Melisa F. Pollak

The Leakage Risk Monetization Model for Geologic CO2 Storage

We developed the Leakage Risk Monetization Model (LRiMM) which integrates simulation of CO2 leakage from geologic CO2 storage reservoirs with estimation of monetized leakage risk (MLR). Using geospatial data, LRiMM quantifies financial responsibility if leaked CO2 or brine interferes with subsurface resources, and estimates the MLR reduction achievable by remediating leaks. We demonstrate LRiMM with simulations of 30 years of injection into the Mt. Simon sandstone at two locations that differ primarily in their proximity to existing wells that could be leakage pathways. The peak MLR for the site nearest the leakage pathways (

A Tale of Two Technologies: Hydraulic Fracturing and Geologic Carbon Sequestration

7.5/tCO2) was 190x larger than for the farther injection site, illustrating how careful siting would minimize MLR in heavily used sedimentary basins. Our MLR projections are at least an order of magnitude below overall CO2 storage costs at well-sited locations, but some stakeholders may incur substantial costs. Reliable methods to detect and remediate leaks could further minimize MLR. For both sites, the risk of CO2 migrating to potable aquifers or reaching the atmosphere was negligible due to secondary trapping, whereby multiple impervious sedimentary layers trap CO2 that has leaked through the primary seal of the storage formation.

Risk governance for geological storage of CO2 under the Clean Development Mechanism.

T wo technologies, hydraulic fracturing and geologic carbon sequestration, may fundamentally change the United States’ ability to use domestic energy sources while reducing greenhouse gas emissions. Shale gas production, made possible by hydraulic fracturing and advances in directional drilling, unlocks large reserves of natural gas, a lower carbon alternative to coal or other fossil fuels. Geologic sequestration of carbon dioxide (CO2) could enable use of vast domestic coal reserves without the attendant greenhouse gas emissions. Both hydraulic fracturing and geologic sequestration are 21st Century technologies with promise to transform energy, climate, and subsurface landscapes, and for both, effective risk management will be crucial. Potential environmental impacts, particularly to groundwater, are key concerns for both activities, because both inject large volumes of fluids into the subsurface. Unless environmental issues and public concerns are actively addressed, public opposition could stall deployment of these two important technologies. In the United States, shale gas production increased 8-fold in the past decade, and it is projected to comprise roughly half of domestic production in 2035. Between 2010 and 2011, the U.S. Energy Information Agency (EIA) doubled the estimate of technically recoverable unproven shale gas reserves. U.S. energy supply projections have been fundamentally and strategically altered. Hydraulic fracturing, which makes this bounty possible, injects a mix of water, propping agents, and proprietary chemicals at high pressure to create millions of small fractures in low-permeability shale and liberate trapped natural gas. At each well, 2 to 4 million gallons of water are injected and 30 to 70% remains underground. Geologic sequestration could keepCO2 out of the atmosphere by capturing it at coal burning power plants or other industrial facilities and injecting it into deep geologic formations. The U.S. Department of Energy, in the 2010 Carbon Sequestration Atlas, estimated that the nation has the capacity to store all CO2 emissions from large domestic stationary sources for at least 500 years (at 2009 emission rates). Geologic sequestration has great promise, but its role in the U.S. energy future is uncertain; there is no economic driver to do it unless society decides to substantively reduce GHG emissions. A few demonstration projects are underway, scheduled to inject a total of about 10 million tons of CO2 in the United States. Another 12 million tons of captured CO2 was used for enhanced oil recovery in 2010, but currently, geologic sequestration is a minor player on the U.S. energy stage. Although hydraulic fracturing and geologic carbon sequestration are distinct technologies, they pose some similar environmental risks. Groundwater contamination could occur if injected or mobilized fluids escape from the target formation and migrate upward into drinking water along faults, fractures, abandoned wells, or poorly constructed injection wells. Both technologies can protect groundwater by carefully studying site geology so only appropriate sites are chosen, using best practices for well construction, monitoring site performance, and developing emergency and remedial response plans so all parties are prepared if problems arise. Despite similarities in their environmental risks, regulations for geologic carbon sequestration and hydraulic fracturing are drastically different; the result is that similar risks are managed quite differently. Ironically, nascent geologic sequestration technology has state-of-the art regulations that were crafted during a decade of federal notice-and-comment rulemaking. The environmental risks of geologic sequestration will be managed by the EPA UIC program, under new Class VI well rules adopted in 2010. As the first injection well class added since 1983, Class VI rules incorporate advances in subsurface technology and modeling, regulatory philosophy, and environmental expectations that have transpired in the intervening quarter century. In contrast, the Energy Policy Act of 2005 officially exempted hydraulic fracturing from regulation under the UIC program. The environmental risks of shale gas production are managed

Research for deployment: Incorporating risk, regulation, and liability for carbon capture and sequestration

Managing local and global risks from the geological storage of CO2 under the Clean Development Mechanism (CDM) presents three main challenges. First, the CDM procedures must be adapted to the specifics of the technology. Second, storage must last far longer than the crediting period, leaving questions about the management of long-term risks. Third, management of local environmental, health and safety risks falls largely outside the CDM governance framework. CDM procedures could be adapted to successfully manage the short-term global risk of carbon dioxide re-entering the atmosphere during the CDM crediting period, but local environmental, health and safety risks and longterm global risk cannot be ensured under existing structures. To better manage these risks, the implications for the CDM are: (1) to provide guidance on site characterization requirements, and have an independent auditor verify that the proposed geological storage site has a high likelihood of safely containing the injected carbon dioxide; (2) to require that carbon capture and storage (CCS) project design documents specify post-crediting-period commitments; and (3) to support CCS specific capacity building. But because CDM governance is designed to strike a balance between respecting host country sovereignty and ensuring high-quality emission reduction credits, some limitations to risk management of geological storage under the CDM remain. These limitations should be weighed against the potential benefits of including CCS in the CDM.