May 2017 Exclusive Story
Pennsylvania Positioned As Petrochemical Powerhouse
CLIFTON PARK, N.Y.–Greenhouse gas regulatory actions targeting oil and gas operations have led to complicated data collection and confusing emissions calculation requirements. These evolving GHG regulations present a compliance challenge for operators, particularly in light of increasing public and regulatory scrutiny. However, operators of petroleum and natural gas systems can avoid reporting pitfalls by implementing management systems that ensure compliance.
GHG regulation started with the 2007 Supreme Court ruling that granted the U.S. Environmental Protection Agency the authority to regulate GHGs as pollutants under the Clean Air Act. This led to EPA creating the Greenhouse Gas Reporting Program, which now targets 41 sources.
With its determination that the oil and gas industry is the second-leading emitter of GHGs, the EPA has issued a landslide of reporting requirements targeting oil and gas. Most of these are found in 40 CFR 98, Subpart W, which came into effect for reporting year 2011.
In 2014, the White House issued its Methane Climate Action Plan-Strategy to Cut Methane Emissions, which mapped the administration’s efforts to improve the measurement of GHG emissions and to reduce oil and gas methane emissions by 40-45 percent by 2025 from the base-line year of 2012. The plan directed the EPA to study additional ways to reduce methane emissions from the oil and gas sector, and if necessary, develop additional regulations by the end of 2016. After this policy directive, EPA adopted major Subpart W rule revisions in 2015, and then released a 2016 proposed revision package.
As originally promulgated, 40 CFR 98, Subpart W, defined eight segments of the petroleum and natural gas system that must monitor and report GHG emissions:
Two additional reporting segments were added to the list in 2015:
Unique And Expansive
For the oil and gas industry, the key factor that makes the application of Subpart W so unique and expansive is its definition of a “facility.” The regulation does not apply a traditional definition, as in the physical boundaries of contiguous or adjacent property. Instead, Subpart W’s definition of facility depends on the industry segment.
For example, under the natural gas distribution segment, a facility is a local distribution company as regulated by a state public utility commission; whereas the onshore production segment defines a facility as all emission sources on well pads, or associated with well pads, that are under common ownership or control and are located in a single hydrocarbon basin as defined by the American Association of Petroleum Geologists.
For example, most Marcellus production is in the Appalachian Basin Eastern Overthrust area (AAPG Basin 160-A), while most Bakken production is in the Williston Basin (AAPG Basin 395). As such, a single facility as defined by the onshore production segment could consist of hundreds, if not thousands, of individual wells!
To comply with Subpart W, thousands of datasets must be collected, including equipment lists and production/operational information. Once collected, emissions must be quantified with engineering calculations based on actual facility or field data, and using leak detection and “leaker” factors. Based on this analysis, emissions from the facility must be reported to the EPA if carbon dioxide-equivalent emissions are greater than or equal to 25,000 metric tons a year.
The EPA also amended reporting obligations to improve completeness, accuracy, transparency, and the agency’s ability to analyze emissions and understand emission trends. For example, starting in reporting year 2017 (calendar year 2016), operators also must report GHG emissions from gathering and boosting facilities, and from hydraulic fracturing completions and workovers of oil wells.
The reporting requirements sound straightforward, but the reality is that operators have their work cut out for them. They will need to do their homework to determine which operations are subject to reporting, which segment they are subject to (e.g., onshore production, or gathering and boosting), and whether any equipment is excluded. With the 2015 revision of Subpart W, most upstream operators will report in either the onshore production, or gathering and boosting segments. This is where things start getting complicated.
In regard to workovers, if applicable to the onshore production segment, starting in reporting year 2016, operators must calculate workover emissions from oil wells using the ratio of the gas flowback rate to the production flow rate collected from each well or representative parameters. If representative information is used, then the operator must subdivide the basin into a unique combination of wells within the boundaries of an individual county and subsurface completion in one or more of the following formation types: oil, high-permeability gas, shale gas, coal seam, or other tight gas reservoir rock.
If wells produce from more than one formation type, then the well is classified into only one category, based on the formation type that contributes most to production, as determined by the reporter’s engineering knowledge.
Evaluating which equipment is subject to reporting under the gathering and boosting segment is a relatively simple task. For example, gathering pipelines are excluded if they have a gas-to-oil ratio less than 300 cubic feet per barrel, or they operate under a vacuum. Since gathering and boosting facilities are defined by AAPG basins, operators need to aggregate all equipment by basin, determine each basin’s emissions, and compare each basin’s emissions to the GHG threshold. A GHG emissions report must be filed for each basin that exceeds the GHG reporting threshold.
Within a basin, operators must further categorize their well locations as either single- or multiple-well pads. This exercise is required since the onshore production segment, as defined, includes all equipment on a single well pad or associated with a single well pad used in production. This can include pipelines and separators located on the pad.
However, the gathering and boosting segment, by definition, includes gathering pipelines and other equipment used to collect liquids and/or natural gas from onshore gas or oil production wells, and to compress, condition or transport the oil/natural gas to a processing facility, transmission pipeline or distribution pipeline.
On a multiwell pad, the gathering and boosting segment begins at the point where the flow from two or more wells is combined, so pipelines and separators located downstream of these combination points are now considered part of gathering and boosting, even if they are physically located on the well pad.
Also beginning in 2016, facilities that meet the definition of the gathering and boosting segment will include stationary and portable fuel combustion equipment that may have been reported previously under Subpart C as “general stationary fuel combustion sources.” Keep in mind that because of the rule’s definitions, an operator’s combustion sources that previously were subject to Subpart C may be covered by the gathering and boosting segment starting this year. In such events, the EPA has stated that for reporting year 2015, operators should continue to report under Subpart C, but that the combustion emission should be included under gathering and boosting starting in reporting year 2016.
In January 2016, the EPA proposed additional Subpart W revisions that added new leak detection monitoring methods, leaking equipment emission factors, reporting requirements, and confidentiality determinations. The purpose of the proposed equipment leak requirements is to align leak detection methods with the recently proposed Subpart OOOOa. As such, if Subpart OOOOa (when final) is amended to incorporate new technologies or monitoring methods, Subpart W requirements will be updated automatically by reference.
The proposed leak detection provisions would be required only for sources reporting under Subpart W that are also subject to Subpart OOOOa. Facilities with a Subpart OOOOa-affected source would calculate and report their GHG emissions by using the data derived from the Subpart OOOOa fugitive emissions requirements, the Subpart W equipment leak survey calculations, and leaker emission factors. For sources reporting under Subpart W that are not subject to Subpart OOOOa (i.e., flares, dehydrators, etc.), the proposed leak detection methods could be used voluntarily.
Meeting The Challenge
Given that companies potentially have hundreds or thousands of wells, gathering lines and associated equipment, thousands of datasets need to be collected to report GHG emissions. The sheer volume of information collected not only represents emissions data, but also the potential for noncompliance.
Successful entities look at this process as an opportunity to not only track GHG emissions, but also to establish management systems to ensure compliance with the myriad operating requirements. Since each entity’s operation and size are unique, systems differ in approach, data collection, tracking and analysis.
Small producers with tens of wells such as EdgeMarc Energy, which holds 52,000 total acres under lease in Pennsylvania and Ohio and has drilled about 50 Marcellus and Utica wells to date, may be able to use a spreadsheet to collect and calculate emissions and track data. However, larger producers with hundreds or thousands of wells, transporters, and processors may require elaborate systems to accomplish the same task.
Regardless of the system size, the approach is similar and can be defined by three main steps: data collection, analysis, and reporting.
The initial step is to identify sources that can provide data to address the GHG reporting rule and demonstrate compliance. Because of an oil and gas company’s distinct function groups, it is important to first understand what information each function group collects and how it is maintained. Initially, not only may it be difficult to collect data, but the information can be conflicting, since different function groups may have similar data. Also, groups may use different terminology and units for the same data.
Therefore, one must define terms and units for data collection and transfer between departments. Potential problems typically are related to duplicate data, incorrect units, operating status, and missing components. The focus at this step is to ensure necessary data can be bridged into a centralized database that includes:
Analysis And Reporting
The collected information must be analyzed carefully for operations (e.g., sub-basins, gathering line ownership, single-versus-multiwell pad), equipment and reporting exemptions, since calculations vary from emission factors to complex equations that require a detailed understanding of equipment and its operation. The information must be quality-checked by persons knowledgeable of oil and gas operations and the latest reporting requirements to ensure it is recent and relevant, as well as within guideline values.
In addition, the tools developed to calculate GHG emissions and house data must be revised to incorporate the latest calculation methods and equipment to ensure calculations are accurate and reflect current conditions. Analysis requirements are similar for sizes of systems, and include:
As an example of identifying function groups to maintain data, the design group may maintain well pad equipment details for leakage emissions, while the production group may maintain throughput and flaring information. The objective is to identify sources that can provide the required data. It is not uncommon for these data sources to be from completely disparate systems. However, the focus at this step is to make sure data from these systems can be bridged into a centralized database.
The final step is reporting. Annual GHG reports must be submitted electronically. Once submitted, reports are evaluated by electronic validation and verification checks. If potential errors are identified, EPA will notify the reporter, who can either describe why the flagged issue is not an error, or correct the flagged issue and resubmit the report.
As the regulatory regime evolves and agencies increase enforcement, a well-thought-out program that embraces the operator’s organizational structure, operations, and field personnel, coupled with a robust tracking system, will lead to compliant operations. A system itself will not be successful without management buy-in. It is imperative for management to promote and emphasize interdepartmental collaboration to ensure information is provided to compliance staff in a timely and complete fashion.
Thomas S. Seguljic is a vice president with HRP Associates Inc. in Clifton Park, N.Y. He has more than 30 years of experience in environmental engineering consulting, including advising industrial and oil and gas clients throughout the United States. Seguljic has worked with clients to identify clean air permitting/operating requirements, and to implement compliance strategies to ensure compliance and reduce compliance costs. He holds a B.S. in mechanical engineering from Colorado State University.
John P. Martin is the founder of JPMartin Energy Strategy LLC in Saratoga Springs, N.Y. The company provides consulting, strategic planning, and policy analysis to the energy industry, academic institutions, and governments. Prior to forming the consultancy, Martin spent 17 years working on energy research and policy issues at the New York State Energy Research and Development Authority. He holds a B.S. in geology, an M.S. in economics, and a Ph.D. in environmental studies from Rensselaer Polytechnic Institute. Martin also holds an M.B.A. from Miami University.
Gary J. Stiegel Jr. is a senior permitting engineer with EdgeMarc Energy Holdings LLC in Canonsburg, Pa. He is responsible for all permitting and environmental compliance associated with the company’s exploration and production activities in Pennsylvania and Ohio. Stiegel has 13 years of experience in dealing with numerous environmental aspects of the energy sector. He holds a B.S. and an M.S. in chemical engineering from the University of Pittsburgh.