Investigation of water displacement following large CO2 sequestration operations

The scale of CO2 injection into the subsurface required to address CO2 atmospheric concentrations is unprecedented. Multiple injection sites injecting into multiple formations will create a large excess pressure zone extending far beyond the limited volume where CO2 is present. In a closed system, additional mass is accommodated by the compressibility of system components, an increase in fluid pressure, and possibly an uplift of the land surface. In an open system, as assumed in this analysis, another coping mechanism involves fluid flux out of the boundaries of the system, in which case the fresh-water-bearing outcrop areas, corresponding to the up-dip sections of the down-dip formations into which CO2 is injected, could be impacted. A preliminary study using a MODFLOW groundwater model extending far down-dip shows that injecting a large amount of fluid does have an impact some distance away from the injection area but most likely only in localized areas. A major assumption of this preliminary work was that multiphase processes do not matter some distance away from the injection zones. In a second step, presented in this paper, to demonstrate that a simplified model can yield results as useful as those of a more sophisticated multiphase-flow compositional model, we model the same system using CMG-GEM software. Because the chosen software lacks the ability to deal easily with unconfined water flow, we compare fluxes through time, as given by MODFLOW and CMG-GEM models at the confined/unconfined interface.Bureau of Economic Geolog

Area of review: how large is large enough for carbon storage?

The Texas Gulf Coast is an attractive target for carbon storage. Stacked sand-shale layers provide large potential storage volumes and defense-in-depth leakage protection. However, multiple perforations resulting from intensive hydrocarbon exploration and production have weakened seal integrity in many favorable locations. If the ultimate goal of carbon storage is to isolate large volumes of CO2 for hundreds to thousands of years, plume migration will encounter inadequately completed wells miles away from the injection zone. Moreover, the detrimental impact of CO2 on cement could undermine the structural integrity of all contacted wells, although pressure effects subside quickly after injection. Even wells abandoned to current standards cannot be guaranteed leak-free in the long term. We describe spatial statistics extracted from the Texas RRC Well Bore database as applied to carbon storage. Although the Area of Review (AOR) has been traditionally defined by a fixed radius with the strong regulatory requirement that the injectate stays within the injection layer, buoyancy is a major characteristic of CO2 that introduces a third dimension into the Area of Review process. Using simple geological mapping to characterize structural traps, we determine the likely pathway and the contacted volume of a migrating plume. The latter can be as large as a fault compartment with dimensions of 20 km × 20 km. However, the contacted volume is ultimately a function of the total injected volume, and the specifics of each project should dictate the dimensions of the zone of endangering influence (ZEI). An option, viable for the Texas Gulf Coast, to reduce geologic uncertainty, to decrease the impact of wells, and to limit the amount of information to be collected, is to inject CO2 below the maximum penetration of most wells.Bureau of Economic Geolog

Convection-diffusion-reaction of CO2-enriched brine in porous media: A pore-scale study

Bureau of Economic Geolog

U.S. EPA Draft Rules on Geological Storage: Selected Stakeholder Feedback

Bureau of Economic Geolog

Identification of a representative dataset for long-term monitoring at the Weyburn CO2-injection enhanced oil recovery site, Saskatchewan, Canada

Bureau of Economic Geolog

Simulation and 4D seismic studies of pressure management and CO2 plume control by means of brine extraction and monitoring at the Devine Test Site, South Texas, USA

Bureau of Economic Geolog

Geochemical impact of O2 impurity in CO2 stream on carbonate carbon-storage reservoirs

Bureau of Economic Geolog

Across-fault pressure perturbation induced by CO2 injection

Geological carbon sequestration aims at long-term storage of carbon dioxide in deep geological formations. To minimize the risk of leakage, the integrity of the geological seal has to be characterized carefully. The focus of this study is to simulate CO2 injection and observe the interaction of the CO2 and pressure evolution with a modeled fault intersecting the injection interval. Such features may be fairly common at a variety of scales in many sequestration reservoir targets, but their hydrologic and mechanical response to rapid pressure changes induced by CO2 injections requires investigation. We present numerical simulations from a commercial simulator (GEM from CMG). Preliminary numerical studies will determine the dependence of the CO2 and pressure evolution along and across the fault as a function of geological parameters. Additionally, the study is designed to complement and understand the field data being collected from the DOE-funded SECARB Phase 3 of the Cranfield CO2 injection project in the fall of 2009. A 12-level 3-component microseismic array has been deployed in a well approximately 1200 feet from a continuous CO2 injection well. A reservoir-scale fault intersects the reservoir between the injection and observation well. Available field data will be integrated with the flow model and analyzed to estimate the hydrologic properties of the adjacent fault. Pressure evolution predictions from the flow simulation will be critical for understanding the temporal distributions of any observed microseismic events detected. This project was funded thought the National Energy Technology Laboratory Regional Carbon Sequestration Partnership Program as part of the Southeast Regional Carbon Sequestration PartnershipBureau of Economic Geolog

Certification framework: leakage risk assessment for CO2 injection at the Montezuma Hills site, Solano County, California.

WESTCARB and C6 Resources are partners in a CO2 injection project in the Montezuma Hills, 80 km (50 mi) northeast of San Francisco, CA. Through a phased process that involves drilling an appraisal well and injecting CO2 on a small-scale, along with thorough analysis of data and modeling of the system, the goal of the project is to assess the deep geologic formations in the area for Geologic Carbon Sequestration (GCS), and if favorable, inject CO2 currently emitted to the atmosphere from nearby refinery facilities at industrial scales on the order of 1 million tons of CO2 per year. The deep geology at the site is considered very favorable for GCS by virtue of the numerous sandstone formations which are potentially capable of storing large amounts of CO2 and which are vertically separated by thick shale formations that prevent CO2 from migrating upward. This general geologic environment is a proven trap for natural gas over geologic time as evidenced by the nearby Rio Vista Gas Field. Assuming step-by-step progress through the various stages, the Montezuma Hills project will involve drilling an appraisal well to over 3 km (10,000 ft) depth, carrying out a small-scale evaluation injection of 6,000 tons of CO2, and evaluation of the feasibility of developing the site for a large-scale injection (e.g., 1 million tons of CO2), and further consideration of the site for an industrial-scale GCS operation (e.g., 0.75 million tons CO2/yr for 25 years). Because GCS is not widely carried out either in the U.S. or abroad, there is very little experience upon which to base estimates of performance of GCS systems. In the absence of a long track record, leakage risk assessment methods are needed to address concerns by the various stakeholders about the effectiveness of CO2 trapping and the environmental impacts resulting from CO2 injection. For the last two years, investigators at the Lawrence Berkeley National Laboratory (LBNL), The University of Texas at Austin (UT), and the Texas Bureau of Economic Geology (TBEG) have been developing a framework called the Certification Framework (CF) for estimating CO2-leakage risk for GCS sites (Oldenburg et al., 2009). Risk assessment methods such as the CF rely on site characterization, predictive models, and various methods of addressing the uncertainty inherent in subsurface systems. A brief outline of the methods used in the CF is provided in Appendix A. This report presents a discussion of leakage risk issues for the Montezuma Hills project and an outline of the research that needs to be done to carry out a leakage risk assessment by the CF approach. C6 Resources has already gathered and synthesized a large amount of data and information on the Montezuma Hills site to examine the feasibility of injecting CO2 at the site. In this case study discussion and research outline, we focus on public data and information that are important from the perspective of CO2 and brine leakage risk assessment. For understandability, inevitably some overlap with information already collected will occur, but our emphasis is on data and interpretations relevant to leakage risk assessment that apparently have not previously been considered in detail by C6 or WESTCARB related to vulnerable entities and potential risk mitigation. For example, we discuss the shallow aquifers, surface water, potential for pressure impact on natural gas resources, and the significance of historical natural gas seepage. As for risk mitigation, winds in the area are a favorable mitigating factor relative to surface leakage due to their ability to disperse CO2 ground plumes. Note that some of the information and text presented here is taken directly from an LBNL report two of us (Oldenburg and Jordan) contributed to several years ago (Oldenburg et al., 2003), and will be indicated as such

Certification framework: leakage risk assessment for CO2 injection at the Montezuma Hills site, Solano County, California.

WESTCARB and C6 Resources are partners in a CO2 injection project in the Montezuma Hills, 80 km (50 mi) northeast of San Francisco, CA. Through a phased process that involves drilling an appraisal well and injecting CO2 on a small-scale, along with thorough analysis of data and modeling of the system, the goal of the project is to assess the deep geologic formations in the area for Geologic Carbon Sequestration (GCS), and if favorable, inject CO2 currently emitted to the atmosphere from nearby refinery facilities at industrial scales on the order of 1 million tons of CO2 per year. The deep geology at the site is considered very favorable for GCS by virtue of the numerous sandstone formations which are potentially capable of storing large amounts of CO2 and which are vertically separated by thick shale formations that prevent CO2 from migrating upward. This general geologic environment is a proven trap for natural gas over geologic time as evidenced by the nearby Rio Vista Gas Field. Assuming step-by-step progress through the various stages, the Montezuma Hills project will involve drilling an appraisal well to over 3 km (10,000 ft) depth, carrying out a small-scale evaluation injection of 6,000 tons of CO2, and evaluation of the feasibility of developing the site for a large-scale injection (e.g., 1 million tons of CO2), and further consideration of the site for an industrial-scale GCS operation (e.g., 0.75 million tons CO2/yr for 25 years). Because GCS is not widely carried out either in the U.S. or abroad, there is very little experience upon which to base estimates of performance of GCS systems. In the absence of a long track record, leakage risk assessment methods are needed to address concerns by the various stakeholders about the effectiveness of CO2 trapping and the environmental impacts resulting from CO2 injection. For the last two years, investigators at the Lawrence Berkeley National Laboratory (LBNL), The University of Texas at Austin (UT), and the Texas Bureau of Economic Geology (TBEG) have been developing a framework called the Certification Framework (CF) for estimating CO2-leakage risk for GCS sites (Oldenburg et al., 2009). Risk assessment methods such as the CF rely on site characterization, predictive models, and various methods of addressing the uncertainty inherent in subsurface systems. A brief outline of the methods used in the CF is provided in Appendix A. This report presents a discussion of leakage risk issues for the Montezuma Hills project and an outline of the research that needs to be done to carry out a leakage risk assessment by the CF approach. C6 Resources has already gathered and synthesized a large amount of data and information on the Montezuma Hills site to examine the feasibility of injecting CO2 at the site. In this case study discussion and research outline, we focus on public data and information that are important from the perspective of CO2 and brine leakage risk assessment. For understandability, inevitably some overlap with information already collected will occur, but our emphasis is on data and interpretations relevant to leakage risk assessment that apparently have not previously been considered in detail by C6 or WESTCARB related to vulnerable entities and potential risk mitigation. For example, we discuss the shallow aquifers, surface water, potential for pressure impact on natural gas resources, and the significance of historical natural gas seepage. As for risk mitigation, winds in the area are a favorable mitigating factor relative to surface leakage due to their ability to disperse CO2 ground plumes. Note that some of the information and text presented here is taken directly from an LBNL report two of us (Oldenburg and Jordan) contributed to several years ago (Oldenburg et al., 2003), and will be indicated as such