pipeline safety: safety of gas transmission and gathering ......the rules governing pipeline safety...

U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration

Pipeline Safety: Safety of Gas Transmission and Gathering Pipelines

Draft Environmental Assessment

Docket No. PHMSA-2011-0023

March 21, 2016

Prepared for: Office of Pipeline Safety

Pipeline and Hazardous Materials Safety Administration

Prepared by: John A. Volpe National Transportation Systems Center

Office of the Assistant Secretary for Research and Technology

DRAFT EA: Pipeline Safety: Safety of Gas Transmission and Gathering Pipelines

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TABLE OF CONTENTS

TABLE OF CONTENTS .............................................................................................................................. I

LIST OF ACRONYMS ............................................................................................................................... II

1.0 SCOPE OF ANALYSIS ...................................................................................................................... 1

2.0 PURPOSE OF AND NEED FOR ACTION ...................................................................................... 1

2.1 INTRODUCTION ................................................................................................................................. 1 2.2 BACKGROUND ................................................................................................................................... 1 2.3 PURPOSE AND NEED .......................................................................................................................... 4

3.0 PROPOSED ACTION AND ALTERNATIVES............................................................................... 5

3.1 OVERVIEW OF ALTERNATIVES .......................................................................................................... 5 3.2 NO ACTION ALTERNATIVE ......................................................................................................... 6 3.3 PROPOSED ACTION ........................................................................................................................... 6

3.3.1 Integrity Management (IM) Program Process Clarifications ................................................. 6 3.3.2 Integrity Assessment and Remediation: Segments Outside HCAs .......................................... 7 3.3.3 Management of Change Implementation ................................................................................. 7 3.3.4 Expansion of Corrosion Control ............................................................................................. 7 3.3.5 Pipeline Inspection Following Extreme Events ....................................................................... 8 3.3.6 MAOP Exceedance Reports and Records Verification ........................................................... 8 3.3.7 Launcher/Receiver Pressure Relief ......................................................................................... 8 3.3.8 Repeal of the Reporting Exemption for Certain Gas Gathering Lines .................................... 9 3.3.9 Revise the Current Definition for Gas Gathering Line ........................................................... 9 3.3.10 Create a New Category of Regulated Onshore Gathering Lines Subject to Safety Regulation 10

3.4 OTHER ALTERNATIVES CONSIDERED BUT DISMISSED ........................................................11

4.0 AFFECTED ENVIRONMENT AND ENVIRONMENTAL CONSEQUENCES ........................13

4.1 AFFECTED ENVIRONMENT ................................................................................................................13 4.2 ENVIRONMENTAL CONSEQUENCES OF THE ALTERNATIVES .............................................................14

4.2.1 Proposed Action Alternative ..................................................................................................14 4.2.2 Summary of Environmental Consequences of the Proposed Action .......................................18 4.2.3 No Action Alternative .............................................................................................................19

5.0 LIST OF PREPARERS AND REVIEWERS ...................................................................................19

6.0 DECISION ABOUT THE DEGREE OF ENVIRONMENTAL IMPACT ...................................19


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LIST OF ACRONYMS

CEQ Council on Environmental Quality CFR Code of Federal Regulations DOT United States Department of Transportation EA Environmental assessment EIS Environmental impact statement FONSI Finding of no significant impact NEPA National Environmental Policy Act of 1969 NTSB National Transportation Safety Board PHMSA Pipeline and Hazardous Materials Safety Administration PIR Potential impact radius RIA Regulatory impact analysis SCC Stress corrosion cracking The Act Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 The proposed rule, the rule, Notice of proposed rulemaking (NPRM)

Pipeline Safety: Safety of Gas Transmission and Gathering Pipelines

USC United States Code


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1.0 SCOPE OF ANALYSIS 1

This draft Environmental Assessment (EA) analyzes the potential environmental 2 consequences associated with adopting PHMSA’s, proposed rule “Pipeline Safety: Safety 3 of Gas Transmission and Gathering Pipelines” (hereafter referred to as the rule, NPRM, 4 or the proposed rule). The proposed revisions in the NPRM will impact 49 CFR Parts 191 5 and 192 relative to gas transmission and gas gathering pipelines. 6 7 Section 2 of this EA provides background information and information regarding the 8 purpose and need for the rule. Section 3 describes the alternatives considered. Section 4 9 discusses the potential environmental consequences resulting from the alternatives. 10 Section 5 provides PHMSA’s preliminary finding regarding the rule’s environment 11 impact. Section 6 identifies the document's preparers and reviewers, and the references 12 consulted during the development of this document. 13 14

2.0 PURPOSE OF AND NEED FOR ACTION 15

2.1 INTRODUCTION 16

This draft EA is prepared in accordance with the National Environmental Policy Act of 17 1969 (NEPA)1, as amended, and the Council on Environmental Quality (CEQ) 18 regulations for implementing NEPA (40 CFR Parts 1500-1508). When an agency 19 anticipates that a proposed action will not have significant environmental effects, the 20 CEQ regulations provide for the preparation of an EA to determine whether to prepare an 21 environmental impact statement or finding of no significant impact (FONSI). If the EA 22 indicates that the proposed action may have significant impacts to the natural or human 23 environment, PHMSA must prepare an EIS. If the EA demonstrates that no significant 24 impacts would occur as a result of the proposed action, then PHMSA may issue a FONSI. 25 In accordance with the CEQ regulations, the EA must include brief discussions of the 26 need for the proposal, alternatives, the environmental impacts of the proposed action and 27 alternatives, and a listing agencies and persons consulted. 28

2.2 BACKGROUND 29

Under the Federal Pipeline Safety Laws, 49 U.S.C. 60101 et seq., the Secretary of 30 Transportation must prescribe minimum safety standards for pipeline transportation and 31 for pipeline facilities. The Secretary has delegated this authority to the PHMSA 32 Administrator (49 CFR 1.97(a)). 33

1 42 U.S.C 4321 et seq.


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34 Therefore, PHMSA is the federal safety agency responsible for ensuring the safe, 35 reliable, and environmentally sound operations of our nation's pipeline transportation 36 system. The rules governing pipeline safety are included in the Federal Pipeline Safety 37 Regulations (PSR) in Title 49 of the Code of Federal Regulations (CFR), Parts 190-199. 38 The PSR dictate design, construction, inspection, testing, operation, and maintenance of 39 pipeline facilities. 40 41 PHMSA is proposing changes to 49 CFR Parts 191 and 192. Part 191 describes 42 requirements on operators of gas pipelines (including gas gathering, transmission, and 43 distribution systems) for reporting of incidents, safety-related conditions, and annual 44 summary data. Part 192 prescribes a wide variety of minimum safety requirements for 45 gas gathering, transmission, and distribution lines. In the NPRM, PHMSA proposes 46 changes to certain requirements relative to gas transmission and gathering pipelines. 47 First, the rule would revise existing regulations for gas transmission pipelines currently 48 regulated by PHMSA. A transmission line is a pipeline used to transport natural gas from 49 a gathering, processing or storage facility to a processing or storage facility, large volume 50 customer, or distribution system. Second, the rule would regulate approximately 356,000 51 miles of previously unregulated gathering pipelines. Gathering lines are pipelines that 52 transport oil or natural gas from the source to a transmission line. PHMSA currently 53 regulates approximately 4 percent of onshore gas gathering pipelines, and the proposed 54 rule would result in regulating all onshore gas gathering pipelines. 55 56 On August 25, 2011, PHMSA published an Advance Notice of Proposed Rulemaking 57 (ANPRM) seeking public comment on a number of questions regarding gas transmission 58 pipelines.2 The questions presented in the ANPRM included whether PHMSA should 59 change integrity management (IM) requirements, revise the definition of a high-60 consequence area (HCA), and place additional restrictions on the use of specific pipeline 61 assessment methods. With respect to non-IM requirements, the proposed changes in the 62 ANPRM included whether revised requirements are needed on new construction or 63 existing pipelines concerning mainline valves; whether PHMSA should strengthen 64 requirements for corrosion control of steel pipelines and whether new regulations are 65 needed to govern the safety of gathering lines and underground gas storage 66 facilities. PHMSA received a total of 1,463 comments; 1,080 from industry sources 67 (trade associations/unions, pipeline operators and consultants); 316 comments from the 68 public (environmental groups, government agencies/municipalities, the National 69 Association of Pipeline Safety Representatives and individual members of the general 70

2 The ANPRM may be viewed at http://www.regulations.gov/#!docketDetail;D=PHMSA-2011-0023.


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public); and 67 general comments not directly related to the ANPRM questions or 71 categories. The comments are summarized and addressed in Section III of the NPRM. 72 73 In the NPRM, PHMSA proposes changes to certain requirements relative to gas 74 transmission and gathering pipelines. Some of the changes will apply to the integrity 75 management (IM) requirements for certain gas transmission pipelines. IM specifies how 76 pipeline operators must identify, prioritize, assess, evaluate, repair and validate the 77 integrity of gas transmission pipelines that could, in the event of a leak or failure, affect 78 High Consequence Areas (HCAs) within the United States. HCAs include certain 79 populated and occupied areas. The proposed amendments to IM include: revision of IM 80 repair criteria for pipeline segments located in high consequence areas (HCAs); adding 81 specificity to performance-based requirements related to the nature and application of 82 risk models; improving requirements for collecting, validating and integrating pipeline 83 data; strengthening requirements for applying knowledge gained through the IM 84 program; strengthening requirements on the selection and use of direct assessment 85 methods; enhancing requirements for internal corrosion and external corrosion 86 management programs; and enhancing requirements for management of change. 87 88 This NPRM also proposes changes with respect to non-IM requirements, including: 89 strengthened requirements for corrosion control of steel pipelines, including improving 90 the specificity of existing requirements; additional requirements for management of 91 change; mandatory integrity assessments; establishing repair criteria for pipeline 92 segments located in segments not located in HCAs; and requirements for verification of 93 maximum allowable operating pressure (MAOP) and for verification of pipeline material 94 for certain onshore, steel, gas transmission pipelines. 95 PHMSA also proposes modifying the regulation of onshore gas gathering lines, including 96 repealing the exemption for gas gathering line reporting requirements, repealing the use 97 of American Petroleum Institute’s Recommended Practice 80, which is currently 98 incorporated by reference for determining regulated onshore gathering lines, and 99 extending regulatory requirements to Type A lines in Class 1 locations for lines eight 100 inches or greater. 101 102 The NPRM also proposes requirements for several additional topics including: requiring 103 inspections by onshore pipeline operators of areas affected by an extreme weather event 104 such as a hurricane or flood, an earthquake, a natural disaster, or other similar event; 105 allowing extension of the seven-year reassessment interval upon written notice; adding a 106 requirement to report each exceedance of the MAOP that exceeds the build-up allowed 107 for operation of pressure-limiting or control devices; adding requirements to ensure 108 consideration of seismicity of the area in identifying and evaluating all potential threats; 109 adding safety regulations related to launchers and receivers which are used for in-line 110


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tools and incorporating consensus standards into the regulations for assessing the 111 physical condition of in-service pipelines. 112 113 These proposed changes, which include some additional topics that have arisen since 114 issuance of the ANPRM, are the subject of this EA. They are listed in Section 1.0 of this 115 EA and described in more detail in Section 3 of this EA. 116

2.3 PURPOSE AND NEED 117

The purpose of the proposed rule is to significantly increase the safe operation of gas 118 pipelines. First, PHMSA proposes to provide additional protections for any pipe 119 segment where persons are expected to be inside the pipeline potential impact radius 120 (PIR). The PIR, as defined in § 192.903, is the radius of a circle within which the 121 potential failure of a pipeline could have significant impact on people or property. 122 The remaining proposals in the NPRM are in response to statutory mandates from the 123 Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (Public Law 124 112-90 (Act)), recommendations from the National Transportation Safety Board 125 (NTSB), and one recommendation from the Government Accountability Office 126 (GAO) as listed: 127

• Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 128 129

o Section 5(e) – Allow periodic reassessments to be extended for an 130 additional six months if the operator submits sufficient justification. 131

o Section 5(f) – Expand integrity management system requirements, or 132 elements thereof, beyond high-consequence areas. 133

o Section 21 – Regulation of gas (and hazardous liquid) gathering lines 134 o Section 23 – Testing regulations to confirm the material strength of 135

previously untested natural gas transmission pipelines 136 o Section 29 – Consider seismicity when evaluating pipeline threats 137

138 • NTSB Recommendations (http://phmsa.dot.gov/pipeline/regs/ntsb/open) 139

140 o P-11-14 – Recommendation to PHMSA to amend 49 CFR 192.619(c) to 141

repeal exemptions for older pipe and require that all gas transmission 142 pipelines constructed before 1970 be subjected to a hydrostatic pressure 143 test that incorporates a spike test. A spike test is a type of hydrostatic 144 pressure test that utilizes a higher pressure over shorter period of time than 145 a standard hydrostatic pressure test. 146

o P-11-15 – Recommendation to PHMSA to amend 49 CFR Part 192 so that 147 manufacturing- and construction-related defects can only be considered 148 stable if a gas pipeline has been subjected to a post-construction 149 hydrostatic pressure test of at least 1.25 times the MAOP. 150

o P-11-17 – Recommendation to PHMSA to require all natural gas 151 transmission pipelines be configured to accommodate in-line inspection 152 tools, with priority given to older pipelines. 153


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o P-11-19 – Recommendation to PHMSA to develop and implement 154 standards for integrity management and other performance-based safety 155 programs that require operators to regularly assess the effectiveness of 156 their programs. 157

o P-12-3 – Recommendation to PHMSA to revise 49 CFR 195.452 to 158 address engineering assessment, assessment methods, excavation criteria, 159 pressure restriction limits, and acceptable methods for determining crack 160 growth for crack defects in steel pipe. 161

o P-14-1 – Recommendation to PHMSA to revise 49 CFR 192.903, Subpart 162 O, to add principal arterial roadways to the list of “identified sites” that 163 establish a high consequence area. 164 165

• Government Accountability Office Report 166 167

o GAO-14-667, Department of Transportation Is Taking Actions to 168 Address Rail Safety, but Additional Actions Are Needed to Improve 169 Pipeline Safety, August 2014. 170

171 172 173

3.0 PROPOSED ACTION AND ALTERNATIVES 174

3.1 OVERVIEW OF ALTERNATIVES 175

PHMSA considered two alternatives for each topic in the proposed rule: the no action 176 alternative and the proposed action, a set of revisions to the Federal Pipeline Safety 177 Regulations. These alternatives are described in Sections 3.2 and 3.3, respectively. Other 178 alternatives are discussed in Section 3.4. 179

Under the no action alternative, PHMSA would not incorporate proposed 180 amendments and changes to revise the Federal Pipeline Safety Regulations. The CEQ 181 regulations for implementing NEPA require the analysis of a no action alternative, as the 182 no action alternative is used to define existing conditions of the natural and human-made 183 environments, and works as a baseline when analyzing environmental impacts of the 184 proposed action and other alternatives, if there are any. 185 186 Under the proposed action, PHMSA would address Sections 23 of the Act, clarify 187 integrity management processes and address integrity assessment for pipelines outside 188 HCAs. In addition, this action would address NTSB recommendations through 189 expansion of corrosion control and inspection of pipelines after extreme events. This 190 action would also change the MAOP exceedance reports and records verification and 191 make changes to launcher/receiver pressure relief. In order to address developments 192


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within the industry, the proposed action would also address changes in gas gathering lines 193 described in section 2.1. 194 195 For some of the topics in the rule, PHMSA considered other alternatives but eliminated 196 them from detailed analysis. These alternatives are discussed in Section 3.4. 197

3.2 NO ACTION ALTERNATIVE 198

Under this alternative, PHMSA would not modify or amend the Federal Pipeline Safety 199 Regulations. Pipeline operators would continue to be governed by the requirements of 200 the existing Federal Pipeline Safety Regulations that govern materials, design, 201 components, welding and joining, construction requirements, meters and regulators, 202 corrosion control, test requirements, uprating, operations, maintenance, personnel 203 qualification, and integrity management, but would not be subject to the new 204 requirements of this proposed rulemaking change. 205

206

3.3 PROPOSED ACTION 207

PHMSA’s proposed action is a set of amendments and editorial changes to the Federal 208 Pipeline Safety Regulations, which are summarized in the sections below. A more 209 detailed description of these changes can be found in the NPRM. The changes described 210 below in Sections 3.3.1 through 3.3.7 would apply to gas transmission pipelines, and 211 Section 3.3.8 describes proposed changes that would apply to gas gathering pipelines. 212

3.3.1 Integrity Management (IM) Program Process Clarifications 213

Subpart O of 49 CFR Part 192 prescribes requirements for managing pipeline integrity in 214 defined HCAs. It requires that integrity management programs for covered pipeline 215 segments identify potential threats to pipeline integrity and use the threat identification in 216 the integrity programs. Included within this performance-based process are requirements 217 to collect data for analysis, and perform a risk assessment. 218 219 This action would clarify IM program process requirements in the following areas: 220 management of change, threat identification, risk assessments, baseline assessments and 221 notifications for reassessment of interval extensions. In addition it would clarify (and in 222 limited cases, revise) repair criteria for remediating defects discovered in HCA segments 223 and would require notification to PHMSA within 180 days of completing an assessment, 224 if the operator cannot obtain sufficient information to determine if a condition presents a 225 potential threat to the integrity of the pipeline. 226


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3.3.2 Integrity Assessment and Remediation: Segments Outside HCAs 227

PHMSA proposes to require initial and periodic integrity assessment and remediation 228 for pipeline segments outside of HCAs; no such requirements currently exist for such 229 segments. This rule would add these requirements for the 93 percent or 280,000 230 miles of onshore gas transmission pipelines that are located in non-HCAs. Data 231 analysis requirements, assessment methods and repair criteria would be the same as 232 for segments that are located within HCAs. Repair criteria for two-year conditions in 233 non-HCAs would be the same as the one-year condition for HCAs. 234

3.3.3 Management of Change Implementation 235

PHMSA proposes to require operators to evaluate and mitigate risks during all 236 phases of the useful life of a pipeline as an integral part of managing pipeline design, 237 construction, operation, maintenance and integrity. Under this change, each operator 238 would be required to develop and follow a management of change process that 239 address technical, design, physical, environmental, procedural, operational, 240 maintenance, and organizational changes to the pipeline or processes, whether 241 permanent or temporary. 242

3.3.4 Expansion of Corrosion Control 243

The PSR currently do not include requirements related to stress corrosion cracking 244 (SCC), which is cracking induced from the combined influence of tensile stress and a 245 corrosive medium. SCC has caused numerous pipeline failures on hazardous liquids 246 pipelines, including a 2003 failure on a Kinder Morgan pipeline in Arizona, a 2004 247 failure on an Explorer Pipeline Company pipeline in Oklahoma, a 2005 failure on an 248 Enterprise Products Operating line in Missouri, and a 2008 failure on an Oneok NGL 249 Pipeline in Iowa. Therefore, PHMSA has determined that additional requirements 250 are needed in 49 CFR Part 192 Subpart I to enhance and improve internal and 251 external corrosion control programs and reduce the threats from SCC. PHMSA has 252 also determined that additional preventive and mitigation measures are needed in § 253 192.935(f) and (g) to ensure that public safety is enhanced in HCAs through greater 254 protection from the time-dependent threats of internal and external corrosion. 255

PHMSA proposes to require operators to expand their corrosion control program in 256 HCAs. Specifically, operators would be required to expand corrosion control 257 requirements in the following areas: pipe coating assessments, remedial actions for 258 external corrosion mitigation deficiencies, close interval surveys, interference current 259 remedial actions, gas stream monitoring program, and preventive and mitigation 260 measures for internal and external corrosion control. 261


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3.3.5 Pipeline Inspection Following Extreme Events 262

Currently, 49 CFR 192.613 prescribes general requirements for continuing 263 surveillance of a pipeline to determine and take appropriate actions needed due to 264 changes in the pipeline from, among other things, unusual operating and maintenance 265 conditions. 266

PHMSA has determined that additional requirements are needed to ensure that 267 operator procedures adequately address inspection of the pipeline and right-of-way 268 for “other factors affecting safety and operation” following extreme weather events, 269 man-made and natural disasters, and other similar events. Such inspections would 270 apply to both onshore and offshore pipelines and their rights-of-way. The proposed 271 rule amends 49 CFR 192.613(a) accordingly, requiring these additional inspections 272 and specifying the timeframe in which such inspections must be performed and the 273 appropriate remedial actions that must be taken to ensure safe pipeline operations. 274

This would ensure pipelines are still capable of being safely operated after these events 275 and what mitigation or corrective actions might be required to ensure continued safe 276 operation. 277

3.3.6 MAOP Exceedance Reports and Records Verification 278

Section 23 of the Act requires that operators report each exceedance of the maximum 279 allowable operating pressure (MAOP) that exceeds the build-up allowed for 280 operation of pressure-limiting or control devices. The proposed rule would codify 281 this statutory requirement by requiring the reporting of MAOP exceedances along 282 with the development of operational and maintenance procedures to assure MAOP 283 are not exceeded by the amount needed for overpressure protection. This change 284 would also include the verification of MAOP-related records. 285

3.3.7 Launcher/Receiver Pressure Relief 286

A “pig” is a generic term signifying any independent, self-contained device, tool, or 287 vehicle that is inserted into and moves through the interior of a pipeline for 288 inspecting, dimensioning, or cleaning. These tools are commonly referred to as 289 “pigs” because of the occasional squealing noises that can be heard as they travel 290 through the pipe. “Pigs” are also referred by a variety of other names based on their 291 use. These names and their use include; scrapers (used to clean pipe), spheres 292 (remove/add water for hydro testing); and smart pigs (inline inspections). A “pig” 293 can be inserted into a pipeline through a launcher/receiver and, usually, is pushed 294 through the line by the pressure of the material being transported. Based on 295 inspections and reports, it has come to PHMSA’s attention that individuals have been 296 injured, some fatally, while removing ILI tools and or devices from the 297 launcher/receiver that were still under pressure. Therefore, PHMSA has determined 298 that more explicit requirements are needed for safety when performing maintenance 299 activities that involve the launchers/receivers. Current regulations for hazardous 300


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liquid pipelines (49 CFR Part 195) have, since 1981, contained such safety 301 requirements for scraper and sphere facilities (49 CFR 195.426). However, current 302 regulations for gas pipelines (49 CFR Part 192) do not similarly require controls or 303 instrumentation to protect against inadvertent breach of system integrity due to 304 incorrect operation of launchers and receivers for inline inspection tools, scraper, and 305 sphere facilities. 306 307 PHMSA proposes in the NPRM to require any launcher or receiver for inline tools be 308 equipped with a device capable of safely relieving pressure in the barrel before 309 removal or opening of the launcher or receiver barrel closure or flange and insertion 310 or removal of inline inspection tools, scrapers, or spheres. PHMSA also proposes to 311 require the use of a suitable device to indicate that pressure has been relieved in the 312 barrel, or provide a means to prevent opening of the barrel closure or flange, or 313 prevent insertion or removal of inline inspection tools, scrapers, or spheres, if 314 pressure has not been relieved. 315

3.3.8 Repeal of the Reporting Exemption for Certain Gas Gathering Lines 316

In Section 21 of the 2011 Act, Congress required that PHMSA review its regulations for 317 gathering lines in an effort to determine their sufficiency. In responding to the mandate, 318 PHMSA determined that the collection of additional information about gathering lines is 319 necessary to study the effectiveness of safety practices on these pipelines. Under current 320 requirements, a large portion of onshore gas gathering pipelines are exempt from 321 reporting. Accordingly, the proposed rule would repeal the exemption for reporting 322 requirements for operators of unregulated onshore gas gathering lines by deleting 323 § 191.1(b)(4), adding a new § 191.1(c), and making other conforming editorial 324 amendments. This change would repeal the exemption for certain gas gathering lines for 325 the immediate notice and reporting of incidents, safety-related conditions, and annual 326 pipeline summary data and reporting into PHMSA’s National Registry of Pipeline 327 Operators. . 328

3.3.9 Revise the Current Definition for Gas Gathering Line 329

Inspection and enforcement of the current regulatory requirements for regulated gas 330 gathering lines has been hampered by the conflicting and ambiguous language of 331 API Recommended Practice (RP) 80, a complex recommended practice that can 332 produce multiple classifications for the same gathering pipeline system. PHMSA 333 has determined that API RP 80 does not provide sufficient clarity regarding the 334 identification of gas gathering lines for the purpose of determining applicability 335 under 49 CFR Parts 191 or 192. Additionally, and as recognized by multiple 336 commenters to the ANPRM, PHMSA has identified a regulatory gap that permits the 337 inadvertent misapplication or, in severe cases, the potential abuse, of the gathering 338 line designation under that recommended practice. 339


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340 The proposed rulemaking action would repeal the use of API RP 80 as the basis for 341 identifying regulated onshore gas gathering lines and would establish new definitions 342 for “onshore production facility or onshore production operation,” “gas processing 343 plant,” and “gas treatment facility,” along with a revised definition for “gathering line” 344 as the basis for determining the beginning and endpoints of each onshore gas 345 gathering line. Neither the new PHMSA definitions related to gathering lines nor the 346 gathering line category descriptions established in this proposed rule make reference 347 to API RP 80. 348

3.3.10 Create a New Category of Regulated Onshore Gathering Lines Subject 349 to Safety Regulation 350

The nature of the nation’s onshore gas gathering infrastructure has changed 351 drastically over the past several years with the extensive resurgence of oil and gas 352 production within the United States due to technological breakthroughs in extraction 353 techniques. Most recently, the continuing development of shale deposits and similar 354 tight gas production is altering not just the extent, but also the nature of the nation’s 355 gas gathering systems. New fields are being developed in new geographic areas, 356 significantly extending the reach of gas gathering lines. Of potentially more impact, 357 changes are occurring in the way that these new fields are being developed. These 358 changes are resulting in gathering lines that are larger in diameter or higher in 359 operating pressure, or both, oftentimes transporting higher throughputs of gas than 360 has been the case in more traditionally developed fields. Gathering lines are being 361 constructed to transport shale and tight gas that are as large as 36 inches in diameter 362 and with maximum operating pressures of up to 1,480 pounds per square inch (psig), 363 far exceeding the historical design and operating parameters of gathering lines. 364 Further changes and infrastructure growth are expected to continue into the 365 foreseeable future, not simply due to continued application of these new 366 technologies, but also because of continued innovations. Based on these factors, 367 PHMSA has taken a renewed look at its regulatory approach as it relates to gas 368 gathering pipelines in order to ensure that risks are being addressed appropriately. 369 PHMSA recognizes that the existing framework for regulating onshore gas gathering 370 lines may no longer be adequate. 371 372 This proposed rulemaking action would expand the amount of onshore gas gathering 373 pipelines that would be subject to PHMSA regulation. PHMSA proposes the 374 following: 375 376

i. Revise the definition of Type A regulated gas gathering pipelines 377 (to be referred to as Type A, Area 1) to include Class 1 pipelines 378 operating at greater than or equal to 20 percent specified minimum 379 yield strength (SMYS) and that are greater than or equal to 8 inches 380 diameter, and 381

382


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ii. Establish two new categories of regulated gas gathering pipelines: 383 a. Type A, Area 2, which would include Class 1 pipelines 384

operating at greater than or equal to 20 percent SMYS but 385 that are less than 8 inches diameter; 386

b. Type B, Area 3, which would include Class 1 pipelines 387 operating at less than 20 percent SMYS and Class 2 388 pipelines operating at less than 20 percent SMYS that are not 389 currently regulated under the current definition of Type B, 390 Area 2. 391

392 Approximately 356,000 miles of gathering lines that were previously not subject to 393 these reporting requirements will now become subject to either some or all of the 394 reporting requirements. The new Type A, Area 2 lines that will become subject to 395 selected safety provisions of PHMSA’s regulations will also become subject to all of 396 the reporting provisions. All of the remaining gathering lines that are not subject to 397 PHMSA’s safety provisions, however, will become subject to a lesser set of carefully 398 selected reporting provisions in order to provide PHMSA with the data it needs to 399 properly monitor and evaluate the risks and safety performance of these remaining 400 gathering lines. 401

3.4 OTHER ALTERNATIVES CONSIDERED BUT DISMISSED 402

For some of the topics addressed in the rule, PHMSA considered alternatives other 403 than the proposed action and the no action alternative. PHMSA considered three 404 types of alternatives for various topics in the rule: extending compliance deadlines, 405 partial and/or full implementation, and technical alternatives. 406 407 Extending compliance deadlines: 408 For several topics in the rule, PHMSA considered extending the deadline for 409 compliance from what is proposed in the rule. However, since the proposed 410 compliance deadlines have long lead times (up to 25 years), extending those 411 deadlines would delay achieving PHMSA’s goals and needlessly render the rule 412 ineffective during the period when compliance is delayed. In particular, delaying the 413 requirements for integrity assessment and remediation outside HCAs would reduce 414 the likelihood of discovering and remediating integrity threats before they can grow 415 large enough to result in a loss of pipeline integrity, and delaying the requirements 416 for launcher and receiver safety features would needlessly expose workers to routine 417 safety risk that should be avoided. As a result, PHMSA eliminated these alternatives 418 from further consideration because they significantly delay achieving the purpose 419 and need of improving the safety and protection of pipeline workers, the public, 420 property, and the environment. 421 422 Partial and/or full implementation 423 PHMSA considered partial and/or full implementation of the rule for two topics: 424 integrity assessments and the regulation of gas gathering lines as detailed below: 425


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426 Assessment Alternatives 427 Since the cost of the rule is highly correlated to the pipeline mileage that would be 428 required to have an integrity assessment, PHMSA evaluated: 429

• two alternative moderate consequence area (MCA) definitions, which would 430 reduce the estimated mileages. 431

• expanding HCAs instead of creating a new MCA, and 432 • applying the MCA requirements to all non-HCA pipe. 433

Under the first alternative MCA definition, PHMSA considered a more limited definition 434 of MCAs using criteria of five buildings intended for human occupancy or five 435 persons/occupied site. PHMSA did not select this alternative because this alternative 436 would leave an estimated 11,000 miles of pipe that contained residences or occupied sites 437 inside the PIR without the additional protections afforded other segments with only 438 marginally less potential consequences. 439 440 Under the second alternative MCA definition, PHMSA considered restricting the 441 application of MCA requirements to pipe segments that are greater than or equal to 442 eight inches in diameter. PHMSA believes that exempting MCA pipe less than eight 443 inches in non-HCA Class 1 or non-HCA Class 2 would result in minimal mileage 444 reduction to the scope of the rule, because such small pipe has a very small PIR. In 445 addition, the statutory mandate to verify MAOP for any pipe in HCA/Class 3/Class 4 446 locations would still apply to the smaller pipe sizes. Thus, pipe segments less than 447 eight inches in diameter in those locations that meet the integrity verification process 448 criteria would still require an integrity assessment. Because of this, PHMSA 449 estimated that the scope of pipelines that would require an integrity assessment 450 would be lessened by only about 4 percent. Similar to alternative 1, this alternative 451 would not achieve the policy objective because some pipe that contained residences 452 or occupied sites within its PIR (even though the PIR is small) would not have the 453 additional protections afforded other segments. For the above reasons, PHMSA did 454 not pursue this alternative. 455

456

PHMSA considered expanding the scope of High Consequence Areas (HCAs) instead of 457 creating Moderate Consequence Areas. Such an approach was contemplated in the 2011 458 ANPRM, and PHMSA received a number of comments on this approach. PHMSA 459 concluded that this approach would be counter to a graded approach based on risk (i.e., 460 risk based gradation of requirements to apply progressively more protection for 461 progressively greater consequence locations). By simply expanding HCAs, PHMSA 462 would be simply lowering the threshold for what is considered “high consequence.” 463


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PHMSA also considered expanding the proposed requirements such that they would 464 apply to all non-HCA gas transmission pipelines, but this was rejected because it would 465 dilute the impact of operator’s maintenance budgets by requiring assessments on 466 segments deemed to be in “low consequence” locations (i.e., segments without any 467 structure intended for human occupancy or occupied site inside the PIR). 468 469 Gathering Line Alternatives 470 For expansion of regulated gas gathering lines, the second most costly portion of the 471 proposed rule, PHMSA also considered applying some safety regulations to all currently 472 unregulated gas gathering lines instead of restricting the new regulations to a subset of 473 lines. This alternative would have applied risk-based rationale to apply selected 474 regulations to pipelines based on a graded approach to address risks appropriate for each 475 category of pipeline. Under this alternative, a very large amount of mileage, 195,000 476 (over 25 times more than currently regulated) would have substantial incremental 477 compliance costs. Therefore, PHMSA eliminated this alternative. 478 479 PHMSA also considered requiring partial reporting of data by operators of 480 unregulated onshore gas gathering pipelines. However, Section 21 of the Act requires 481 that PHMSA provide a report to Congress on regulation of gathering lines, and this 482 information is needed to fulfill that statutory mandate. Without reported data on a level 483 comparable to other regulated pipelines, PHMSA would not be able to adequately 484 oversee this new population of regulated pipelines or be responsive to the Congressional 485 mandate. Therefore, PHMSA eliminated this alternative from further consideration 486 because if the rule only required partial reporting by unregulated onshore gas 487 gathering lines, it would not fulfill the statutory mandate of the Act. 488 489 Technical Alternatives 490 PHMSA considered various technical alternatives to those proposed in the rule for 491 improving corrosion control, but found that the alternatives would be more expensive 492 to implement without providing any expected appreciable benefit (RIA, Sec 3.4.5.2). 493 494

4.0 AFFECTED ENVIRONMENT AND ENVIRONMENTAL 495 CONSEQUENCES 496

4.1 AFFECTED ENVIRONMENT 497

The gas pipeline infrastructure in the United States is a network of over 2.6 million miles 498 of pipelines (http://opsweb.phmsa.dot.gov/pipelineforum/facts-and-stats/incidents-and-499 mileage-report/). These pipelines exist in a variety of diverse environments, including 500 offshore locations, highly populated urban sites, and unpopulated rural areas. Therefore, 501

http://opsweb.phmsa.dot.gov/pipelineforum/facts-and-stats/incidents-and-mileage-report/

http://opsweb.phmsa.dot.gov/pipelineforum/facts-and-stats/incidents-and-mileage-report/


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the potentially affected environment would be the land area and waterways in the United 502 States where pipelines are located. 503

4.2 ENVIRONMENTAL CONSEQUENCES OF THE ALTERNATIVES 504

This section identifies the environmental effects of each alternative. These effects 505 include impacts to human health and the physical environment. The physical 506 environment includes: 507

• Air quality and climate 508 • Soils, topography and geology 509 • Water resources (floodplains, wetlands and water bodies) 510 • Historical and archeological resources 511 • Wildlife 512 • Farmland 513

4.2.1 Proposed Action Alternative 514

This section identifies the environmental effects of each component of the proposed 515 rulemaking, including potential impacts to human health and to the physical environment, 516 as defined in Section 4.2. Many of the changes included in the proposed rule build on 517 existing prudent pipeline practices and others propose entirely new practices. Either way, 518 the proposed rule would require these practices. 519 520 The proposed rule would impose testing or inspections that could identify conditions in 521 existing pipelines that require preventative maintenance activities. These maintenance 522 activities that occur in response to testing or inspection results, could lead to more 523 excavations. While pipeline operators typically adhere to certain practices to minimize or 524 mitigate environmental damage during excavation, these activities result in ground 525 disturbance that has the potential to cause sedimentation into adjacent wetlands and 526 waterways.3 This could reduce water quality and diminish aquatic habitat. In addition, 527 disturbance to vegetation could reduce available wildlife habitat for terrestrial species. 528 Excavation could also disturb historical and archaeological resources and farmland, if any 529 of these resources are present. However, impacts associated with these excavations are 530 expected to be localized to the area immediately adjacent to the work area and temporary 531 in duration. The size of these excavations would be contained within the existing right-532 3 Many state and local governments have laws and ordinances in place that apply to excavations aimed at reducing sedimentation. See for example, Virginia Erosion and Sediment Control Regulations (VESCR) VA Code Ann. § 62.1-44.15:57 and Pennsylvania Erosion and Sediment Control Regulations, 25 PA Code 86. Depending on the location and the resources impacted, The Clean Water Act (CWA) also prohibits contamination of water bodies from sedimentation. (CWA §§402404; 33 USCA §§ 1342)


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of-way. While such excavations would individually have minor localized environmental 533 impacts, they would also decrease the likelihood of pipeline failures that could result in 534 catastrophic damage to human health and the environment. Therefore, it is expected that 535 in such cases, the proposed rule would have a negligible adverse effect on the physical 536 environment and would provide overall increased protection to human health and the 537 physical environment in the form of prevention. 538 539 To the extent that the proposed rule would affect pipelines that exist in areas with 540 minority and low-income populations, the regulatory amendments would have the same 541 effect regardless of the geographic location of the pipelines. Because PHMSA believes 542 that these regulatory amendments would increase pipeline safety across systems, we 543 believe any impact to areas where environmental justice concerns exist will be positive, 544 and impacts would be the same as those in areas where environmental justice is not a 545 concern. Therefore, consistent with Executive Order 12898 and DOT Order 5610.2(a), 546 Department of Transportation Actions to Address Environmental Justice in Minority 547 Populations and Low-Income Populations, PHMSA does not anticipate that the proposed 548 rule would result in disproportionately high and adverse effects on minority or low-549 income populations. 550 551 Analysis conducted for the RIA shows that the proposed rule may result in fewer 552 accidents or incidents, which could lead to a reduction in gas released into the 553 atmosphere as greenhouse gases (GHG). The proposed changes to gas transmission lines 554 are estimated to prevent the release of up to 1,337 metric tons of carbon dioxide (CO2) 555 and 35,663 metric tons of methane per year (or 750,260 metric tons of CO2 equivalent). 556 The proposed changes to gas gathering lines are estimated to prevent the release of up to 557 491 metric tons of carbon dioxide and 5,337 metric tons of methane per year (112,568 558 metric tons of CO2 equivalent). Thus the proposed rule is expected to result in total 559 annual reductions of 1,828 metric tons of carbon dioxide and 39,000 metric tons of 560 methane (820,828 metric tons of CO2 equivalent).4 561 562 In addition to reductions in GHG release, the proposed changes are expected to enhance 563 the protection and safety of pipeline workers and the public. For example, changes 564 related to integrity management process clarifications and improvements are expected to 565 improve the safe operation and maintenance of gas transmission pipelines. Management 566 of change aspects of the rule have the benefit of ensuring that all aspects of the pipeline 567 management process appropriately assure safety and pipeline integrity. MAOP 568

4 The volume of CO2 and methane released annually are from the RIA, Tables 4.1-5B and 4.2-7. The EPA Greenhouse Gas Calculator (http://www.epa.gov/cleanenergy/energy-resources/calculator.html) was used to calculate the CO2 equivalency.


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documentation and reporting is expected to reduce the likelihood of occurrence of 569 incidents due to excessive pressure conditions. Changes to launcher and receiver safety 570 features are expected to reduce the likelihood that pipeline workers would be injured by 571 high-pressure releases from launchers and receivers. Implementation of the gas 572 transmission portion of the proposed rule could potentially result in a reduction of 573 injuries and fatalities. Incorporation of these rule changes may result in an average 574 reduction of 0.114 fatalities and 0.722 injuries per year, or a total of approximately 2 575 fatalities and 11 injuries over a 15 year period. Implementation of the gas gathering 576 portion of the proposed rule could potentially result in a reduction of injuries and 577 fatalities; incorporation of these rule changes may result in an average reduction of 0.808 578 fatalities and 1.278 injuries per year, or approximately 12 fatalities and 19 injuries over a 579 15 year period. Thus implementation of all components of this rule would result in a 580 reduction of just under 1 fatality and 2 injuries per year, or 14 fatalities and 30 injuries in 581 a 15 year period. 582 583 In this section, environmental consequences of the proposed action alternative are 584 examined for each component of the proposed rulemaking, which are described in section 585 3.2. This section describes the potential impacts of each component on public health. 586 587 Integrity Management (IM) Program Process Clarifications: This change would 588 clarify and improve requirements in the IM program through validating and integrating 589 pipeline data and expanding threat management. In addition, updated risk models and 590 calculations would be provided and required to be utilized, further improving the IM 591 program. Through clarification and updates to the existing IM program, processes aimed 592 at identifying pipeline anomalies would be more accurately and effectively implemented 593 in turn reducing the potential for pipeline failure. This change may result in preventative 594 maintenance activities that could lead to more excavations, which individually have very 595 minor and localized environmental impacts. Therefore, this change is expected to have a 596 net benefit to human health and the physical environment. 597 598 Integrity Assessment and Remediation: This change would require integrity 599 assessment and remediation for segments outside HCA’s. This change may result in 600 preventative maintenance activities that could lead to more excavations, which 601 individually have very minor and localized environmental impacts. However, this 602 change is expected to identify more pipeline anomalies, in turn reducing pipeline failure 603 that could result in damage to human health and the environment. Therefore, this change 604 would result in a net benefit to human health and the environment. 605 606 Management of Change Implementation: This change would ensure accurate 607 information is readily available regarding repairs and maintenance activities. Through 608


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this increased standard, a reduction in errors and omissions would reduce the potential for 609 pipeline failure that could result in damage to human health and the environment. 610 Therefore, it is expected that this component of the proposed rule would have a positive 611 impact to human health and the physical environment. 612 613 Expansion of Corrosion Control: Improving existing corrosion control standards and 614 requirements would reduce the potential for pipeline failure that could result in damage to 615 human health and the environment and may also reduce the need to excavate in order to 616 replace corroded pipes. Therefore, it is expected that this component of the proposed rule 617 would result in a net benefit to human health and the physical environment. 618 619 Pipeline Inspection Following Extreme Events: Requiring pipeline inspections 620 immediately following an extreme event would more readily identify pipeline damage 621 that could result in impacts to human health and the environment. This change may 622 result in maintenance activities that could lead to more excavations, which individually 623 have very minor and localized environmental impacts. Therefore, it is expected that this 624 component of the proposed rule would result in a net benefit to human health and the 625 physical environment. 626 627 MAOP Exceedance Reports and Records Verification: This component of the rule 628 would give operators and regulators a better understanding of MAOP exceedances that 629 occur. PHMSA believes this would prevent potential pipeline failure by readily 630 identifying operators with numerous MAOP exceedances. Therefore, it is expected that 631 this component of the proposed rule would have a positive impact to human health and 632 the physical environment. 633 634 Launcher/Receiver Pressure Relief: This component of the rule would ensure safety 635 protocol is followed when testing pipelines for anomalies. These requirements would 636 prevent a small release in gas and ensure operator safety from unexpected pressure 637 releases during inspection operations. This would have a positive impact to human health 638 and the environment. 639 640 Repeal of the Reporting Exemption: This change would repeal the current exemption 641 for certain gas gathering lines from incident and safety related reporting. This would 642 support the continuing evaluation of the effectiveness of safety practices and determine if 643 additional requirements are needed. This is expected to improve overall safety within the 644 pipeline industry which would have a positive impact to human health and the 645 environment. 646 647


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Revise the Current Definition for Gas Gathering Line: This change would clarify the 648 existing definition of gas gathering lines. This would address a regulatory gap that 649 permits the inadvertent misapplication or, in severe cases, the potential abuse, of the 650 gathering line designation under current practice. This change may result in 651 increased maintenance activities that could lead to more excavations, which 652 individually have minor and localized environmental impacts. However, this change 653 is expected to improve compliance, in turn reducing pipeline failure. Therefore it is 654 expected that this will result in a net benefit to human health and the environment by 655 reducing the potential for an incident. 656 657 Create a New Category of Regulated Onshore Gathering Lines: Creating a new 658 category of Type A gathering lines for high risk lines not currently regulated would 659 incorporate corrosion, damage prevention and other safety provisions in current 660 regulations. Incorporation of these new requirements may result in preventative 661 maintenance activities that could lead to more excavations, which individually have very 662 minor and localized environmental impacts. However, this change is expected to identify 663 more pipeline anomalies, in turn reducing the potential for pipeline failure that could 664 result in damage to human health and the environment. Therefore, this change would 665 result in a net benefit to human health and the environment. 666

4.2.2 Summary of Environmental Consequences of the Proposed Action 667

The proposed action alternative is not expected to result in adverse environmental 668 impacts and may result in beneficial impacts. Some elements of the proposed rulemaking 669 would impose testing or inspections that could identify conditions in existing pipelines 670 that require preventative maintenance that involves excavations. Such excavations would 671 individually have minor localized environmental impacts and would also decrease the 672 likelihood of pipeline failures that could result in catastrophic damage to human health 673 and the environment. Other components of the proposed rule would reduce the potential 674 for pipeline failure through regulations that would clarify integrity management, improve 675 safety protocols, expand corrosion control, and incorporate new onshore gas gathering 676 requirements. This would decrease the likelihood of pipeline failures that could result in 677 catastrophic damage to human health and the environment. 678 679 In summary the proposed rule would have a net positive impact to human health and the 680 physical environment through a reduction in pipeline failures and increased safety to 681 pipeline workers and the public. 682


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4.2.3 No Action Alternative 683

There are not expected to be any environmental impacts to human health, the physical 684 environment or environmental justice from the no action alternative, in which no 685 regulatory changes would occur. However, if the no action alternative were selected, the 686 changes aimed at increasing worker safety and reducing pipeline failure would not be 687 implemented or achieved. Therefore, PHMSA believes that the no action alternative 688 would be an inferior choice for environmental and human safety protection. 689 690 691

5.0 LIST OF PREPARERS AND REVIEWERS 692

This EA was prepared by the following DOT staff from PHMSA and Volpe National 693 Transportation Systems Center (No other agency assisted in the development of this 694 EA.): 695 696 Preparers Volpe Center

Preparer: Travis Mast, Biologist Reviewer: Marla Engel, MRP, AICP, Environmental Protection Specialist

PHMSA Reviewers: Amelia Samaras, PHMSA Cameron Satterthwaite, PHMSA

697

6.0 DECISION ABOUT THE DEGREE OF ENVIRONMENTAL IMPACT 698

PHMSA has preliminarily determined that the selected alternative would not have a 699 significant negative impact on the environment. In fact, PHMSA believes the proposed 700 rule would have a positive impact on the environment. PHMSA welcomes comment on 701 any of these conclusions. If it is determined that no significant impacts would occur as a 702 result of the proposed action, then the determination will result in a Finding of No 703 Significant Impact (FONSI). 704 705 References 706 NPRM (draft). Department of Transportation, Pipeline and Hazardous Materials Safety 707 Administration. Notice of Proposed Rulemaking, 49 CFR Parts 191 and 192. (2013). 708


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“Pipeline Safety: Safety of Gas Transmission and Gathering Projects.” Docket No. 709 PHMSA- 2011-0023 710 711 RIA (draft). Department of Transportation, Pipeline and Hazardous Materials Safety 712 Administration. (2013). “Regulatory Impact Analysis: Pipeline Safety: Safety of Gas 713 Transmission and Gathering Pipelines” PHMSA-2011-0023 714 715 Pacific Gas and Electric Company Natural Gas Transmission Pipeline Rupture and Fire. 716 San Bruno, California, September 9, 2010. Pipeline Accident Report NTSB/PAR-11/01. 717 (Washington, D.C.: National Transportation Safety Board, 2012). 718 http://www.ntsb.gov/doclib/reports/2011/PAR1101.pdf 719 720 Enbridge Incorporated Hazardous Liquid Pipeline Rupture and Release, Marshall, 721 Michigan, July 25, 2010, Pipeline Accident Report NTSB/PAR-12/01 (Washington, 722 D.C.: National Transportation Safety Board, 2012). 723 http://www.ntsb.gov/Investigations/AccidentReports/Pages/PAR1201.aspx 724 725

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pipeline safety: safety of gas transmission and gathering ......the rules governing pipeline safety...

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