CHAPTER 2 EMISSION SOURCES AND CONTROL TECHNOLOGIES AFFECTING UPSTREAM AND MIDSTREAM OIL AND GAS

• Jurisdiction: United States

Air Quality Issues Affecting Oil, Gas, and Mining Development in the West
(Feb 2013)
CHAPTER 2
EMISSION SOURCES AND CONTROL TECHNOLOGIES AFFECTING UPSTREAM AND MIDSTREAM OIL AND GAS
Ivan L. London
Bryan Cave
Denver, Colorado
Jay Christopher
Trihydro Corporation
Denver, Colorado

IVAN L. LONDON is an associate in the Denver office of Bryan Cave LLP. He graduated from Macalester College in 2003 with a B.A. in economics, from Colorado School of Mines in 2004 with a M.S. in mineral economics, and from the University of Oklahoma College of Law in 2008 with a J.D. Since joining Brian Cave in 2011, Ivan has been primarily engaged in oil and gas environmental and other regulatory issues, including both upstream and refining.

JAY CHRISTOPHER is Business Unit Manager of Air & Process Services at Trihydro Corporation in Denver, Colorado. He has has over 35 years of energy industry environmental experience. For most of the last 20 years, Mr. Christopher has specialized in air quality issues and permitting affecting complex facility operations, with results-oriented, hands-on experience in both corporate headquarters and facility regulatory settings. He has managed the environmental compliance program and environmental professional staff for a major refinery's downstream businesses, as well as being actively involved in Denver regional air quality issues and national trade groups. With Trihydro Corporation since 2010, Mr. Christopher is responsible for Trihydro's air regulatory compliance, air permitting, and greenhouse gas services teams, where he represents clients throughput the energy industry. Trihydro's air regulatory compliance client base focuses on the upstream, midstream, and downstream oil and gas sectors, with clients throughout the United States. Prior to joining Trihydro, Mr. Christopher was the environmental team lead/environmental manager at the Suncor Energy (U.S.A.) Inc. refinery in the Denver area from 2005 - 2010. Mr. Christopher was also the senior air specialist at the refinery from 1993 - 2005. He has also worked for Conoco and Texas Eastern Corporation.

I. Introduction

Air quality has become a lightning rod for environmental regulatory action and stakeholder disputes regarding oil and gas development in the Intermountain West as well as other parts of the United States. Beginning in the 1980s, the Environmental Protection Agency (EPA) and state and local agencies have created an array of rules applicable to drilling, natural gas processing, storage, compression, dehydration, and pipeline transportation.¹ EPA recently brought air regulations further into the spotlight by promulgating new nationally applicable rules that increase both the scope and stringency of oil and gas regulation, as well as revising existing rules.² Industry groups and environmental groups are currently engaging with EPA in litigation over the new and revised rules.³ In fact, EPA recently asked the D.C. Circuit to hold the litigation in abeyance while EPA evaluates whether to reconsider the new and revised rules.⁴ While the permanent impact, indeed, the existence, of the rules is currently "up in the air," it is worth addressing at this point how these rules may affect oil and gas operations.

"[T]he Clean Air Act is a very complicated statute encompassing several distinct environmental programs."⁵ Complexities and uncertainties in the new rules may "significantly impact the planning, capital investment, and time for installation of required controls" needed to achieve compliance.⁶ Moreover, the oil and gas industry contains a variety of players, from large multinationals to very small independents, with

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varying degrees of regulatory compliance capabilities. Environmental regulations under the Clean Air Act (CAA) can be difficult to understand, and are often fraught with ambiguities. Additionally, the compliance verification requirements typically employed by EPA are generally suited for centralized operations and may create a whole new set of challenges when applied to distributed, unmanned operations at hundreds of thousands of wells and tens of thousands of well pads across the United States. It's not currently clear whether operators⁷ will be able to easily manage this evolution of the CAA regulatory framework, or whether the regulations will fundamentally restructure the way industry will need to approach every oil and gas development project.

This paper concentrates on the operational and regulatory aspects of the new and revised CAA regulations applicable to upstream and midstream operations. Section II focuses on upstream and midstream oil and gas equipment that may cause emissions. Section III covers EPA's new federal air regulations governing natural gas production and hydraulic fracturing, and discusses some of the challenges posed by EPA's approach. The discussions in Sections II and III should help operators tackle the new regulatory environment impacting operations.

II. Oil and Gas Equipment that May Cause Emissions

A. Well Sites

1. Natural Gas Well Drilling and Completions

Drilling rigs typically rely on diesel engines, which emit nitrogen oxides (NOx), hazardous air pollutants (HAPs) and volatile organic compounds (VOC).⁸ After drilling, operators increasingly use hydraulic fracturing to open up the formation containing the resource.⁹ The equipment used to fracture the well typically includes large diesel engine-powered pumps, which emit NOx, HAPs, and VOCs, to force the fracturing fluids into the formation.

Prior to turning the newly drilled and completed well to production, operators must remove accumulated fracturing fluids from the wellbore, a process referred to as "flowback." During flowback, natural gas, oil, and other liquids are expelled from the

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well, releasing VOCs and greenhouse gases (GHG).¹⁰ The composition of the flowback materials changes as the flowback progresses.¹¹ Initially, the flowback consists of water, sand, and fracturing fluids. Over time, liquid flow decreases and gas and hydrocarbon vapor flow increases.¹² As gas production begins, volumes and pressures may be inadequate or the gas may not meet specifications and must be either vented or flared. In many cases, once the gas meets minimum sales specifications, the gas is routed to a sales line. Sometimes, operators must temporarily flare the gas because the gathering pipeline and processing plant infrastructure are not present.¹³ Even after an operator connects a well to such facilities, excessive gathering system pressures may necessitate short-term flaring.¹⁴ Accordingly, several states have required the use of combustion¹⁵ or capture¹⁶ of these emissions under specified circumstances.

2. Storage Vessels

Hydrocarbon liquid and produced water storage tanks are ubiquitous in upstream and midstream operations. At or near the well site, operators separate the gas-phase materials from the liquid-phase materials, and in some cases further separate the produced water from the hydrocarbon liquids.¹⁷ Operators typically store crude oil, condensate, and produced water in fixed-roof storage tanks.¹⁸ Storage tanks may emit VOCs and GHGs through working, breathing, and flashing losses. Working and breathing losses result from vapors being pushed from the tank due to the introduction of new material to the tank (working) or daytime heating of the tank (breathing). Flashing losses result from the release of dissolved gases that occurs when the pressure of the liquid phase is reduced as it travels from the separator to the storage tank. Controls for

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tank emissions generally rely on the use of a flare or enclosed combustor, but in some cases may also include vapor recovery.¹⁹

3. Pneumatic Controllers and Pumps

Like storage vessels, natural gas-driven pneumatic controllers and chemical injection pumps are ubiquitous in oil and gas operations. Due to a lack of electrical power at most production sites, the energy required to operate a valve or pump is often derived from the pressurized gas produced by the well. Typically, these controllers and pumps vent to atmosphere, resulting in emissions of VOCs and GHGs. In some cases, emissions can be reduced by selecting "low-bleed" or "no-bleed" pneumatic controllers or by using solar-powered chemical injection pumps. The use of "low-bleed" or "no-bleed" pneumatic controllers is much more common today and significantly reduces GHG and VOC emissions.

4. Reciprocating Internal Combustion Engines

Reciprocating internal combustion engines (RICE) can be found at well sites during various phases of the life of the well. Drill rigs, workover rigs, and completion equipment all may use RICE during certain phases of the life of the well. Additionally, some locations may utilize RICE to run stationary onsite compression for gas lift systems that remove formation liquids from the wellbore or inject gas into the gathering system. For some oil producing locations, operators may use RICE to power pumping equipment or to provide additional site electricity. Finally, many upstream vapor recovery systems use small RICE-driven compressors to collect and compress recovered vapors. RICE may be a source of NOx, HAP, and VOCs emissions. EPA has promulgated many complex regulations that apply to RICE, but generally has not done so in a manner targeted specifically at the oil and gas industry.²⁰ While it is important for operators to know and understand the RICE regulations, they are beyond the scope of this paper, which focuses on new and revised regulations specific to the oil and gas industry.

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B. Gathering Facilities and Gas Plants

1. Compressors

Compressors are used to increase the pressure of the natural gas to facilitate the movement of the gas along a pipeline or through a facility. Compressors are typically not associated with a single well or well pad but instead operate as part of a gathering system, connecting many...