3

Infrastructure Inventories, Environmental Restoration, and Management

The first panel session of the workshop provided an overview of ways to develop an inventory of abandoned wells, the planning and siting of shale development projects to reduce the environmental footprint, and regulatory approaches and challenges to managing unconventional oil and gas development. These three presentations were followed by a panel discussion moderated by Michael Parker (Parker Environmental and Consulting, LLC) (ExxonMobil; retired).

PANEL PRESENTATIONS

What Is the Inventory: Mapping Abandoned Wells and Lessons for the Future

Alan Krupnick, Resources for the Future

Krupnick described a study which Resources for the Future (RFF) did for the Paul Allen Foundation on closing the gaps in active oil and gas well policy (Ho et al., 2016). The concern was fugitive methane emissions which escape from various points along the natural gas supply chain and threaten to erode potential climate benefits of using natural gas. If natural gas is a clean fuel from a climate perspective, then fugitive methane emissions need to be kept to a minimum. One understudied part of the lifecycle of oil and gas fields is inactive wells, he said. The RFF study goal was to examine the scale of the problem including the number of wells, the types of impacts, the cost of decommissioning or plugging and abandoning wells, and the regulatory context.

In referring to his slide, (Figure 3.1) Krupnick explained that inactive wells can be temporarily abandoned, a situation in which a company may decide not to produce from that

well at a particular time and the well may be “shut in.”¹ For example, a Louisiana study cited that 46 percent of Louisiana wells were in this temporarily abandoned status for 10 years or more (Ho et al., 2016). In other cases, companies may be reluctant to decommission, or plug and permanently abandon wells because of the expense involved. Companies want the flexibility to go back into the market and produce from a well again if the conditions warrant at some future time. Temporary abandonment can be for a long period and the shut in strategy and technology can be less robust than what one would do if a well was plugged and abandoned. Thus, environmental impacts like methane leakage might be more severe for temporarily abandoned wells than permanently decommissioned or plugged and abandoned wells (note the difference in shading in Figure 3.1).

The orphan designation shown in Figure 3.1 applies to wells that do not have an owner. Orphaned wells are usually a result of bankruptcy, he said. Wells can be plugged and abandoned by the private sector (those that were temporarily abandoned) or by the government (in the case of orphaned wells). One of the concerns RFF heard during their study was the long term ability of technologies for plugging and abandoning a well to protect the well from methane and other leakages. The risk of inactive well leakage such as methane emissions incorporates both type and severity of the risk, as well as the number of wells. Krupnick outlined recent work in Pennsylvania (Kang et al., 2014) on methane emissions from inactive wells that suggested emissions that may constitute about four to seven percent of all anthropogenic emissions in that state.

In addition to methane emissions, groundwater contamination issues are also of concern. Kell (2011) suggested that 41 out of 185 (22 percent) groundwater contamination incidents in Ohio were traced to leakage from abandoned wells, while 30 out of 211 (14 percent) incidents were due to orphan well leakage in Texas. To provide a sense of scale,

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¹ A shut in well is capable of producing but is not presently producing. Reasons for a well being shut in may be lack of equipment or market factors, for example. Definition available at: https://cogcc.state.co.us/COGIS_Help/glossary.htm (accessed on June 1, 2017).

Krupnick cited a study (Brandt et al., 2014) that suggested approximately three and a half million wells have been drilled in the United States to date and that about 800,000 of them were still active. RFF examined drilling information in 13 individual states and found different classification methods for inactive wells. RFF found about 635,000 inactive wells in those states (Table 3.1). About 557,000 were inactive and plugged and abandoned; therefore, they were essentially decommissioned. The remaining 74,000 inactive wells were not decommissioned. The same 13 states had more than 544,000 active wells.

RFF also examined the cost of plugging these wells, and in particular the orphan wells. Krupnick noted that the costs of plugging and abandoning these orphan wells were greater than the average bonding amount that was levied (Figure 3.2), leaving many states with financial and environmental liabilities. An exception was Oklahoma where the costs of plugging and restoring orphaned wells were less than the financial bonding requirements. In Pennsylvania, however, about 98 percent of orphan well decommissioning projects exceed the average bond amount. He noted that the data are poor on this topic and it is difficult to get good data to understand the problem.

Further examination of data from Kansas helped to clarify why costs varied across decommissioned wells. Well depth was one important factor: with increased depth, decommissioning costs increased. Well age also appeared to matter: the older the well, the more expensive it was to plug, he said.

Towards the end of his presentation, Krupnick focused on regulation and noted RFF’s

past work in their “state of the states” report.² He said that their efforts examined the stringency of the regulations and compared regulations across different states. They found that although the number of elements regulated by each state was similar, the stringency with which states apply the regulations was variable. To illustrate some of the recommendations that came out of this previous RFF study, he showed a map (Figure 3.3) of the duration in time (months) of temporary abandonment of wells. The duration of abandonment varied from 6 months in Texas to 300 months in California. Krupnick also noted variation from state to state on the stringency of environmental restoration requirements.

Krupnick concluded by highlighting some of the RFF report’s main policy recommendations related to inactive wells:

• Revising the financial bonding requirements as they seem too low;
• Adjusting bonds to take account of well depth and other factors that affect cost;
• Protecting states against expensive projects;
• Tightening well transfer conditions and requirements for maintaining temporary abandonment status; and
• Improving data collection and reporting.

Landscape Scale Planning and Siting of Shale Development—an Energy by Design Approach to Reducing the Overall Environmental Footprint

Michelle McGregor, the Nature Conservancy

Energy development is the biggest driver of habitat loss in the United States, McGregor began, with energy development projects expanding into areas that previously were not at

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² For example, see “The State of State Shale Gas Regulation” report. Available at http://www.rff.org/research/publications/state-state-shale-gas-regulation (accessed on January 9, 2017).

risk for this type of landscape and habitat change. She noted that the situation has opened many opportunities to explore improved siting and mitigation approaches and that The Nature Conservancy (TNC) has been examining the issue of landscape-scale planning and siting. TNC has developed a comprehensive conservation and energy development approach that incorporates a mitigation hierarchy of avoidance, minimization, and mitigation. During the past six years, TNC has developed an ArcGIS-based tool—Landscape Environmental Energy Planning (LEEP)—which is based on a science and data-driven examination of the cumulative impacts of energy development on land, water, wildlife, and local communities, and helps optimize layouts for shale oil or gas well pads, roads, and pipelines to reduce those impacts.³

The tool incorporates existing environmental regulations and encourages exclusions and setbacks beyond regulatory minimum requirements, McGregor said, and was developed with technical contributions from industry and other stakeholders. The tool is currently optimized for the Appalachian region. For each infrastructure scenario, the tool:

• Calculates environmental impact metrics;
• Estimates development costs. Basic standardized construction costs are built into the tool; and
• Assesses trade-offs between impacts and costs.

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³ LEEP: That Nature Conservancy’s Appalachian Shale Siting Tool is available at: https://www.nature.org/ourinitiatives/regions/northamerica/areas/centralappalachians/leep-summary.pdf (accessed on June 8, 2017).

An example of the tool’s output of cost and environmental impact for several different infrastructure layouts is provided in Figure 3.4. The scenarios are input to the program prior to development to try to optimize the balance between lower environmental risk and minimum cost increases for environmental risk reduction.

In advancing the next generation of best practices in energy development, McGregor noted the strong efforts of numerous organizations in this arena including the American Petroleum Institute, the Environmental Protection Agency, and at the state level. TNC took a science-based approach to best practices for energy development with special focus on impacts to the land surface and wildlife and a set of recommended practices for ecological buffers, road development, stream crossings, water withdrawals, timing of activities, noise, and artificial lighting. Details on these best practices are publicly available on the TNC website.⁴

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⁴ For summary of TNC’s recommended practices, see http://www.nature.org/ourinitiatives/regions/northamerica/areas/centralappalachians/recommended-shale-practices-overview.pdf (accessed on January 13, 2017).

In a series of collaborative workshops hosted together with Carnegie Mellon University’s Scott Institute for Energy Innovation and the Steinbrenner Institute for Environmental Education and Research, TNC gathered stakeholders from academia, the regulatory sector, NGOs, and industry at a workshop to discuss best practices related to energy development and landscape-scale planning, and ways to mitigate impacts to habitat, water, and air. The discussions focused on current challenges, legacy impacts, and research, technology, and regulation needs. McGregor noted some of the discussions included the environmental challenges, regional maturity of oil and gas development, learning across sectors (from coal and conventional oil and gas development, for example), new technology, and the problem of communicating information between industry and other stakeholders. After the TNC workshop, a poll of industry partners indicated landscape-scale planning as an emerging opportunity for industry, she said. As communities become more involved in energy development projects or as environmental risk increases, industry is examining ways to establish comprehensive development plans in which communities have been involved, and which include well-defined environmental risks, contingency plans, and efforts to avoid and mitigate impacts. TNC continues to work with a multi-stakeholder group on planning and responsible siting of shale development projects, McGregor said, with key principles that include:

• Promoting responsible siting of shale infrastructure that minimizes impacts to environmental and cultural resources;
• Reducing surface landscape footprint through actions such as co-locating infrastructure and relationship building; and
• Integrating ecological and community considerations with geologic and economic factors at the earliest possible planning stage.

The overarching principle for landscape-scale siting and planning is to develop and implement a comprehensive lifecycle plan demonstrating the full mitigation hierarchy to reduce impacts and increase transparency, McGregor said. TNC’s approach to a mitigation hierarchy addresses avoiding, minimizing, and compensating for impacts. She noted that to advance the idea of providing compensation for impacts, TNC has been working with industry partners on the development of mitigation banking, which preserves, enhances, restores or creates an area that provides compensation for resource impacts. McGregor concluded by outlining some of the key components of landscape-scale plans for energy development projects such as the need for a written plan for siting and maintaining the operations, for transparency and baseline data, for implementation of mitigation procedures, for monitoring, and for all parties to be held to the same requirements.

Management: Regulatory Approaches and Challenges

Leslie Savage, Texas Railroad Commission

Savage focused most of her remarks on inactive and producing wells in Texas. She initially noted that the Railroad Commission⁵ in Texas has a large program for the cleanup of abandoned and orphaned well sites with regulatory requirements for surface landscape restoration. She said that about 1.25 million wells have been drilled in Texas with well depths

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⁵ The Commission was established in 1891 to regulate the rail industry. Since that time, the Commission has been responsible for overseeing many industries that include oil and gas, alternative fuels, gas services, pipeline safety, and mining and exploration. Available at http://www.rrc.state.tx.us/ (accessed on January 18, 2017).

ranging from 40 feet to 30,000 feet. These wells include horizontally and vertically drilled wells, wells in permeable sediments, and wells that are fracture-stimulated to produce oil and gas. The wells are drilled in both rural and more populated areas where communities may have varying levels of experience with oil and gas development. When regulating oil and gas development, state and local government in Texas also has to consider variations in climate, water resource availability, and geologic conditions, she said.

Texas has a long history of oil and gas production, with its first commercial oil production in 1866 and natural gas production in 1872. Today, Texas has about 7,000 active well operators and 318,000 actively producing wells. Regulations in Texas have been continually adjusting to improve the overall effectiveness of the programs and to encourage oil and gas production. Savage noted that monitoring trends over time was an important component of adjusting regulations to meet current needs.

The first state regulation on well plugging was developed in 1919 and has been updated many times by the Commission since then (e.g., 1934, 1965, 1966, 1992, and more recently). In 1965, the Commission established its first well plugging program supported by revenue generated from public funds.

The Commission identifies inactive wells as wells that do not have an organization report⁶ which is required for any wells under the Commission’s jurisdiction, she explained. The organization report has to be renewed each year and the Commission ensures that the operator is in compliance with regulations and that financial assurance is in place for active and inactive wells. If the organization report is not renewed, then the wells are categorized as inactive.

Savage noted that in 2010 and again in 2012, the Commission amended their rules to address inactive wells. Components of this change included putting time limits for determining when operators have to purge production fluids from all piping, tanks, vessels and equipment;⁷ when they have to remove storage facilities and other equipment from the well site; and when to assess risks to groundwater for the life of that well. As wells remain inactive for longer periods, the regulatory requirements become more stringent. Before an operator can renew their organization report, which is required by the state to continue to do business, the operator has to procure financial assurance. They can select to plug 10 percent of their inactive well inventory every year or they have to certify that the well has a future use, she said.

In 2014 the Commission also amended their well completion and well control rules, Savage said. The rulemaking was expanded to address cementing and casing requirements, hydraulic fracturing, and required additional isolation of problematic zones during well drilling and well plugging. The zones include those with corrosive fluids, pressured potential flow zones, and disposal well zones. By tightening the requirements for the completion of wells, the Commission believes there will be fewer problems with plugged wells. She emphasized that the Commission requirements are directed toward decreasing the risk for future problems with legacy wells.

Savage commented on the multi-pronged approach in Texas to address the regulation of development and maintenance of oil and gas wells:

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⁶ For example of an organization report, see http://www.rrc.texas.gov/media/2637/form-p5.pdf (accessed on January 18, 2017).

⁷ See http://www.rrc.state.tx.us/oil-gas/compliance-enforcement/hb2259hb3134-inactive-well-requirements/surface-equipment-cleanupremoval/ (accessed December 2017).

• Financial security requirements such as bonding, letter of credit, and cash deposits for specific well types;
• Inactive well requirements; and
• Well plugging requirements.

The Commission does restrict the transfer of wells from one operator to another. If an operator wants to transfer wells to another operator, the receiving operator has to have sufficient financial assurance, she said. Compliance with the Commission’s rules is also required.

In her concluding remarks, Savage highlighted that the oil and gas regulatory cleanup fund takes care of abandoned wells, orphaned wells, wells that do not have an operator, and site cleanup. The fund is not publicly funded, rather it is funded by fees and penalties incurred by industry in Texas.

MODERATED DISCUSSION

An online participant noted that Texas has a large number of wells in the Permian Basin. If one considered wind and solar development, in addition to oil and gas development, it is one of the most energy intensive areas in the world. Would the TNC landscape planning tool be scalable and usable for this region? McGregor responded by indicating that, while the tool was developed originally for hydraulic fracturing it could be adapted to consider wind and solar. Three companies looking at purchasing and using the TNC tool are considering it for other types of energy development, she said.

A recurring theme during the workshop was inadequate financial bonding for future remediation. A participant noted that it is difficult to get bonding increases through their state legislature and suggested looking at solutions such as a severance tax or post-revenue taxes. Savage indicated that the Texas legislature is examining bonding, although financial bonding will not cover the majority of plugged wells in Texas where operators already pay a regulatory fee. These fees generate monies that go into an oil and gas regulation fund which can be used to address issues at the well site. Savage noted the challenge of maintaining a balance between ensuring that companies have funds to develop oil and gas and ensuring enough funds are available to take care of problems after the resource is extracted.

Parker noted several states that have implemented similar programs to Texas, for example Louisiana and Oklahoma, where operators pay into dedicated funds for reclamation and cleanup at well sites. The future will require addressing tens to hundreds of thousands of wells but without a coherent funding mechanism presently in place to do so. This situation presents a challenge with implications for legacy concerns related to wells, surface facilities, and infrastructure. Savage followed with a comment on groundwater contamination noting the Texas Groundwater Protection Committee. The committee consists of water resource agencies which meet quarterly and make legislative recommendations via published reports. She noted that the group produces a joint groundwater monitoring report every other year. Past reports have established that the majority of groundwater contamination incidents in Texas are not due to legacy wells. Krupnick followed with a comment on fugitive methane emissions, which are mostly well-related rather than pipeline-related issues when viewed from a legacy perspective. He mentioned that a few states are trying to implement programs to reduce fugitive methane emissions; however, methane emissions are primarily a national and global issue. States do not have a lot of inherent incentive, as they would with groundwater pollution, to regulate methane from the oil and gas life cycle, he said.

Another participant indicated that inactive wells can be a regulatory concern. If the renewal of a temporarily abandoned well is routine, then the future utility is not as likely to

be evaluated by the operator. In Alabama, the participant continued, when industry wants to renew the status of an inactive well, the operator has to complete a questionnaire to address issues such as future utility of the well and wellbore integrity. With this process in place, more wells are plugged by the operators because they scrutinize the future utility of wells very seriously. If the future utility of an inactive well is not supportable based on the questionnaire, they may not seek to renew the status of an inactive well and instead choose to plug it.

The panelists were asked to comment on minimizing the subsurface footprint of wells, especially with consideration toward the large number of wells that are expected to be drilled according to forecasts by the Energy Information Administration (EIA). McGregor emphasized that TNC is focused on the surface landscape, rather than the subsurface; however, they do work collaboratively with groups that do examine the subsurface. She indicated that a tool could potentially be developed similar to TNC’s landscape-scale planning tool that would focus on the subsurface.

Regarding the costs of plugging and abandoning, a participant highlighted that the costs Krupnick presented seemed low. From the participant’s experience, plugging and abandoning a well may range between about $50,000 and $200,000. Krupnick indicated that the numbers in their report were from averages derived from available state data and that he, too, was surprised by the low numbers. Parker indicated that a drilling rig is not always necessary to plug a well, thereby lowering the cost somewhat. The majority of plugging work today is actually done with coal tubing units, which are cost-effective and could be a contributing factor keeping the costs relatively low. Bundling wells for plugging and abandonment, a practice used in Texas, may also help to lower the costs of mobilization of equipment, Savage indicated. An online participant asked what funding mechanisms would be appropriate for plugging leaking wells since plugging is inadequately covered by financial bonding or regulatory fees. Parker noted that several states have set up orphan well programs and these programs are funded by a fee or tax. He said that Texas, Louisiana, and Oklahoma are among those states with these types of programs.

Another participant asked how TNC will measure the effectiveness of their landscape planning tool in terms of conservation outcomes. McGregor noted that using the tool does not guarantee a conservation outcome but that the tool may help industry recognize opportunities to look at their projects on the scale of the full landscape to reduce the overall environmental footprint. Krupnick followed by noting that models are needed, for example, to identify an optimal spatial siting for wells.

The purpose of the workshop—that is, what is being done now to prevent negative legacy impacts into the future—was a theme emphasized by a participant who suggested it would be valuable to take a set of orphan wells and do a historical analysis of their origins. The participant noted that many state regulatory organizations updated their bonding requirements during the 1990s but that many of the state financial bonding systems were established as penalty bonding systems rather than performance-based bonding systems. This arrangement was made, in part, because these wells are very long lived assets. The participant suggested that perhaps the question is not whether the bonds pay for the cost of plugging but rather, do the comprehensive regulatory systems prevent wells that are being drilled today from going into an orphan well status? Krupnick noted that many factors contribute to better well construction and these factors probably lower the environmental risk of the newer wells relative to the older ones. Well integrity is much higher now than it was in the past. Further, plugging standards have evolved dramatically during the past decades, so the likelihood of well leakage is probably much greater for a well plugged in 1930 than it is for a well plugged in 1995.

Another participant asked what kind of follow up occurs at the regulatory level once the wells are plugged and abandoned. Parker indicated that, in general, most state regulations for plugging wells are responsive to groundwater protection concerns or methane leakage. Schematic wellbore plugging requirements in most states are established to address this issue, he added. Although this does not prevent a problem from occurring in the future, most states are attentive to these kinds of concerns, he said.

McGregor posed a question about a way to create a financial accounting standard that would affect well depreciation after a specific time frame similar to what is done with capital assets. A participant remarked that various types of depreciation are already taken into account. For example, equipment and the lease on the well are depreciated with time. Usually depreciation helps the well stay solvent for a longer time because it reduces taxes, she said. Regarding taxes, she noted severance taxes are already established to help recover and compensate the public from possible future impacts from wells. Perhaps a review of some mechanisms that are already in place to mitigate potential future environmental risk might be warranted, the participant said.

A final comment from a participant addressed well-bore integrity. The participant noted the issue of deep-well injection to dispose of waste water implicated in the incidence of induced seismicity in states like Kansas and Oklahoma and how this poses new challenges to define well-bore integrity.

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