Simulation Of CO2 Injection Research Articles

System-level modeling for economic evaluation of geological CO2 storage in gas reservoirs

One way to reduce the effects of anthropogenic greenhouse gases on climate is to inject carbon dioxide (CO2) from industrial sources into deep geological formations such as brine aquifers or depleted oil or gas reservoirs. Research is being conducted to improve understanding of factors affecting particular aspects of geological CO2 storage (such as storage performance, storage capacity, and health, safety and environmental (HSE) issues) as well as to lower the cost of CO2 capture and related processes. However, there has been less emphasis to date on system-level analyses of geological CO2 storage that consider geological, economic, and environmental issues by linking detailed process models to representations of engineering components and associated economic models. The objective of this study is to develop a system-level model for geological CO2 storage, including CO2 capture and separation, compression, pipeline transportation to the storage site, and CO2 injection. Within our system model we are incorporating detailed reservoir simulations of CO2 injection into a gas reservoir and related enhanced production of methane. Potential leakage and associated environmental impacts are also considered. The platform for the system-level model is GoldSim [GoldSim User’s Guide. GoldSim Technology Group; 2006, http://www.goldsim.com]. The application of the system model focuses on evaluating the feasibility of carbon sequestration with enhanced gas recovery (CSEGR) in the Rio Vista region of California. The reservoir simulations are performed using a special module of the TOUGH2 simulator, EOS7C, for multicomponent gas mixtures of methane and CO2. Using a system-level modeling approach, the economic benefits of enhanced gas recovery can be directly weighed against the costs and benefits of CO2 injection.

Top-down and bottom-up estimates of CO2 storage capacity in the United Kingdom sector of the southern North Sea basin

Calculations of the CO2 storage capacity in the Leman Sandstone Formation and the Bunter Sandstone Formation in the data-rich southern North Sea basin, using structure contour, porosity, and isopach maps and a simulation of CO2 injection, suggest that their CO2 storage capacities are approximately 3 and up to 15 Gt CO2, respectively. It is recognized that such data are not available for most sedimentary basins, and a simple top-down method of calculating CO2 storage capacity would be highly desirable from a policy maker's perspective, so that the storage capacity of a basin, region, or jurisdiction could readily be estimated. Therefore, the above estimates were used to calculate the amount of CO2 stored per unit area and the amount of CO2 stored per unit of pore volume in the Leman Sandstone and Bunter Sandstone formations. The results were compared to similar calculations, derived from published data, for the Utsira Sand, a CO2 storage reservoir in the northern North Sea. The mean CO2 stored per unit area of the formation is 140 kg m2, and the range is 42–260 kg m2. The mean CO2 stored per unit pore volume is 6.3 kg m3, and the range is 1.8–10.0 kg m3. Two important factors that vary widely between these three North Sea reservoir formations are the total pore volume in traps and the achievable CO2 saturation; neither can be determined without detailed data.

Assessment of a potential storage site for carbon dioxide: A case study, southeast Queensland, Australia

Australia's coal-fired power plants produce about 70% of the nation's total installed electricity generation capacity and emit about 190 million t of CO2/yr, of which about 44 million t come from central and southeast Queensland. A multidisciplinary study has identified the onshore Bowen Basin as having potential for geological storage of CO2. Storage potential has been documented within a 295-km2 (113-mi2) area on the eastern flank of the Wunger Ridge using a simplified regional three-dimensional model and is based on estimating injection rates of 1.2 million t CO2/yr for 25 yr. Paleogeographic interpretations of the Showgrounds Sandstone reservoir in the targeted injection area indicate a dominantly meandering-channel system that grades downdip into a deltaic system. Seismic interpretation indicates a relatively unfaulted seal and reservoir section. The depth to the reservoir extends to 2700 m (8858 ft). CO2 injection simulations indicate that at least one horizontal or two vertical wells would be required to inject at the proposed rate into homogeneous reservoirs with a thickness of approximately 5 m (16 ft) and permeability of 1 d. The existence of intrareservoir shale baffles necessitates additional wells to maintain the necessary injection rate; this is also true for medium-permeability reservoirs. The long-term storage of the injected CO2 involves either stratigraphic and residual gas trapping along a 10–15-km (6–9-mi) migration path and, ultimately, potentially, within updip depleted hydrocarbon fields or trapping in medium-permeability rocks. Trapping success will be a function of optimal reservoir characteristics and the distribution of seals and baffles. This optimization may target specific, as-yet to be determined, permeability ranges.

Depth, radiocarbon, and the effectiveness of direct CO2 injection as an ocean carbon sequestration strategy

If radiocarbon were a good predictor of the amount of time until a water parcel returns to the surface, it could be used to estimate the effectiveness of carbon sequestration by direct injection. We performed direct CO2 injection simulations in both one‐dimensional box‐diffusion and three‐dimensional ocean general circulation models. The 1‐D model results for ocean carbon retention accord with the 3‐D model results, especially in the Pacific basin and at shallower depths. In the 1‐D model, carbon retention in the ocean is directly related to both the injection depth and the Δ14C of carbon at the injection location. However, in the 3‐D model, depth, but not radiocarbon, provides a relatively good prediction of carbon retention. This suggests that the expected time for a water parcel to return to the surface is closely related to its depth and not in general to the time since last at the surface.

Laboratory Experiments and Reservoir Simulation Studies in Support of CO2 Injection Project in Mattoon Field, Illinois, USA

Abstract This paper describes the results of rock and fluid property measurements and of the reservoir simulations associated with the demonstration of CO2-assisted oil recovery in the Cypress Sandstone reservoirs at Mattoon Field, Illinois. This work provided technical support for the field project. Results from core flood tests indicate that oil recovery from immiscible displacement of reservoir crude oil with carbon dioxide will increase with displacement pressure. Miscible displacement of oil with CO2 from the Cypress Sandstone reservoirs at Mattoon field is not possible. As shown by the slim-tube experiments, the minimum miscibility pressure (MMP) of Mattoon oil is close to the formation parting pressure of the Cypress Sandstone at Mattoon field. Nevertheless, phase behaviour experiments show that dissolved CO2 significantly enhanced oil recovery through oil swelling and viscosity reduction at pressures below miscibility conditions. Numerical simulations of CO2 injection into various reservoirs within the Sandstone were performed. A straight CO2injection program and a water alternating gas (WAG) injection program were simulated and compared in both the A-sandstone of the Pinnell Unit and E-sandstone interval of the Sawyer Unit. In the Pinnell Unit, the simulated results show an inefficient displacement of reservoir oil by CO2 and that neither of the two methods will be economically feasible because of the poor interwell communication and limited areal extent of the producing interval. This result is supported by the low oil recovery from the field CO2 injectivity tests in the Pinnell Unit. On the contrary, simulated results show that a significant amount of additional oil can be produced from the Sawyer Unit. The wateralternating- gas (WAG) injection program yielded more oil than water injection alone. The simulated results also indicate strategically- placed new wells will enhance the recovery of additional oil. Introduction This work provided technical support for a CO2-assisted oil recovery demonstration project funded by a cost-shared agreement (Cooperative Agreement number DE-FC22-93BCI4955) between the United States Department of Energy and American Oil Recovery, Inc. (AOR). The Mattoon Field, which is the site of the project (Figure 1), was discovered in June 1940. Development included approximately 420 producers and 90 dry holes drilled on a 4.05 ha (10 acre) well spacing. The principal reservoirs are found in the Cypress, Rosiclare and Aux Vases Sandstones of the Mississippian System (Figure 2). Secondary recovery was initiated in 1952 utilizing Pennsylvanian brine as well as treated municipal sewage water(1). The target intervals for additional oil recovery with CO2 are the Chesterian Cypress Sandstone reservoirs in the Mattoon field. In general, Cypress Sandstone reservoirs are the most prolific in Illinois(2). Recent studies(3,4,5) show that Cypress reservoir sandstones consist of four to five stacked layers having varying reservoir quality and often separated by thin shaly sandstone or calcareous beds. Because of the variations in reservoir quality, some layers are not as efficiently swept as others during water flooding. Such layers will contain more bypassed mobile oil than others. Furthermore, Cypress Sandstone reservoirs typically have high immobile oil saturation.