2

Understanding Legacy Issues and Managing Risk

The first session of the workshop included three keynote presentations. The keynotes provided the broad context for the workshop and included aspects of technology development, resource assessment, and regulatory perspectives. The keynote presentations were followed by a discussion between the speakers and the audience. This discussion was moderated by Dr. Susan Brantley (The Pennsylvania State University).

KEYNOTE PRESENTATIONS

Technology and Approaches to Development, Evolution, and Decommissioning
of Unconventional Wells (Subsurface) and Surface Infrastructure

Vikram Rao, Research Triangle Energy Consortium

Rao opened his presentation by describing the basic technological components and approaches for development of an unconventional well, with particular attention to the physical barriers—steel and cement—associated with the integrity of a well. His premise was that a properly constructed well with sound mechanical integrity is less likely to leak in the future and he emphasized the importance of the quality of the cementing process in preventing such leakage and avoiding negative environmental impacts.

Almost every unconventional well is drilled vertically and then horizontally, with hydraulic fracturing occurring on this lateral extension (Figure 2.1). All wells have a steel surface casing¹ that is cemented, with the casing located at some depth below the deepest

___________________

¹ Casing is a term used for pipe (typically steel) that is lowered into the drilled hole and cemented into place. The casing helps to prevent the geological formation from collapsing into the open hole, prevents the flow of fluids from the well into the surrounding rock formation or aquifers, and provides a means to manage and monitor fluid pressure in the well. See Schlumberger Oilfield Glossary: http://www.glossary.oilfield.slb.com/Terms/c/casing.aspx. Several different casing segments are usually constructed during the completion of the well, each with a surrounding cement seal (see Figure 2.1).

underground sources of drinking water. After the surface casing is set, drilling continues to a point above the horizontal target zone, where another steel casing, called an intermittent casing, is set (Figure 2.1). That casing is also cemented before the drill bit is turned horizontally into the hydrocarbon-bearing rock formation. The horizontal zone itself is cased and may or may not be cemented. Rao noted that each casing is typically sealed and protected by a layer of cement to prevent leakage into surrounding rock or water zones. The purpose of

the well completion process is to link the reservoir to the surface and isolate the producing reservoir while providing a conduit for safe production of oil or gas.²

Rao then discussed regulatory and voluntary compliance mechanisms that can help to assure well construction best practices as a remedy for preventing downhole leak paths. Referring to a regulatory example from the North Carolina Mining Engineering Commission, he cited a rule that required well casing to be placed 100 feet below the deepest underground sources of drinking water. He also reiterated the need for high-quality cementing with particular attention to zones of potential fluid incursion. Although not all wells are cemented bottom to top for specific production-related reasons, he emphasized the need to test the cement integrity before and after it is set.

The decommissioning of wells involves plugging and dismantling the surface well infrastructure (typically called “plugging and abandoning” the well) and can also have negative legacy impacts if not performed correctly. With plugging and abandonment procedures, Rao suggested that early warning systems for detecting leaks and spills associated with these activities might be designed and employed through a combination of best practices, instrumentation, and monitoring.

Focusing on potential leaks at the surface near a well, Rao discussed five different categories: (1) surface spills on or near a well site; (2) unintentional leaks from equipment; (3) leaks due to specific design choices (e.g., valves that use line pressure); (4) leaks due to operational practices; and (5) leaks from wastewater impoundments. He indicated that spills at or near the rig site are probably the issue of most concern at present (Drollette et al., 2015). With regard to operational practices, he shared an example with gas wells. During gas production, he said that liquid may load in the bottom of the well from time to time which then can hinder gas production. The liquid may be released to the surface via pressure from within the reservoir which will allow the gas to resume flowing but, he noted, this practice of releasing the liquid from the well can be performed in both environmentally correct and incorrect ways. Thus, an opportunity exists for sound design choices, which would avoid potential negative environmental consequences.

Other remedies to prevent negative environmental impacts include well-written plans and sharing best practice experiences. He illustrated an approach using DeepStar®.³ This approach was taken voluntarily by industry to address a particularly difficult problem—effective development of offshore production wells in deep water. Companies worked together to form a consortium that did not violate antitrust issues, and collaborated to advance safe well infrastructure and increased efficiency in the production of oil and gas. He suggested that the benefits of these kinds of voluntary efforts reach beyond just the industry members. Rao also mentioned that most engineering and process designs have forks in the road. At these forks, more sustainable and less sustainable choices exist. Incorporating an analysis of these kinds of choices in engineering curricula at universities is not commonly done, he said. Doing so could provide an opportunity to develop the next generation workforce for unconventional resources with a culture oriented toward engineering and development that leaves positive environmental legacies.

Rao concluded by discussing issues associated with methane emissions. Proportional sources of fugitive methane based on estimated annual emissions from natural gas production indicate that natural gas distribution systems are a significant source of anthropogenic

___________________

² See http://www.glossary.oilfield.slb.com/Terms/c/completion.aspx (accessed September 2017).

³ “DeepStar is a joint industry technology development project focused on advancing technologies to meet its members’ deepwater needs to deliver increased production and reserves.” Available at: http://www.deepstar.org/ (accessed December 2016).

methane. Emissions from completion flowbacks associated with hydraulic fracturing are a small portion of the estimated annual emissions from upstream natural gas production (Figure 2.2; see also Lamb et al., 2015). In this context, Rao emphasized the importance of taking better measurements of methane emissions to help control them. He suggested that better measurements could be obtained, for example through instrumenting wells with new nanotechnology devices (see, for example, discussion by panelist Barry Freifeld, in Chapter 4). Opportunities for data analytics and communication could also aid in monitoring wells and be used in a forward-looking way to avoid future negative legacy issues from methane emissions.

To conclude, Rao remarked on the importance of locating and mapping abandoned wells and air emissions. This mapping can be done with current technologies and put into geographic information systems so that new well locations are accurately positioned and known both now and in the future.

Rigorous Unconventional Resource Assessments: Implications for Long-Term Planning and Governance

Svetlana Ikonnikova, Bureau of Economic Geology, University of Texas

Ikonnikova presented findings from an interdisciplinary study undertaken by the Bureau of Economic Geology at the University of Texas at Austin with support from the Cynthia

and George Mitchell Foundation and Arthur P. Sloan Foundation. The study assessed major U.S. shale gas and shale oil basins specifically by addressing:

• What is the resource in place?
• What portion of the resource is technically and economically recoverable? and
• What is the long-term production outlook?

To place the assessments of individual unconventional resource plays in context, Ikonnikova began by sharing some key insights from the study. She noted the economy-wide implications of the development of these resources and the potential to help reduce carbon dioxide emissions as natural gas replaces the burning of coal for U.S. energy production. She also noted the importance of recognizing that the shale gas and shale oil resources are not homogenous—every play, which is an area of hydrocarbon accumulation, is different. Thus, when considering legacy impacts from resource development, the differences between plays and the practices used to develop the resource are important considerations. When addressing economic challenges and environmental concerns, understanding past practice and planning for the future will require real efforts to integrate data, she said.

Ikonnikova referred to Figure 2.3 to discuss some of the broad similarities and differences among the six major unconventional plays the study reviewed: the Marcellus, Barnett, Fayetteville, Haynesville, Eagle Ford, and Bakken. Among all six plays, the total number of horizontal wells drilled within the last decade (not counting wells that were only drilled vertically or as directional wells) is about 65,000. She began her comparison between the plays by differentiating between them according to “resource in place”⁴ and “technically recoverable resources”⁵ using present technologies. Among the six plays, the Marcellus has the greatest gas resource in place and the greatest technically recoverable gas resource (Figure 2.3).

Ikonnikova indicated that about 23 percent of the gas and 6 percent of the oil from the total of approximately 3,100 trillion cubic feet (Tcf) of gas and 450 billion barrels of oil (Bbbl) in these six plays is technically recoverable. In the Permian basin (in western and southwestern Texas and eastern New Mexico), about 22 percent of the gas and about 7 percent of the oil are technically recoverable. Thus, even with current technology, which is considered advanced, a lot of resource is still left in the ground.

Using the Eagle Ford play as an example, Ikonnikova demonstrated use of integrated data sets to try to maximize the efficiency of production and minimize use of other resources such as water (Figure 2.4). The oil in place in the Eagle Ford is heterogeneously distributed within the play (Figure 2.4a); knowing the amount of oil in place helps understand how much can be currently recovered (Figure 2.4b), she said. With this knowledge, a profitability index (Figure 2.4c) can be calculated for given economic scenarios (e.g., Figure 2.4d). The layering of information helps create an understanding of where drilling could be expanded, where more control and monitoring are needed, and where water resources may be required (Figure 2.4e).

This kind of information can be used to calculate various U.S. Energy Information Association (EIA) price scenarios. Ikonnikova illustrated this approach by showing price scenarios for the Eagle Ford (EGLF) and Bakken shale oil. Figure 2.5 shows annual pro-

___________________

⁴ Resource in place was defined as the amount of free natural gas or liquids (which might be oil of different grades or rich condensate) that is contained in the formation, given the formation pressure and hydrocarbon-pore-volume.

⁵ Technically recoverable resources were defined as the amount of resource that can be produced by future wells with the most current technology and completion practices.

duction through 2044 assuming the price per barrel increases steadily from about 2016. Annual production is somewhat stable through time for the Bakken play, while production decreases from a peak production around 2024 in the Eagle Ford play. Ikonnikova also showed price scenarios for shale gas supply from the Barnett, Fayetteville, Haynesville, and Marcellus. These latter price scenarios suggest recovery, given today’s technologies, of less than 10 percent (approximately 300 Tcf from a total of approximately 3,100 Tcf) of the total resource in place.

To sustain oil and gas production in the future from these types of plays, Ikonnikova stressed that better geologic understanding of the plays and advances in well engineering and drilling are important. As more is learned about geology, hydraulic fracturing and other aspects of well completion can become more efficient and resource recovery may be increased. Advances in well engineering and drilling (e.g., drilling more wells per pad) are also important to sustain future production. To help illustrate this latter point, she showed an example from the Barnett which included the number of wells, well drilling direction and lengths, amount of proppant—a solid material designed to keep a hydraulic fracture open—used, the volume of water used and produced in hydraulic fracturing, and the expected recovery of

natural gas. By increasing the number of horizontal wells drilled from a single surface pad and increasing horizontal well lengths, resource recovery may be increased with less overall impact to the surface environment.

The combination of maturation in drilling technology and in understanding the geology and rock and fluid behavior of individual plays may also allow more effective recovery of surface areas once pads are abandoned and the infrastructure moved to adjacent pads. Re-entry into wells on old pads may also increase resource recovery, although revisiting old pads may raise additional questions about the quality of the old infrastructure and its ownership and operation.

The economic aspects of the geology and engineering in these plays may also influence the potential environmental impacts from development of these resources. High prices tend to intensify development, while low prices may encourage well operators to strive for greater cost efficiency through scale and intensity. With increases in scale and intensity, incident frequency and impacts could increase (e.g., spills are more costly). This, in turn, may lead to greater investment in safety and infrastructure. In contrast, low oil and gas prices may make producers more vulnerable to regulatory risks. In this situation, she said, operators often try to preempt regulations by proactively addressing potential problems with solutions.

When discussing the ways in which to leave positive environmental legacies in developing these resources, concerns often focus on land use and water, Ikonnikova said. Operators have been improving the ways in which to manage water, to prevent spills and leaks, and to work with local communities. Nonetheless, questions remain about aging and abandoned infrastructure and who is responsible for it.

To shape constructive conversations about developing these resources with minimal impacts to the environment, Ikonnikova concluded by suggesting incorporating the following elements:

• Involvement of major stakeholders, including land owners, communities, regulators and producers in discussions;
• Underpinning those discussions with comprehensive information and data sharing;
• Integrated perspectives that account for stakeholder interests and responsibilities; and
• A longer planning horizon to motivate investments.

When the Landscape Is Quiet Again

David Glatt, North Dakota Department of Health

Glatt opened his presentation by discussing the role of regulators in examining and addressing challenges. He said that regulators deal with issues on a daily basis that are raised by both land owners and well operators. When referring to the workshop theme of avoiding negative environmental legacies, his keynote title, he said, represented the responsibility of all stakeholders involved in the development of natural resources to envision what remains on the landscape after resource extraction has ceased. Through an understanding of the history of natural resource extraction in North Dakota and specifically, some lessons from legacy impacts from coal development, he suggested the potential to identify solutions to prevent negative legacy issues associated with current oil development in the state.

North Dakota has had a history as an energy exporter, Glatt said. In the 1960s, coal was mined in substantial quantities in the state to help fulfill the need in large metropolitan areas for cheap and reliable energy. During this period, Wyoming, North Dakota, and Montana were also key states with resources to provide that energy. Regulation of the coal extraction industry was not favored by some because of the concern that regulation could result in negative economic impacts. North Dakota’s governor at the time was a farmer and the governor sat through many contentious meetings about the regulation of the coal industry and posed a statement, which Glatt cited:

Glatt elaborated on the importance of developing resources for the greater good while simultaneously conducting such development in the right manner, and in an environment of collective trust. He noted that waiting for a regulation to take care of a problem may be too late, as negative impacts may have already occurred.

North Dakota has developed oil and gas resources since about the 1950s, Glatt said, although the development was fairly slow for the first fifty years (Figure 2.6). With the development of the Bakken play beginning in about 2008, however, development and subsequent oil production have increased dramatically (Figure 2.7). This substantial increase in oil production changed many aspects of life in North Dakota both positively and negatively, with a number of issues that no one foresaw. The positive developments associated with the increase in oil production were a stronger state economy, jobs, infrastructure, and an increase in the state’s population, he said. Historically, North Dakota’s population was about 600,000. Recent oil production increased the population significantly with people from all over the world. He then noted past experiences of boom-bust cycles in the United States and highlighted the Colorado Rockies and the associated negative environmental legacy impacts such as mine spoils that followed peak periods of hard rock mining. When the resource is

present and being developed, communities and regions can benefit financially and otherwise; however, when the resource is gone, the situation can become more difficult. Thus, Glatt emphasized the need for a long-term view of resource development.

Specific challenges that North Dakota regulators face in the development of oil fields are surface spills of saltwater, produced water, and oil, Glatt continued. Prior to the oil boom in the Bakken, North Dakota had about 500 reported spills a year. Once the boom started, his office received reports of five spills a day. Produced water characteristics in North Dakota typically have total dissolved solids of greater than 300,000 mg/L, chloride concentrations greater than 100,000 mg/L, and ammonia concentrations greater than 100 mg/L. He emphasized that produced water is 30 times saltier than ocean water and when produced water is spilled, it creates major resource problems. When managed properly, produced water is often injected into the subsurface for deep disposal with no resulting surface spill problem. With oil infrastructure, pipelines, and trucking, however, North Dakota is seeing major problems of produced water spills and the result that landscapes become marked with dead zones. To address the issue of these kinds of spills, Glatt suggested the need for a holistic approach.

Some of the present-day environmental legacy problems in North Dakota are a result of oil field development back in the 1950s, Glatt said. Environmental issues tend to be exacerbated as well productivity decreases, well operators change, and profitability declines. An opportunity exists, however, with the unconventional hydrocarbon development in the Bakken. For example, one could project 30 years into the future and begin long-term financial planning today, using some of the funds derived from current production. In this way, long-term assurance can exist to address potential future environmental issues. In the short term, upgrading infrastructure, including pipelines, monitoring construction oversight, engaging in-field inspectors, and consistent communication with land owners would be helpful. Further, the inspections of environmental clean-up sites would be useful to ensure that the work is done properly.

Glatt emphasized the importance of holding discussions in which all stakeholders, including landowners, industry representatives, and government officials, are encouraged to provide input. He described the evolution of these relationships through a series of meetings held in North Dakota in which few people spoke at an initial gathering but which led, by the fifth meeting, to stakeholders devising their own collective solutions and a guidance document on how to address and clean up saltwater spills.

North Dakota has also established a legacy fund to help mitigate negative environmental impacts from development of oil fields. The fund is financed both by monies generated from penalties incurred by the industry and some additional state monies. On an annual basis, the state selects five to 10 sites and cleans them up using the legacy fund. Another potential mechanism to address future environmental issues may be a bonding requirement developed through a state, federal, or other entity and upon which the relevant parties could agree when companies initially begin to develop a site, Glatt said.

In addressing the change North Dakota has experienced since the development of the Bakken, Glatt suggested the following key approaches applied in the state to help avoid negative environmental legacy issues. These might also apply to other regions of the country undergoing development of these resources:

• Increased field presence—have inspectors who meet and speak directly with landowners;
• Increased industry, federal, local, private landowner and state communication, cooperation, and education—everyone has to work together;
• Data availability and transparency—make data available and accessible to everyone;

• Provision of a safety net before cessation of oil and gas resources development—put provisions in place to be able to take the landscape back to agricultural or other uses after oil and gas development has ended; and
• Technology and best available science—use science and technology in collaboration with industry to help identify and address problems.

To conclude, Glatt stressed the importance of relationships between industry and the regulator. As these relationships improve, he sees enforcement actions decreasing and communication increasing, accompanied by subsequent benefits to the environment. All of this can be done safely and economically, while keeping in mind the goal of leaving a positive environmental legacy.

MODERATED DISCUSSION

A participant asked the speakers to comment on studies of past legacy impacts. For example, would it be helpful to document the coal experience in North Dakota and elsewhere? Glatt indicated that learning from past experiences with coal could be useful and cited parallels to the ways in which regulators and industry interact and the need to look at the full lifecycle of resource development through the post-production phase. Rao suggested further benefits in understanding what happens to methane that is purged from coal mines and lessons that might be applicable from the management and storage of coal fly ash in ponds. Rather than storing fly ash in ponds, states like Wisconsin are recycling fly ash in a useful way.

One participant noted the iconic interactions in North Dakota between operators and surrounding communities and asked Glatt to comment on how to minimize the impact of issues such as increased truck traffic due to the development of unconventional hydrocarbons. Glatt indicated that important conversations developed over time between regulators and company officials about how to provide workers with a good place to live through building a good community. The majority of companies want to provide a good working environment for their employees and for a strong community, he said. Rao and Glatt both then discussed the potential advantages of impact fees on resource development, with the benefits going back to the community. Ikonnikova noted that constructive dialogue between operators and communities can be improved by finding ways to ensure appropriate communication of information to meet various needs and levels of understanding.

A participant noted that culture and infrastructure change irreversibly with development of these types of resources and asked the speakers to comment upon what happens to the community when the resource is gone. Glatt suggested that culture and infrastructure are entwined in the concept of making the landscape quiet again. Ikonnikova noted that the infrastructure may remain after development and that communities may thus become responsible for the infrastructure. The way in which the responsibility for the infrastructure is transferred after the resource is gone is very important and may need to be arranged at the start of these projects.

A comment from another participant related to linking some of Glatt’s observations about opportunities to connect landowners with industry and different investment strategies in Ikonnikova’s report. The participant described components of a three-year project to understand how landowners perceive the costs and benefits of energy development and indicated that a significant issue relates to the volunteer time that landowners give to participate in discussions with operators and regulators. While regulators and operators are paid employees, only some landowners are benefiting from the income associated with mineral

development and that the volunteer time given by landowners is a social cost that often is unaccounted. The participant asked Ikonnikova for any examples where long-term planning and chain of custody infrastructure issues have been integrated into investment strategies. Ikonnikova outlined one example of regional drilling where the entire community was involved. Landowners formed bargaining groups which brought forth an understanding that the community had to stand together. Such approaches can result not only in royalties to the community, but community-oriented infrastructure such as schools and hospitals, she said.

Directing a comment and question to all keynote speakers, a participant described the system used by Norway to apply their royalties from offshore oil and gas development to build a long-term wealth fund, which is one of the largest in the world. The participant then asked whether keynote speakers had discussions with political leadership on investing for the future in a similar way which would benefit subsequent generations. Glatt indicated that the North Dakota legislature examined this issue and has established a legacy fund which has put away about $3 billion. Beginning in 2018 the state can use the interest from that money on various projects. Ikonnikova shared an example from Russia where money was put away when oil prices were high although how the money will be spent and who prioritizes the spending have not been finalized. Rao outlined an example of a carbon emissions fund in Alberta, Canada where funds from a carbon tax on electricity are used to mitigate the effects of carbon emissions.

A participant asked Glatt how scientists participate in conversations between landowners, industry, and regulators. Glatt indicated that when scientists participate, they do so effectively and are viewed as non-partisan experts. He mentioned a specific case in which they asked soil scientists from North Dakota State University to talk about specific issues and those technical contributions helped move the conversation forward. Rao said that in North Carolina, scientists are often involved on specific issues such as fugitive emissions or questions about water. He also noted that scientists often have a better background in understanding the big picture, and where and how information might be applied. The public and industry may lack this perspective. Rao then commented on communicating with the public and mentioned the importance of using citizen science to engage the public. Brantley noted that citizen science is an area that needs exploring, and that it also takes time to develop. In Pennsylvania, she said, they have engaged citizens to investigate shale gas well leakage impacts on streams and have people from all over the state collecting stream data. The information is shared at an annual workshop with state entities, federal scientists, watershed groups, and the private sector in attendance.

Another participant emphasized that the actual recovery volumes of shale oil and gas from these reservoirs is very low relative to the amount initially estimated to be in place and that industry responds by drilling more wells, longer laterals, tighter cluster spacing, and more stages which are likely to create more negative environmental legacy impacts. The participant asked whether past experiences from conventional oil and gas development could be translated to unconventional development. Rao responded by illustrating examples from offshore pad drilling and batch drilling where opportunities have been realized to reduce potential environmental impacts. An offshore pad may have 15 to 20 wells and this concentration of wells presents an opportunity for centralized water treatment, he said; batch drilling offers the advantage of concentrating material handling. Ikonnikova added that while these types of technological developments can improve recovery rates for the operators, the advances can sometimes move so quickly that standards or best practices can be challenging to develop in real time. Thus, she suggested, supporting paths toward establishing positive legacies for these operations could benefit from taking time to think through new technological developments and best practices simultaneously.

The final comment raised by one of the participants related to challenges of continuing support for research. The participant indicated that his group’s reclamation-related research activities had been supported in a balanced way by industry and matching state funds, but that the decline in oil and gas prices had reduced the levels of both private sector and matching funds. Brantley indicated that this situation relates directly to the need for all sectors to communicate on ways to prioritize immediate research, development, and regulatory needs with time and available funding.