Considerations for the Implementation of the New Underground Injection Control Program for Carbon Dioxide Geologic Sequestration

Regulations for geological sequestration (GS) of carbon dioxide (CO2) have been adopted in the state of Washington and proposed by the state of Kansas and the U.S. Environmental Protection Agency (EPA) Underground Injection Control (UIC) Program. These three sets of rules take significantly different approaches to regulating GS of CO2. This paper compares these rules, focusing on elements where their differences highlight the choices that must be made to create a regulatory framework for GS in the United States. Consensus is emerging in some areas, but there is still substantial disagreement regarding the allowable composition of the CO2 stream, the size of the area of review, reservoir performance goals, and management of risks other than those to groundwater. Gaps include issues related to ownership of subsurface pore space, greenhouse gas accounting, and long-term stewardship. The divergent approaches of these rules raise two overarching questions: (1) Should policy makers create GS regulations by modifying and supplementing UIC rules or through new enabling legislation? (2) What should be the relative roles of state and federal governments in GS regulation? We outline trade-offs between the consistency and coordination that federal involvement could offer and the reality that states need to be heavily involved with implementation of GS regulations. We conclude that federal involvement above and beyond the proposed EPA Class VI rules is needed to create effective GS regulation in the United States.

ABSTRACT: The United States Environmental Protection Agency (USEPA) developed the Underground Injection Control (UIC) Class VI regulations under the authority of the Safe Drinking Water Act (SDWA), specifically for the injection of carbon dioxide into deep subsurface formations for the purpose of geologic sequestration. The Class VI regulations are built upon the long-standing protective framework of the UIC Program to prevent the endangerment of underground sources of drinking water, with requirements that are tailored to address issues unique to carbon dioxide injection. These include requirements that address the large injection volumes anticipated at geologic sequestration projects, higher reservoir pressures relative to other injection formations, and the behavior of the injected carbon dioxide (e.g., its relative buoyancy, mobility within subsurface geologic formations, and corrosivity in the presence of water). The regulations establish technical requirements for geologic site characterization, area of review, corrective action on artificial penetrations, well construction, testing and monitoring, reporting, well plugging, post-injection site care, site closure, and financial responsibility.

U.S. Environmental Protection Agency’s (EPA’s) Class VI regulations require owners or operators of carbon storage projects to determine an Area of Review (AoR) representative of project risk to underground sources of drinking water (USDWs). The AoR is an estimate of the project footprint and is used to develop monitoring plans to ensure protection of USDWs. In this syudy, the NRAP-IAM-CS software tool was applied to estimate the AoR and the leakage potential of legacy wells located within the AoR to impact groundwater quality at a carbon storage screening site for the NMB-CS, Phase 1 project. The NRAP-IAM-CS is a science-based toolset developed by the U.S. Department of Energy for quantitative risk assessment of geologic sequestration of carbon dioxide (CO2) (Pawar et al., 2016). The toolset adopts a stochastic approach in which predictions include site uncertainties using storage reservoir, leakage scenario, and shallow groundwater impact reduced order models (ROMs). Risk-based analysis done using the NRAP-IAM-CS yielded an AoR that was comparable to estimates defined by the critical pressure needed move fluid from the reservoir to the overlying USDW through an open wellbore. The risk-based AoR was slightly smaller than that based on the critical pressure (234 km2 compared to 269 km2), because small fluxes did not impact groundwater quality. Leakage from two legacy wells located within the AoR should not impact groundwater quality over the 30-year injection period. Legacy Well 1 penetrates the simulated CO2 plume and would require a permeability of 5 x 10-12 m2 (~5 Darcy) to impact groundwater quality after about 20 years of injection. Legacy Well 2 falls outside of the CO2 plume footprint, where reservoir pressures are too small to generate large enough leakage flux to change groundwater quality even with well permeabilities as high as 5 x 10-11 m2 (~50 Darcy). This work represents one of the first applications of the NRAP toolset for the screening of potential CO2 storage sites. The toolset provides a risk-based method of evaluating the AoR and the impact of CO2 or brine leakage through legacy wells. The following recommendations will strengthen the use of probabilistic assessments for site selection and permitting of Class VI CO2 injection wells.

In this peer review process, member states of the Underground Injection Practices Council (UIPC), the USEPA and the USDOE have attempted to look at the major ground water protection efforts of state regulatory agencies, their underground injection control (UIC) programs. It is the belief of the UIPC that the national UIC program represents one of the oldest, largest and perhaps one of the most effective environmental programs to protect our nation's Underground Sources of Drinking Water (USDWs). These programs have been in place for many years. During that time our national commitment to ground water protection and the available technologies to protect it have changed extensively. In light of these changed commitments and new technologies, the UIPC set out to look at the California UIC program. Topics/processes addressed in this report include: permitting, mechanical integrity testing, compliance, plugging and abandonment, inventory/data management, public outreach, and personnel qualifications. (CBS)

The Commonwealth of Pennsylvania relies heavily upon its ground water resources for drinking water. The U.S. Environmental Protection Agency, Region III, is responsible for regulating the discharge of waste to the subsurface through injection wells within Pennsylvania. To facilitate identification of industrial facilities unregulated by EPA that may be contaminating ground water through industrial water and waste water discharge wells, a screening procedure was devised utilizing a Geographic Information System (GIS). This procedure involved cross-referencing locations of industrial sites to maps of municipal sewer systems. The effectiveness of this GIS screening procedure was investigated in seven counties in southeastern Pennsylvania. Facilities identified by the procedure were inspected for possible violations of Underground Injection Control (UIC) program regulations. As a result of these inspections, many facilities were found to be illegally discharging waste into ground water. In addition, other EPA program violations were identified. The project demonstrated that the GIS screening procedure can be an effective tool to locate sources of pollution of ground water.

Design Support of an Above Cap-rock Early Detection Monitoring System using Simulated Leakage Scenarios at the FutureGen2.0 Site

Summary Purchasing producing oil and gas properties without consideration of the potential environmental liabilities attendant to ownership and operation is a trap for the unwary. Changes in the law governing injection operations, toxic waste, and groundwater contamination are increasing dramatically the level of monitoring and reporting activities in the oil industry. The potential liability to restore and clean up damages caused by past operating practices exists. In the past, valuing petroleum properties has been done with little consideration of these regulatory aspects. Three cases are presented that involve parts of real problems to demonstrate the regulatory impact on operation and development of petroleum properties. Those who purchase or appraise producing properties should apprise themselves of potential new business Costs and ensure that economic projections reflect the change. When appraising engineers lack the expertise to evaluate or are directed by the client to ignore these aspects, engineering reports should disclose that these aspects have not been analyzed. Introduction Engineers, sellers, purchasers, and energy lenders should become familiar with the terms Superfund Amendment and Reauthorization Act (SARA), Resource Conservation and Recovery Act (RCRA), Underground Injection Control (UIC), and Underground Source of Drinking Water (USDW). Petroleum property purchasers or appraisers must develop some awareness of the rapidly changing regulatory climate and how regulatory programs affect development projects and their economics. Compliance Audits and Site Inspections A Potential Cure for Financial Woes Regulation under SARA has set the precedent for the assumption of a previous owner's environmental liability through the purchase of real estate. Properties of relatively small value are burdened with enormous cleanup costs. Because these costs could easily exceed a small company's net worth, environmental liabilities are a financial burden to be avoided. Although the oil and gas industry has been exempted from regulation under hazardous-waste programs, it is not protected from problems under a variety of local, state, and federal regulations. Purchasers should investigate the compliance and site conditions to protect themselves from the unnecessary assumption of the seller's troubles, a problem that may not be effectively immunized by contract language alone. Areas of Concern to Petroleum Valuation Engineers Compliance with existing regulations is a problem of national scope. The greatest impact, however, is in the older producing areas, where drilling activity predates regulation, particularly in the Appalachian basin, Illinois basin, parts of the Michigan basin, and the eastern portions of Texas, Oklahoma, and Kansas. Compliance problems have a major impact on the value of property. Petroleum engineers should be careful in providing clients with reserve and valuation studies where environmental problems are ignored. Three areas viewed as major concerns aregroundwater contamination from production and injection wells or pits,the inability to make property improvements because of construction requirements and regulatory constraints, andfailure to comply with existing construction or facilities regulations and to conduct monitoring and reporting programs.

The U.S. Environmental Protection Agency (EPA) administers the Safe Drinking Water Act (SDWA) to ensure that the water obtained from a public water supply is safe to drink. Under the SDWA, EPA establishes enforceable maximum contaminant levels (MCLs) for contaminants that may have an adverse health effect and are known or anticipated to occur in water. Occasionally, public water supplies are unable to meet the MCL at the time it becomes enforceable. The SDWA allows public water supplies to apply to the State for a temporary variance or exemption from an MCL(s) as long as the concentration of the contaminant(s) exceeding the MCL(s) does not result in an unreasonable risk to human health. EPA has developed guidance to assist States in determining what level above the MCL presents an unreasonable health risk. In developing this guidance, the toxicity exhibited by each regulated contaminant is evaluated individually. Consideration is also given to the available risk assessments (short-term and long-term) for each contaminant, comparing carcinogenic risks with noncarcinogenic assessments. Other factors that may be considered on a contaminant by contaminant basis include for example, past exposure and expected duration of the variance or exemption period, population sensitivity, and volatilization of the contaminant from drinking water.

The sanitary survey program was created by the US Environmental Protection Agency (EPA) to support state primacy agencies in assessing utility progress with implementing water quality requirements in the Ground Water Rule and the Interim Enhanced Surface Water Treatment Rule. In the spring of 2021, EPA said it was planning to issue a direct file rule to integrate cybersecurity into the existing sanitary survey program. Multiple organizations representing water utilities and state primacy agencies communicated to EPA that using the sanitary survey program for cybersecurity was ill-advised. Even so, on March 3, 2023, EPA issued the “Cyber Rule” directing state primacy agencies to assess cybersecurity of public water systems (PWSs) as part of the sanitary survey program—effective immediately. The new Cyber Rule requires all PWSs (n = 151,606) to determine whether they use “operational technology,” meaning hardware and software that detect or cause a change through the direct monitoring or control of physical devices, processes, and events in the enterprise, per the Internet of Things Cybersecurity Improvement Act of 2020, 15 U.S.C. § 271(3)(6). EPA provided states with three compliance options: (1) self-assessment or third-party assessment by a state-approved entity; (2) state assessment during a sanitary survey; or (3) an alternative, equivalent, state-developed cybersecurity program. The draft guidance for the Cyber Rule includes a checklist of 33 controls that EPA determined are “technically feasible for most PWS[s] to address without significant capital expenditures.” Sixteen of these controls are classified by EPA as potential “significant deficiencies” if not implemented. There are numerous implementation challenges, including the ability of a state official to nonintrusively verify that a control has been implemented. The Cyber Rule interprets the use of operational technology as being part of the equipment or operations examined in the sanitary survey, components used for producing and distributing safe drinking water. This represents a significant expansion of the states’ existing sanitary survey inspection obligations. The details of the rule were never proposed or made available for public review and comment, which is the norm under the Administrative Procedures Act (APA). While EPA did have discussions with states in the summer of 2022, the Association of State Drinking Water Administrators has consistently advised the agency against using the sanitary survey for addressing cybersecurity. Bypassing APA and other regulatory obligations represents a troubling process issue that undermines the integrity of the rule of law. This includes EPA's determination that the regulatory oversight approach set out by Congress in §2013 of America's Water Infrastructure Act (AWIA) of 2018 was, in the administrator's judgment, insufficient. AWIA §2013 amended the Safe Drinking Water Act (SDWA) §1433 to require each community water system serving 3,300 or more people to conduct a risk and resilience assessment (RRA) at least every five years, which explicitly encompass cybersecurity threats to “electronic, computer, or other automated systems.” Further, §2013 requires systems to incorporate the findings of the RRA into emergency response plans, which must address the “strategies and resources to improve the resilience of the system, including the physical security and cybersecurity of the system.” Congress clearly defined a process by which a specific class of PWSs would address cybersecurity. Finally, Congress instructed EPA to directly implement, oversee, and enforce AWIA §2013. Unlike other SDWA requirements, AWIA does not authorize the EPA to delegate implementation to the states. Contrary to congressional direction, the Cyber Rule shifts the burden of oversight to the state. Many of these procedural concerns were shared with EPA in a January 2023 letter from the water community. Undeterred, EPA proceeded with issuing the Cyber Rule. Subsequently, on April 17, the states of Missouri, Arkansas, and Iowa filed a challenge to the Cyber Rule in the US Court of Appeals for the Eighth Circuit, State of Missouri, et al. v. EPA, et al., No. 23-1787 (8th Cir.). AWWA and the National Rural Water Association have filed to intervene on behalf of the states. The intent of the challenge is to hold EPA accountable for going around the checks and balances created to govern the promulgation of regulations. Perhaps watching the “Three Ring Government” episode from Schoolhouse Rock! is in order since it explains the balance of power between the three branches of government. The judiciary is a last resort for accountability; it is unfortunate that the public–private collaboration called for in the National Cybersecurity Strategy was not exercised. Kevin M. Morley is manager of federal relations at the AWWA Government Affairs Office in Washington, D.C. He can be reached at [email protected].

A team led by the Gulf Coast Carbon Center at the Bureau of Economic Geology, Jackson School of Geosciences at The University of Texas at Austin, has been funded by the National Oceanographic Partnership Program (NOPP) through and in cooperation with the U.S. Department of Interior (DOI), Bureau of Ocean Energy Management (BOEM) to generate a Best Management Practices (BMPs) document on sub-seabed geologic sequestration of carbon dioxide (CO2) below the U.S. outer continental shelf. The team consists of scientists, engineers, lawyers, and business managers from academia, private industry, and State of Texas government from the following institutions: (1) Gulf Coast Carbon Center at the Bureau of Economic Geology (BEG), (2) Det Norske Veritas (USA) Inc (DNV), (3) Wood Group Mustang and sister company Wood Group Kenny (Wood Group), (4) Texas General Land Office (GLO), (5) Harte Research Institute for Gulf of Mexico Studies at Texas A&M University-Corpus Christi (HRI), and (6) The University of Houston Law Center. Individual team members have expertise in carbon sequestration monitoring, CO2-pipeline design and construction, and domestic and international offshore environmental policy. The BMPs will be reviewed by external experts after it is generated and before being submitted to BOEM. The purpose of the BMPs will be to provide technical guidance to BOEM and BSEE (U.S. DOI Bureau of Safety and Environmental Enforcement) to establish regulatory guidelines for offshore components of future U.S. Carbon Capture and Storage, which is sometimes referred to as sequestration, (CCS) industry. Sub-seabed geologic sequestration (GS) is the process whereby CO2 captured from large volume industrial sources (e.g., power plants, oil refineries) will be (1) compressed to supercritical state and transported via pipeline to offshore injection wells, and (2) injected into geologic strata deep (thousands of feet) below the seafloor. Objectives of the CO2 injection will be for “pure sequestration” (i.e., long-term storage of CO2 in subseafloor saline reservoirs) or sequestration combined with enhanced oil recovery (EOR). Sub-seabed geologic sequestration is very different from ocean dumping (i.e. dissolution of CO2 into circulating seawater) or injection of CO2 into deep water, shallow sub-seabed sediments. Some researchers proposed in the past that shallow subseafloor depths (<; 1,000 ft) were sufficient for permanent CO2 storage in deep marine environments (>; 11,000 ft water depth) (e.g., House et al., 2006). However, the shallow sedimentary subseafloor environment could become unstable and allow release of CO2 into ocean water, the end result of which would be ocean dumping. One mechanism of seafloor instability could be the release of gas from hydrates owing to pressure and temperature perturbations that may be introduced by shallow drilling and CO2 injection. Furthermore, the logistics of transporting CO2 hundreds of miles offshore to areas with sufficient water depths for storage in shallow subsea sediments would probably not be economically feasible. We want to emphasize that subseabed GS of CO2 is not ocean dumping. One of the biggest concerns for onshore GS is the potential to impact shallow drinking water resources. Injecting CO2 deep below the seafloor will avoid this potential consequence. But there are sensitive marine environments of concern in offshore settings, protection of which is critical. Environmental monitoring of marine ecosystems (nearshore, along CO2 pipeline corridors, and outer continental shelf) and subseafloor geological strata in which CO2 will be injected will be a large component of the BMPs. Topics being included in the BMPs, a draft of which will be submitted to BOEM in June of 2013, are: (1) site selection and characterization, (2) risk analysis, (3) project planning and execution, (4) environmental monitoring, (5) mitigation, (6) inspection and auditing, (7) reporting requirements, (8) emergency response and contingency planning, (9) decommissioning and site closure, and (10) legal issues. Where possible, we are using existing regulatory, policy, and technical guidance documents as a starting point for the BMPs. We think the most likely location for initiation of U.S. offshore geologic sequestration of CO2 will be in the western or central sectors of the Gulf of Mexico where extensive offshore oil and gas infrastructure already exists. Academic members of our project team are actively working on criteria for site selection [1]. However, private industry is also assessing the feasibility of offshore geologic sequestration below the Atlantic seafloor [2].

Know where you stand.The odds are African Americans are twice as likely to suffer a stroke as white Americans.Beating the odds isn't about winning, it's about living.You have the power to end stroke.1-888-4-STROKE / StrokeAssociation.org

The Underground Injection Control Regulations promulgated in 1980, under the Safe Drinking Water Act of 1974, require Area-of-Review (AOR) studies be conducted as part of the permitting process for newly drilled or converted Class II injection wells. Existing Class II injection wells operating at the time regulations became effective were excluded from the AOR requirement. The AOR is the area surrounding an injection well or wells defined by either the radial distance within which pressure in the injection zone may cause migration of the injection and/or formation fluid into an underground source of drinking water (USDW) or defined by a fixed radius of not less than one-fourth mile. In the method where injection pressure is used to define the AOR radial distance, the AOR is also known as the ''zone of endangering influence.''

This roundtable discussion focuses on the enforcement of Safe Drinking Water Act (SDWA) regulations. Reflecting its dissatisfaction with the US Environmental Protection Agency's track record of enforcing the SDWA, Congress gave the agency new enforcement powers and the mandate to use them when it passed the 1986 SDWA amendments. The change in enforcement status quo has raised numerous questions among those responsible for achieving and ensuring compliance, especially in light of the promise of a dramatically increased number of regulations.

Water requirements and uncontrolled air emissions from well vents and steam generators were estimated for each technology based upon available literature. Estimates of best air emission control technologies were made using data for EOR steam generators actually in use, as well as control technologies presently available but used by other industries. Amounts of solid wastes were calculated for each air emission control technology. Estimates were also made of the heavy metal content of these solid wastes. The study also included environmental residuals which may be expected should coal be used instead of lean crude to produce steam for thermal EOR. It was concluded that from an environmental prospective tertiary oil is preferable in many respects to shale oil, coal and synfuels. Alternative sources of oil such as syncrude, new exploration, and primary production could cause far more environmental damage than incremental EOR. Future EOR in specific regions may be constrained because of environmental issues: air emissions, solid waste disposal, water availability, and aquifer contaminators. Competition for water and the scarcity of surface water or groundwater which are low in total diminutive solids will impede some EOR projects. Risks of groundwater contamination should be minimized particularly because of requirements of the Environmental Protection Agency's new underground injection control program. A quantitative environmental assessment will require a complete and consistent data base for all fields for which EOR is planned out in which tertiary production is taking place. This is particularly true for EOR which will occur in Alaska or in offshore areas, where environments are fragile and where operating conditions are severe. 147 references, 29 figures, 46 tables.

Regulation of oil and gas exploration and production wastes and of Class II injection wells (those that inject produced brines and drilling fluids) could become more rigorous in the next several years. First, many of the wastes associated with oil and gas activities, including those disposed in Class II wells, may come under increased regulatory control. Presently, most oil and gas wastes are "exempted" from the severe requirements of the hazardous waste regulatory program. Other wastes from exploration and production activities, however, are not exempted and may potentially be subject to hazardous waste regulation. The U. S. Environmental Protection Agency (EPA) has recently "clarified" the scope of this exemption with respect to wastes associated with crude oil reclaimers, service companies, and gas plants and feeder pipelines. Moreover, Congress has been debating the reauthorization of the Resource Conservation and Recovery Act (the federal hazardous waste management statute), and one of the key issues is whether oil and gas wastes should be subjected to further regulatory control. In addition, the Railroad Commission of Texas has draft proposed rules on regulation of hazardous oil and gas wastes, which will impose additional regulatory standards and controls over such wastes. Second, EPA has been considering changes to the Class II injection well program. An Advisory Committee was assembled and was composed of representatives of major and independent oil companies, environmental interests, and state and federal regulators. The EPA has evaluated the Committee's recommendations and has drafted a proposal for additional Class II regulations. The draft proposal includes tough new construction requirements for newly drilled or converted Class II wells; added monitoring and testing requirements; and additional area of review requirements that would apply to both new and existing wells. The EPA may formally propose these rules in the Spring of 1994, and they could be finalized by Summer 1995.