Trends in domestic regulation of shale development
As America’s recently reinvigorated oil and gas industry wrestles with the current drop in world oil prices, U.S. regulators remain hard at work, at both the federal and state levels. While this sharp decline in oil prices has introduced significant uncertainty, as to the scale of hydraulic fracturing operations in the short term—companies have slashed their 2015 capital spending plans, and the number of active drilling rigs continues to decline—the regulatory landscape surrounding hydraulic fracturing is clearer than it has ever been, and promises to become increasingly well-defined in 2015.
Most states with shale activity now require some level of disclosure of the chemicals utilized in fracing fluids; have updated their well-cementing and construction rules; and have established drill site setback regulations, among other regulatory programs. Meanwhile, at the federal level, the U.S. Environmental Protection Agency (EPA) is moving forward with efforts to require greenhouse gas reporting for certain additional hydraulic fracturing operations, and to regulate methane emissions associated with oil and gas production. Moreover, state regulations, increasingly, are addressing concerns related to induced seismicity, protection of groundwater, and waste disposal.
GREENHOUSE GASES AND AIR EMISSIONS
As the Obama administration continues its efforts to implement the Climate Action Plan, announced in June 2013, E&P activities are receiving increased attention. A study, published in March 2014 by Purdue University and Cornell University academics, found that methane emissions associated with natural gas drilling operations in the Marcellus shale were 100 to 1,000 times greater than estimated by the EPA.
Although other studies have different and conflicting findings on this topic, the regulation of methane emissions from E&P activities has become a significant part of the Obama administration’s strategy for reducing emissions more broadly.
For example, in December 2014, the EPA proposed amending its Subpart W regulations, which address greenhouse gas reporting for petroleum and natural gas systems. Subpart W applies to hydraulic fracturing operations through reporting requirements related to gas well completions and workovers, as well as various venting and flaring techniques applicable to both oil and gas wells, subject to a 25,000-metric-ton, CO2-equivalent threshold to trigger the reporting requirement.
The EPA’s December 2014 proposal seeks to extend these reporting requirements to capture emissions from oil well completions, and workovers that use hydraulic fracturing. If finalized, as proposed, the EPA expects that 246 companies already subject to the reporting requirement would be required to report emissions from their oil well completions, and workovers that incorporate fracing. Moreover, the EPA estimates that adding oil well completions and workovers, that incorporate fracing, to the rule, would cause 50 additional companies to become subject to the reporting requirements. This is because it would bring their total reportable emissions above the 25,000-metric-ton CO2-equivalent threshold.
In addition to expanding emissions reporting requirements, the EPA has proposed following the lead of several states, which have begun to regulate methane emissions associated with fracing. At the state level, these efforts initially focused on mandating “green completions,” which require the capture of methane released as it comes to the surface with flowback water after hydraulic fracturing, or as it emerges with limiting flaring. Even where such efforts are targeted at reductions of volatile organic compounds (VOCs), substantial reductions in methane emissions often result.
The EPA took action, aimed at reducing VOC emissions, in April 2012, when it issued new rules subjecting all oil and gas to regulation under the Clean Air Act’s New Source Performance Standards, and National Emission Standards for Hazardous Air Pollutants, programs. These rules limit VOC emissions at fractured and refractured gas wells by employing various technologies, including the use of gathering lines, flares or green completions, depending on the type of well. The regulations also establish specific requirements regarding emissions from production-related wet seal and reciprocating compressors, pneumatic controllers, and storage vessels.
Despite the fact that these requirements only recently became fully implemented, and therefore the ancillary methane reductions have not yet been fully realized, the EPA also announced in January 2015 that, in a separate effort, it will issue a proposed rule in the summer of 2015, that would result in a 45% reduction in methane emissions from oil and gas production by 2025 from 2012 levels. This rulemaking effort is part of the Obama administration’s strategy, initially announced in March 2014, to reduce methane emissions.
The EPA’s proposal is expected to focus on the regulation of new, and modified, sources of methane emissions, and is likely to require green completions and limiting of flaring. Other rules, aimed at methane emissions reduction, are expected from the Bureau of Land Management to address activities on federal lands; the Pipeline and Hazardous Materials Safety Administration to address pipelines; and the Department of Energy regarding compressor efficiency. These rules also may affect E&P activities.
These federal proposals would build upon similar efforts already in place at the state level. Colorado, for instance, became the first state to regulate methane emissions from oil and gas operations in a set of rules passed by the state’s Air Quality Control Commission (AQCC) in February 2014. The AQCC’s rules require a 95% reduction of VOCs, and methane emissions at oil and gas production facilities. Colorado’s rules require green completions at all newly constructed, hydraulically fractured, or recompleted wells; require emissions reductions from centrifugal compressors; and extend VOC emissions control requirements to storage tanks utilized during the first 90 days of production.
Colorado’s rules also address fugitive emissions, which are being regulated increasingly at the state level. Colorado’s rules address fugitive emissions through various leak detection and repair requirements. For example, components at natural gas compressor stations and well production facilities must be inspected frequently, and an attempt to address any leaks requiring repair must be made within five days of detection.
Though Colorado was the first state to comprehensively regulate methane emissions from oil and gas operations, Wyoming was the first to implement fugitive emission controls on VOCs. The Air Quality Division of Wyoming’s Department of Environmental Quality updated its Oil and Gas Production Facilities Permitting Guidance in September 2013, to require operators to employ leak detection, and repair programs, in the Upper Green River basin, where ozone formation has been a problem. There, leak detection and repair requirements apply to all new and modified facilities, where fugitive emissions are greater than, or equal to, four tons per year of VOCs. Operators are required to monitor fugitive emissions on a quarterly basis, using various methods, including Method 21 (an EPA leak detection protocol), infrared cameras, audio-visual-olfactory inspections, or a combination of these approaches.
Ohio also has followed Wyoming’s lead in regulating fugitive emissions. Ohio’s revised Model General Permits for oil and gas wellsites, issued in April 2014, require more frequent leak detection inspections and quick repair of detected leaks. Unlike Wyoming, which does not limit venting or flaring, the Buckeye State’s regulations prohibit venting without a flare or condenser, and its Model General Permits require establishment of numerical emissions limitations, applicable to flares.
Perhaps the most aggressive regulation of flaring can be found in North Dakota, where producers must submit a gas capture plan with every drilling permit application, as part of a statewide flaring reduction policy. In addition, the North Dakota Industrial Commission (NDIC), Department of Mineral Resources, Oil and Gas Division, will allow all infill horizontal wells to produce at a maximum efficient rate for 90 days. After that time, the operator must either connect the well to a gathering facility, or implement remote capture processes, subject to a narrow exception for infill wells that cannot be economically connected to a gas facility.
As a result of the policy, North Dakota has intended to capture 77% of gas production in January 2015, 85% in January 2016, and 90% in October 2020. To ensure that these targets are achieved, the NDIC will compel operators to curtail production from wells found to be in violation.
INCREASED CONCERN REGARDING SEISMICITY
Another issue that has gained prominence recently, is whether operations employing hydraulic fracturing may contribute to increased seismicity in an area. Despite increasing evidence that underground wastewater injection activity—and not hydraulic fracturing—is likely behind many claims of increased seismicity, some states have taken a cautious approach. They have imposed regulatory burdens on fracing and the underground injection of wastewater in disposal wells, in connection with the potential for seismicity.
For example, in June 2013 the Illinois legislature passed its first comprehensive bill regulating fracing. It included a seismic “traffic light” system designed to address seismicity resulting from the underground injection of wastewater produced by oil and gas wells. The regulations implementing the traffic light system call for the issuance of “Yellow Light Alerts” to wells within 6 mi of the hypocenter of an earthquake of magnitude 2.0–4.0. If a well receives three Yellow Light Alerts within one year, it must reduce its injection volumes and consult with the Illinois Department of Natural Resources (IDNR). If a well receives five Yellow Light Alerts, the IDNR will issue a cessation order.
“Red Light Alerts” are issued to all wells within a 10-mi radius of an earthquake that is 4.0 or greater, and result in the issuance of a cessation order to all wells within 6 mi of the hypocenter. The regulations also give IDNR the authority to issue cessation orders under other circumstances, and allow it to require wells to implement various mitigation measures following issuance of such an order.
Oklahoma, which has also seen a rise in seismic activity and corresponding allegations of a connection to drilling activity and wastewater disposal wells, has adopted a “traffic light” system as well. Oklahoma’s system will apply to permitting decisions for proposed disposal wells, in addition to existing wells in seismically active areas. Oklahoma designated a 10-km area of interest around the epicenter of each 4.0-magnitude-or-greater earthquake.
Proposed wells are reviewed for proximity to faults, areas of past seismic activity, and other factors during the permitting process. Existing wells, in areas of interest, are subject to higher regulatory scrutiny, including potential shutdown. Finally, Oklahoma has accelerated the frequency of mechanical integrity tests for disposal wells that handle volumes of 20,000 bpd or more, requiring such inspections at least annually.
Ohio’s Department of Natural Resources (ONDR) previously implemented seismicity-related regulations for disposal wells in 2012, after a series of seismic events was tied to a well in Youngstown. The well was used for the disposal of brine and flowback water produced by fracing operations. In April 2014, Ohio regulators also raised concerns about links between fracing operations and seismicity, not just disposal wells. ODNR issued a statement saying that hydraulic fracturing activities may have increased pressure on a microfault contributing to small tremors.
The ODNR also announced stricter conditions for hydraulic fracturing in areas where seismic activity has occurred. The new permitting conditions require companies to install seismic monitors for horizontal drilling permits within 3 mi of a known fault area, or area of seismic activity greater than a 2.0 magnitude. Similar to Illinois’ approach, drillers are required to halt activity, if the monitors detect a seismic event greater than 1.0 magnitude, and to investigate the cause. If the investigation shows hydraulic fracturing had a probable connection to the seismic event, well completion operations would be suspended.
New regulations set to go into effect in California in July 2015 take a similar approach. There, operators must monitor seismic activity within an area five times the size of the stimulation area. Upon discovery of an earthquake of magnitude 2.7 or greater, the operator must notify the regulatory authorities and cease fracing activity until the California Department of Conservation’s Division of Oil, Gas and Geothermal Resources is satisfied that the fracing does not create an increased risk of seismic activity.
Following a number of minor earthquakes near oil and gas production activities in the Barnett shale region in 2013, the Texas Railroad Commission (RRC) published a new rule in November 2014, aimed at reducing seismic activity. Companies seeking permits for disposal wells must now provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells, and allow modification, suspension, or termination of permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity.
Since the beginning of the shale boom, groundwater contamination has been at the top of the list of concerns voiced by opponents of hydraulic fracturing. However, connecting fracing to groundwater contamination has proven difficult. Indeed, a number of recent scientific studies published by both academics and governmental agencies have concluded that there is no evidence of the vertical migration of gas or fluids from depth to groundwater. Nonetheless, a number of states are adding pre-drilling baseline groundwater testing to their requirements, to determine whether alleged groundwater contamination is properly attributable to oil and gas production, or is a pre-existing condition.
For example, the Wyoming Oil and Gas Conservation rules, approved in November 2013, require companies to perform baseline groundwater sampling and analysis, and monitor water sources within a half-mile radius of a proposed well. The rule went into effect in March 2014, and requires operators to submit a groundwater baseline sampling, analysis and monitoring plan with each application for a permit to drill. Operators must perform baseline water sampling and testing before commencing any drilling activities, followed by resampling and testing, in 12 to 24 months, and again in 36 to 48 months, after setting the production casing or liner.
Wyoming’s rules are perhaps the country’s most extensive with regard to groundwater monitoring, but not the only ones in place. Ohio’s regulations, which took effect in 2012, require operators to conduct pre-drilling baseline water quality sampling of all water wells within 1,500 ft of a proposed horizontal well. Similarly, Nevada issued final regulations for hydraulic fracturing activities in September 2014 that include requirements for groundwater baseline sampling and monitoring before drilling commences.
California followed suit, with its new regulations, scheduled to become effective in July 2015. There, surface property owners within 1,500 ft of the wellhead, or within 500 ft of the well’s subsurface horizontal path, may request baseline and post-stimulation testing of well and surface waters on their properties that are fit for drinking or irrigation uses. Likewise, North Carolina’s ongoing regulatory update process has included the approval of rules requiring baseline and subsequent testing of water supplies within a half-mile of a wellhead. These rules are expected to be submitted to the legislature for approval in early 2015.
Meanwhile, the EPA is continuing work on a comprehensive study of fracing’s effects on groundwater contamination, required by the 2010 Appropriations Act. It is expected that the EPA’s peer review process will conclude in 2015, although a final report is not expected until 2016.
WASTE DISPOSAL: THE NEXT BATTLE
In addition to Texas’ efforts to address seismicity concerns associated with disposal wells, more stringent waste disposal regulations and, potentially, bans are on the horizon in many states. As water use and supply concerns have sparked broader recycling efforts in producing states, non-producing states are considering bans on the disposal of hydraulic fracturing wastes in their jurisdiction.
For example, in June 2014, the governor of Connecticut signed into law a moratorium on the storage, treatment and disposal of waste from hydraulic fracturing activities through July 2017. In the meantime, the Connecticut Department of Energy and Environmental Protection will work to adopt regulations addressing disposal activities.
New Jersey and New York are both also considering a ban on the treatment of wastewater from fracing. In New Jersey, Gov. Chris Christie (Rep.) has vetoed two separate bills—the most recent in August 2014—which would have prohibited New Jersey companies from treating, discharging, disposing and storing waste from hydraulic fracturing. In New York, a non-governmental organization and state legislator teamed up in September 2014, to announce several proposed bills aimed at restricting the disposal of wastes associated with hydraulic fracturing in the state, including one calling for a complete ban on the importation of such wastes from Pennsylvania. Though that state legislator lost a re-election bid in November 2014, similar efforts are likely to continue in the state, which is increasingly averse to hydraulic fracturing, having announced in December 2014 that it will ban fracing in 2015.
On the other hand, Texas regulators have focused on recycling, exempting certain wastewater recycling activities from permitting requirements. The RRC adopted new water recycling rules in April 2013 that eliminated the need for a recycling permit, if the operator is recycling its own fluid in-lease or transferring it to another operator’s lease for recycling. The revisions streamlined the recycling rules, in an effort to encourage more recycling and decrease freshwater use. Colorado’s permitting program also establishes a non-commercial category of operators, who are allowed to recycle and reuse wastewater with fewer regulatory hurdles, and to develop waste sharing plans.
Regardless of the level of E&P activity, federal and state regulators continue to update their regulations, to address environmental concerns associated with shale development. New regulations regarding fugitive emissions, induced seismicity, and baseline groundwater monitoring, are starting to spread across more jurisdictions, while increased regulation of hydraulic fracturing wastewater disposal and recycling appears to be on the horizon.
Like oil prices, these and other regulatory initiatives can create challenges for industry participants, but are unlikely to derail the development of shale resources in the U.S. over the long term. As the industry enters 2015 with an anxious focus on current market conditions, shale oil and gas developers should continue to track these important regulatory developments, as well.
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