CHAPTER 5 APPLYING FEDERAL ENVIRONMENTAL LAWS TO CO2 ENHANCED OIL RECOVERY
| Jurisdiction | United States |
(May 2015)
APPLYING FEDERAL ENVIRONMENTAL LAWS TO CO2 ENHANCED OIL RECOVERY
Of Counsel
Holland & Hart LLP
Salt Lake City, Utah
Amy M. Mowry
Attorney
Shanor & Collins LLC
Denver, Colorado
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MARIE BRADSHAW DURRANT is an attorney in the Energy, Environment, and Natural Resources group at Holland & Hart, LLP, in Salt Lake City. She helps energy and mining clients navigate environmental compliance, investigations, and enforcement actions. She also advises clients on both domestic and international natural resource projects. She has extensive experience promoting the concerns of energy clients to federal agencies and legislative bodies, including analysis and critiques of proposed rules and administrative actions. Ms. Durrant has also helped clients negotiate environmental and jurisdictional issues associated with projects on public lands and in Indian country. In her pre-law life, Ms. Durrant completed a dissertation focused on environment and community issues on Mount Kilimanjaro, Tanzania, and served in the U.S. Peace Corps in Chad, Africa.
AMY MOWRY practices in the area of natural resources and energy law, with an emphasis on oil and gas title examination and transactional matters. Amy has advised clients on a variety of surface and subsurface issues in developing and safeguarding their mineral rights. Amy is licensed in Colorado, Wyoming, North Dakota, and Montana, and has prepared all types of title opinions throughout the Rocky Mountain region. Prior to law school, Amy was a graduate instructor of English Language and Literature and also served as a volunteer University Teacher of English as a Foreign Language with the United States Peace Corps in El Jadida, Morocco.
Three recent EPA actions are meant to support the current Administration's climate change policies by encouraging the sequestration of carbon dioxide (CO2) from coal-fired power plants in depleted oil and gas reservoirs. Oil and gas operations employing CO2 for enhanced recovery (ER) play a key role in EPA's plan. As envisioned by EPA, power plants will capture and sell their CO2 to oil and gas companies with depleted reservoirs.1 Oil and gas companies engaged in ER operations will pay power plants for the captured CO2, then use the CO2 to recover more oil and gas. These payments will help offset the large capital costs incurred by power plants to capture emitted CO2. As the only commercially successful, high-volume CO2 injectors, ER operators represent both the experience and the financial model needed to make carbon capture and sequestration/storage (CCS) work as a carbon-reducing strategy. If the oil and gas companies respond positively, the CO2 "sumps" in depleted reservoirs will provide the ideal receptacle for captured CO2 from power plants.
EPA's plan involves three separate yet integrated environmental regulations. First, EPA's New Source Performance Standards (NSPS) under the Clean Air Act for electric generating units/power plants (EGU-NSPS) essentially mandates CCS for all future coal-fired power plants.2 Second, EPA's Underground Injection Control (UIC) regulations under the Safe Drinking Water Act set permitting standards for both ER wells and CCS wells to protect underground sources of drinking water (USDW). Finally, EPA's regulations under the Resource Conservation and Recovery Act (RCRA) provide an exemption from hazardous waste requirements for disposal of CO2 captured from EGUs. The combination of these environmental regulations is inevitably more complicated than it at first appears.
Optimistically, all of these regulations will work together to promote reductions in CO2 that contribute to climate change, reduce the huge financial costs for power plants to capture the CO2 and support the maximum extraction of oil and gas from depleted reservoirs. Oil and gas companies gain an additional source of CO2 for enhanced recovery, simultaneously increasing their prospects for CO2 acquisition while reducing the costs for coal-tired power plants to capture the CO2. The RCRA regulations provide regulatory relief from burdensome hazardous waste requirements to facilitate the symbiotic relationship.
Under this idealistic scenario, oil and gas companies whose oil fields no longer produce could change their business models from oil and gas production to CO2 sequestration, charging power plants for the captured CO2 streams (CO2 Streams) that were previously purchased to recoup the additional costs of transitioning their wells from regulation under UIC Class II to Class VI. However, as EPA has begun to enact these regulations, the reality is falling short of these rosy expectations. While the three regulatory schemes are in different stages of development, several legal concerns and inconsistencies are becoming apparent through public comments, administrative
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petitions and active litigation. This paper explores how the three interrelated environmental regulations--the EGU-NSPS, UIC Class VI wells and the RCRA CO2 hazardous waste exemption--are developing and evaluates the current implications for ER operators within a context that is still taking shape.
I. The Integration of the Electric Generating Unit NSPS and CO2 Enhanced Recovery
While a power plant rule may not seem relevant for ER, EPA's proposed EGU-NSPS essentially requires CCS for any new coal-fired power plant, and CCS carries related implications for ER. First, EPA relies on the profitability of CO2 ER to support the feasibility and financial viability of CCS as the best system of emission reduction (BSER).3
In the EGU-NSPS, CCS is only "mandatory" for newly built coal-fired power plants.4 By setting an emissions rate limit for new coal-fired plants that can only be achieved through capturing the CO2 released by the coal and storing or sequestering it underground, EPA has made CCS the BSER technology requirement. Such technology mandates are common under the NSPS, but many consider the CCS requirement a de facto ban on new coal-fired plants because CCS technology is not currently commercially viable.5
According to EPA, the long history of successful CO2 ER projects supports the idea that CCS is a reasonable technology that can be accommodated by the power plant industry. "[A]ccording to the D.C. Circuit case law, control costs are considered acceptable as long as they are reasonable, meaning that they can be accommodated by the industry."6 EPA further observes that
[a]n assessment of the technical feasibility and availability of CCS indicates that nearly all of the coal-fired power plants that are currently under development are designed to use some type of CCS. In most cases, the projects will sell or use the captured CO2 to generate additional revenue. These projects include the following [all of which are based on CO2 offtake for ER] . . . Southern Company's Kemper County Energy Facility .. . SaskPower's Boundary Dam CCS Project ... Texas Clean Energy Project . . . [and] Hydrogen Energy California, LLC .... 7
In addition to justifying the costs of CCS as reasonable, for CCS to be required as the BSER control technology under the EGU-NSPS, EPA must establish that such technology has been adequately demonstrated.8 EPA again attempts to meet this requirement in part by relying on ER.9 Thus, EPA's regulatory ability to require CCS depends in part on a cooperative relationship between
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power plants and ER. However, because EPA does not regulate ER operations through the EGU-NSPS, there must be some external attraction for ER operators to participate in the CCS program in order for it to be successful. As experts have warned, "CCS has little chance of being used by electric utilities unless it involves EOR."10 EPA acknowledges this fact in the EGU-NSPS: "We expect that for the immediate future, virtually all of the CO2 captured at EGUs will be injected underground for long-term geologic sequestration at sites where enhanced oil recovery is also occurring."11
However, several groups have called EPA's determination that CCS is adequately demonstrated into question.12 There are recent indications that EPA may be rethinking its use of CCS in light of the difficulty of showing that CCS has been "adequately demonstrated." Recent reports indicate that EPA is evaluating fallback options because of legal concerns about the viability of CCS as BSER.13
In order to receive regulatory credit for decreasing CO2 emissions, the EGU-NSPS would require EGUs to send their captured CO2 either to Class VI wells (discussed in the next section) or to Class II ER wells that choose to increase their CAA obligations by complying with the greenhouse gas (GHG) reporting requirements in Subpart RR.14 Class II wells normally report under Subpart UU.15 The primary additional obligation under Subpart RR is the adoption of a monitoring, reporting and verification (MRV) plan that requires EPA approval and oversight and may require future revisions.16 If ER operators do not submit to these additional obligations, EGUs will not receive regulatory credit for CO2 storage, removing the real incentive for EGUs to send them captured CO2 Streams.
Affected oil and gas companies have commented that the additional reporting and MRV obligations will deter ER operators from accepting CO2 Streams.17 Currendy, most ER operators obtain CO2 from natural sources or as a co-product from natural gas processing.18 Injection of CO2 from these sources is regulated under Subpart UU, which is less burdensome than Subpart RR. Industry participants claim that Subpart UU is sufficient to protect USDWs from both natural and
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anthropogenic CO2 injections, and thus there is no reason to expect power plant CO2 Streams to pose a different or greater risk of infiltrating USDWs than natural CO2.19
The MRV Plan under Subpart RR must contain the...
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