding units explicitly, using three geologic conceptual models for intrinsic permeability and porosity: homogeneous, core-sample-stochastic, and wireline stochastic. The Copper Ridge formation is simulated using stochastically generated geology from the wireline and borehole field testing data. The confining layers above and below the Copper Ridge formation are not explicit modeled and are assumed impermeable. Subsequent borehole field testing has identified an additional potential injection reservoir in the Copper Ridge formation. This chapter presents a pilot study to predict CO 2 injection rates over a 20-year injection period and CO 2 distributions over a 100-year injection and redistribution period for two potential brine reservoir—the Rose Run and Copper Ridge formations. Simulations of CO 2 injection and redistribution were conducted for both the single-vertical and double-horizontal injection wells. Single-vertical well simulation scenarios assumed radial symmetry using a two-dimensional radial domain centered on the vertical injection well, extending radially to 8 km. Double-horizontal injection wells assumed planar symmetry, normal to the horizontal well and centered on the vertical well using three-dimensional domains that extended from the vertical well to 8 km.

Geologic Storage of CO 2 from Refining and Chemical Facilities in the Midwestern United States

Publisher Summary This chapter describes the process of geologic storage of CO2 from refineries and chemical plants in the midwestem United States. Three locations in the midwestem United States were evaluated for saline reservoir sequestration of CO2 transported from refineries and chemical plants along existing pipeline rights of way. Based on formation volume calculations, the potential storage capacity in a single formation, the Mt. Simon Sandstone, is in the range of several billion tons. Compositional reservoir simulations were completed to predict the formation pressures, CO2 spreading, and dissolution following injection. Injectivity at all sites was sufficient for more than 1 mt/year/well of CO2 without exceeding the fracture pressure limits, and no leakage of CO2 into shallower horizons was predicted. A horizontal injection well scenario showed a smaller increase in reservoir pressure than vertical wells. The geochemical evaluation included a summary of the brine chemistry and mineralogy of the reservoir and caprock formations. Equilibrium geochemical simulations for several scenarios did not indicate any adverse reactions as a result of CO2 injection. A preliminary economic and engineering assessment of several injection scenarios showed that the cost of CO2 dehydration, compression, transport, and injection is nearly

Issues Related to Seismic Activity Induced by the Injection of CO2 in Deep Saline Aquifers

20 per ton, excluding any capture costs. The largest capital cost is in compression and pipeline systems, and the largest operational cost is that of compression. System costs may be reduced by optimizing the location of storage reservoirs closer to the emission sources or through development of a regional shared transport network and storage site.