# East Tennessee Natural Gas — Pipeline Special Permit - **operation:** document - **citation:** PHMSA-2022-0167 - **title:** East Tennessee Natural Gas — Pipeline Special Permit - **source type:** permit - **agency:** Pipeline and Hazardous Materials Safety Administration - **status:** current - **official:** true - **published on:** 2023-03-31 - **effective on:** 2023-03-31 - **summary:** PHMSA-2022-0167, issued 2023-03-31 for East Tennessee Natural Gas's gas transmission system. - **machine formats:** - **json:** https://regulus.evalyn.ai/document/phmsa-special-permit-phmsa-2022-0167.json - **markdown:** https://regulus.evalyn.ai/document/phmsa-special-permit-phmsa-2022-0167.md - **app url:** https://regulus.evalyn.ai/document/phmsa-special-permit-phmsa-2022-0167 - **source url:** https://www.regulations.gov/docket/PHMSA-2022-0167 **body:** PHMSA pipeline special permit PHMSA-2022-0167. Operator: East Tennessee Natural Gas. System: Gas Transmission. Issue date: 2023-03-31. <<>> U.S. DEPARTMENT OF TRANSPORTATION PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION SPECIAL PERMIT – Usage of Composite Pipe Special Permit Information: Docket Number: PHMSA-2022-0167 Requested By: East Tennessee Natural Gas Transmission, LLC Operator ID#: 4070 Original Date Requested: December 2, 2022 Original Issuance Date: March 31, 2023 Effective Dates: March 31, 2023 to March 31, 2033 Code Section(s): 49 CFR 192.53(c), 192.121, 192.144, 192.149, 192.150, 192.619(a), 192.624, 192.710, and 192.714 (effective May 24, 2023) Grant of Special Permit: By this order, subject to the terms and conditions set forth below, the Pipeline and Hazardous Materials Safety Administration (PHMSA) Office of Pipeline Safety (OPS)1 grants this special permit to East Tennessee Natural Gas Transmission, LLC (ETNG)2 for a special permit segment totaling approximately 0.64 miles of 8.625-inch diameter gas transmission pipeline on Line 3320A-100 located in Roanoke County, Virginia to allow for insertion of a 7.6-inch diameter composite pipe and components. This special permit is for use of non-steel (composite) pipe in a gas transmission pipeline. Composite pipe (Smartpipe®)3 is a type of flexible reinforced thermoplastic pipe (RTP) which is not authorized for use in regulated gas transmission pipelines. 1 Throughout this special permit, the usage of “PHMSA” or “PHMSA OPS” means the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration Office of Pipeline Safety. 2 East Tennessee Natural Gas, LLC is owned by Enbridge. 3 Smartpipe® is defined as the composite pipe. Smartpipe® system is the Smartpipe® pipe and components. PHMSA-2022-0167 – East Tennessee Natural Gas, LLC Special Permit – Composite Pipe – Virginia Page 1 of 29 <<>> I. Purpose and Need: This special permit allows ETNG to maintain the current maximum allowable operating pressure (MAOP) of 813 pounds per square inch gauge (psig). This segment is non piggable, and without a special permit, it would be subject to MAOP reconfirmation under 49 CFR § 192.624 assessment requirements for Class 3 locations. This special permit application request seeks a special permit to use composite pipe in a gas transmission pipeline that operates at a MAOP of 813 psig. ETNG has requested a special permit for approximately 0.64 miles of natural gas transmission pipeline of the following 49 CFR Part 192 sections: Section Section Title Description of Waived Requirements 192.53(c) General Sub-paragraph (c) does not recognize Smartpipe® in meeting the requirements of the Subpart. 192.121 Design of Plastic Pipe The qualification requirements are specific to plastic pipe, and do not apply to flexible non-metallic Reinforced Thermoplastic Pipe (RTP) such as Smartpipe®. 192.144 Qualifying metallic components There is no listed specification for the swaged steel connectors to use with Smartpipe®. 192.149 Standard fittings There is no listed specification for Smartpipe® connectors. 192.150 Passage of internal inspection devices There are presently no ILI tools for composite pipe systems since the internal wall of the composite is thermoplastic instead of steel. 192.619(a) Maximum allowable operating pressure: Steel or plastic pipelines This section does not provide a design formula for RTP. 192.624 Maximum allowable operating pressure reconfirmation: Onshore steel transmission pipelines The MAOP reconfirmation requirements do not expressly contemplate the installation of composite RTP. 192.710 Transmission lines: Assessments outside of high consequence areas The assessment requirements are specific to onshore steel transmission pipelines and do not expressly contemplate assessment of pipelines comprised of composite RTP. 192.714 (effective May 24, 2023)4 Transmission lines: Repair criteria for onshore transmission pipelines The repair requirements are specific to onshore steel transmission pipelines and do not expressly contemplate assessment of pipelines comprised of composite RTP. 4 Final Rule, Safety of Gas Transmission Pipelines: Repair Criteria, Integrity Management Improvements, Cathodic Protection, Management of Changes, and Other Related Amendments, 87 Fed. Reg. 522245 (Aug. 24, 2022) (with an effective date of May 24, 2023). PHMSA-2022-0167 – East Tennessee Natural Gas, LLC Special Permit – Composite Pipe – Virginia Page 2 of 29 <<>> Special Permit Segment: This special permit pertains to the specified special permit segment defined in Table 1 – Special Permit Segment and is identified using the ETNG survey station (SS). The special permit segment is defined as the Smartpipe®, fittings, monitoring devices, and related facilities to be installed to comply with the special permit conditions. Table 1 – Special Permit Segment Start End Outside Diameter Line Name Length (feet) Survey Survey County, No. Year Seam MAOP Station Station State Dwellings Installed Type (psig) (inches) (SS) (SS) 8.625 RURA-ELON – Line 3320A-100 3,403 0+00 34+03 Roanoke, VA 6 1965 ERW 813 Note: ERW is a low frequency electric resistance welded pipe longitudinal seam. Attachment A is a general map that includes the pipeline route map showing the special permit segment. The current potential impact radius (PIR) for ETNG Line 3320A-100 is 170 feet, and there are 6 dwelling units within the PIR. The MAOP of the special permit segment is 813 pounds per square inch gauge (psig), which ETNG does not propose to increase under this special permit. Thus, there will be no change to the PIR for the special permit segment. PHMSA grants this special permit based on the findings set forth in the “Final Environmental Assessment and Finding of No Significant Impact” document, which can be read in its entirety in Docket No. PHMSA-2022-0167 in the Federal Docket Management System located on the internet at www.regulations.gov. II. Conditions: PHMSA grants this special permit subject to ETNG implementing the following conditions on the special permit segment. 1) Condition 1 - Maximum Allowable Operating Pressure and General Conditions a) Maximum Allowable Operating Pressure: ETNG must continue to operate each special permit segment at or below a MAOP of 813 pounds per square inch gauge (psig). This MAOP PHMSA-2022-0167 – East Tennessee Natural Gas, LLC Special Permit – Composite Pipe – Virginia Page 3 of 29 <<>> has been established based on the pipeline facilities that connect to the special permit segment, which is ETNG’s Line 3320A-100. b) Hydrostatic Test: Prior to ETNG putting the pipe in service, the pipe, connections, and appurtenances must be field hydrostatically tested at a pressure of 1.5 times the MAOP of 813 psig (minimum test pressure of 1,220 psig) for a minimum of 12 hours with recording charts (pressure chart, temperature chart, dead weights and log, and calibration records of equipment, calibrated within 30 days of test), the results of which must be made available to the Director, PHMSA Central Region, for review, including determination parameters of an acceptable test. ETNG must compensate for temperature and elevation variations and such compensation must be documented on test records. c) General Conditions: i) The Smartpipe® in the pipeline must operate at or below a design factor of 0.449 for all Class locations and road crossings within the special permit segment. ii) Due to the composite design of Smartpipe®, Barlow’s formula in 49 CFR 192.105 cannot be used to determine the pressure rating of this material, per API 15S, Second Edition, Section 5.3.3. In this case, the 7.6-inch diameter Smartpipe® has a minimum burst pressure of 4,300 psig, which results in a maximum pressure rating of 813 psig.5 2) Condition 2 - Procedure Updates Within 90 days of the grant of the special permit, ETNG must develop and maintain procedures in accordance with 49 CFR 192.603 and 192.605 that incorporate the special permit condition requirements as follows: a) Operations and Maintenance Manual: ETNG must amend the applicable sections of its Operations and Maintenance (O&M) manual(s) and procedures to incorporate the special permit conditions, including but not limited to the following: i) ETNG must document its repair and replacement procedures and standards within the comprehensive written specifications or standards required under 49 CFR 192.303 and the O&M Procedures required in 49 CFR 192.605. 5 The 7.6-inch diameter Smartpipe® will be 6.0-inch inside diameter and 7.6-inch outside diameter with a rating of 813 psig, empty weight of 5.7 pounds per foot, maximum pipe operating temperature of 120 degrees Fahrenheit (°F), and maximum installation tension of 40,000 pounds. PHMSA-2022-0167 – East Tennessee Natural Gas, LLC Special Permit – Composite Pipe – Virginia Page 4 of 29 <<>> ii) ETNG must develop O&M Procedures based upon safe operating conditions but must hand dig for initial location of the special permit segment pipeline and associated monitoring devices or communication lines. ETNG must hand or shovel dig whenever excavation operations are within two (2) feet of the pipeline and associated monitoring devices’ communication lines. b) Integrity Management Program: i) ETNG must incorporate each special permit segment into its written integrity management program (IMP) procedures as if the special permit segment is a “covered segment” as defined in 49 CFR 192.903 and must develop and follow an integrity management (IM) program in accordance with the requirements of 49 CFR Part 192, Subpart O (except as waived or modified herein) applicable to plastic transmission pipelines including the following sections: 49 CFR 192.901, 192.917(b) through (e), 192.921(a)(2) or (a)(4), 192.935, 192.937(c)(2) or (c)(4), and 192.939(b). This includes, but is not limited to, risk assessments, regular patrolling, participation in the national one-call system, direct assessment sections for periodic testing and installation of remote-controlled valves. ii) The special permit segment must have integrity threats identified, assessed, and remediated in accordance with these special permit conditions, 49 CFR 192.917, and 49 CFR Part 192, Subpart O. iii) Any high consequence area (HCA) in a special permit segment must be assessed and remediated for threats in accordance with these special permit conditions and 49 CFR Part 192, Subpart O. iv) All permit conditions that are applicable to the special permit segment are applicable to HCAs where the HCA overlaps the special permit segment. v) The special permit segment must meet the requirements of 49 CFR 192, Subpart O, if Subpart O is more stringent than the special permit conditions. c) Damage Prevention Program: ETNG must incorporate within a special permit inspection area the applicable best practices of the Common Ground Alliance (CGA)6 in its damage prevention (DP) program. ETNG must prepare and follow a damage prevention program in 6 Common Ground Alliance. (March 2020). Best Practices Guide. Retrieved from: https://commongroundalliance.com/BPguide. PHMSA-2022-0167 – East Tennessee Natural Gas, LLC Special Permit – Composite Pipe – Virginia Page 5 of 29 <<>> accordance with 49 CFR 192.614. ETNG must make this program part of its O&M Procedures prior to placing the special permit segment in natural gas service. d) Manuals - Design, Construction, Operating, Maintenance, and Emergency Response: ETNG must submit manuals, procedures, specifications, or other documents pertaining to the Design, Construction, O&M, and Emergency Response related to the special permit segment for review by the Director, PHMSA Central Region, at least 30 days prior to operation of the special permit segment pipeline, unless otherwise indicated in writing by the Director, PHMSA Central Region. 3) Condition 3 - General and Design Requirements a) Branches: ETNG must not tap, branch, or split the special permit segment Smartpipe® without the use of the appropriate Smart Pipe Company Inc. (SPCI) manufactured fittings for the specified application. Prior to installation of a tap, branch, or split, ETNG must submit a notification to the Director, PHMSA Central Region, and receive a “no objection” letter. b) Road Crossings: Due to the nature of the installation method, all road crossings must be cased with steel pipe. Any future road crossings using Smartpipe® must have a minimum of 36- inches cover and must be cased or 49 CFR Part 192 compliant steel pipe must be installed. 4) Condition 4 - Material and Testing Requirements a) Pipe Layers: ETNG must install line pipe in the special permit segment that is comprised of high-density polyethylene (HDPE) PE4710 inner layer made from natural gas pipe grade material, which meet the material requirements of API 15S, Second Edition. All composite components must be manufactured and tested in accordance with API 15S, Second Edition. b) Regrind and Rework of Polymeric Materials: Materials used in the manufacture of the pipe installed within the special permit segment, during construction or in future repairs or replacement, may not contain any regrind or rework material. c) Outdoor Pipe Storage: ETNG must comply with API 15S, Second Edition requirements for outdoor storage and ultraviolet radiation exposure of polyethylene (PE) pipe for all Smartpipe® system materials used in the special permit segment. ETNG must document compliance with API 15S, Second Edition in its Material Specifications and O&M Procedures. d) Factory Pressure Testing: To verify the pipe produced for the special permit segment two (2) samples from beginning of production and two (2) samples from end of production must be factory pressure tested by short term burst following API 15S, Second Edition, Section 6.4.2.2 PHMSA-2022-0167 – East Tennessee Natural Gas, LLC Special Permit – Composite Pipe – Virginia Page 6 of 29 <<>> with results compared to product variant testing to qualify production parameters. ETNG must make available pressure test records demonstrating that special permit segment pipe was factory pressure tested. Such records must be traceable to line pipe, repair pipe, and replacement pipe used within the special permit segment and must include: pressure test reports, pressure testing parameters (pressure, time, procedure and/or standard number, date, etc. and test acceptance parameters), and pressure testing recorders with current calibration records for pressure test recoding equipment. ETNG must provide a certification from the pipe manufacturer that the tests were completed. ETNG must make available all pressure test records to the Director, PHMSA Central Region, prior to operation of the special permit segment upon request. e) Testing of Reinforcement Materials: Smartpipe® samples that are same design and construction as the special permit segment must be obtained from Smartpipe® inventory. The following testing must be performed: i) Conduct short-term burst testing on five (5) samples at ambient temperature per the requirements of American Petroleum Institute, API 15S, Second Edition, Section 5.3.4. ii) The reinforcement materials, prior to pipe construction, shall be destructively tested. Samples from each reinforcement material reel shall be tested for yield strength, and elongation. in accordance with American Society for Testing and Materials (ASTM), ASTM D5035. The results of the tensile properties testing must be compared to the manufacturer’s requirements for as-received reinforcement materials iii) ETNG must obtain mechanical and chemical properties test reports that certify the reinforcement material used in manufacturing the Smartpipe®. f) Elevated Temperature Testing: One (1) sample obtained from Smartpipe® inventory, of the same design and construction to be used in the special permit segment, must be subjected to elevated temperature testing per the requirements of API 15S, Second Edition, Section 5.4.3.2. g) Long-Term Integrity: In designing the pipeline, ETNG must consider and plan for all pipeline integrity risk factors, including, but not limited to: Pressure and temperature cycling; performance of multilayer Smartpipe® at minimum operating temperatures, and repairs under a range of ambient conditions; long term performance of composite material and mechanical fittings; cathodic protection of metallic appurtenances; long term performance of pipe; risk PHMSA-2022-0167 – East Tennessee Natural Gas, LLC Special Permit – Composite Pipe – Virginia Page 7 of 29 <<>> migration through damage to the pipe wall; and methods for assessment of buried or excavated pipe. i) ETNG must schedule and perform three (3) inspections during which non-destructive and destructive testing must be performed on the pipe material after installation. Nondestructive testing must focus on the composition and degradation of the pipe material and destructive testing must include a hydrotest to burst pressure. ETNG must perform these inspections and tests in years 1, 3, and 4.5 (not to exceed this timing by 90-days) after installation. ii) A Direct Assessment7 segment must be installed in such a way that simulates the condition of the special permit segment in the immediate vicinity of the operating pipeline at Milepost 0.64 on or near ETNG’s property, see Appendix A - Pipeline Overview Map. This Smartpipe® Direct Assessment segment must have 10 feet removed during the intervals defined in Condition 3(g)(i) above to be evaluated, including destructive testing. The test results must be sent to the Director, PHMSA Central Region, and posted on the docket at www.regulations.gov. (1) Each removed Direct Assessment sample must be disassembled, visually, and non- destructively inspected, as appropriate, including any indications of corrosion or slippage of the end fitting. (2) The Smartpipe® Direct Assessment sample must be burst tested per the requirements of API 15S, Second Edition, Section 6.4.2.2. iii) Perform removal, replacement, and installation of pipe and fittings, and other actions related to the removal of test segments, in accordance with the requirements of this special permit. iv) ETNG must report the results of the inspections and tests to the Director, PHMSA Central Region, within 60 days of completion of testing. v) In lieu of performing the testing requirements described in Conditions 4(g)(i) and 4(g)(ii)(1) and (2), of this special permit, and since the special permit segment will be 7 Direct Assessment Segment consists of multiple Smartpipe® samples that are from the same production run of the installed special permit segment. The Direct Assessment Segment is attached to the special permit segment and will operate at the same pressure, temperature, and flow as the special permit segment. The Direct Assessment segment can be isolated for removal of Smartpipe® samples for testing as prescribed in the special permit conditions. PHMSA-2022-0167 – East Tennessee Natural Gas, LLC Special Permit – Composite Pipe – Virginia Page 8 of 29 <<>> connected to the special permit segment installed under PHMSA-2022-0167, ETNG may use the results of the destructive and non-destructive testing to determine the long-term integrity of the pipeline. Any results from the analysis of these tests that require corrective action(s) shall be applied to the special permit segment. 5) Condition 5 - Construction Operator Qualifications a) If the performance of a construction task associated with construction or repair of the special permit segment could affect the integrity of the segment, ETNG must treat that task as a “covered task” notwithstanding the definition in 49 CFR 192.801(b), and must implement the requirements of 49 CFR Part 192, Subpart N. ETNG’s construction operator qualification (COQ) procedures, training program, and qualification tests must include detailed information on all construction-related tasks as a covered task. b) ETNG must develop and implement a COQ plan that specifically relates to construction activities for the special permit segment. The purpose of the plan must be to ensure construction personnel and operations personnel are trained. The COQ plan must be followed throughout the construction phase with respect to the following: pipe inspection, hauling and stringing, appurtenance inspection, installation of appurtenances, padding and backfilling as required, hydrostatic testing, pipe repairs made from hydrostatic testing, dewatering and purging, and inspection of work (i.e. trenching, excavating, etc.). These tasks can affect the integrity of the special permit segment and must be treated as “covered tasks.” The Smartpipe® must be installed in one continuous section. Installation and end connections systems must be completed by qualified SPCI personnel. c) ETNG must also treat in the following special permit segment tasks as covered COQ “covered tasks,” such tasks include: right-of-way soil stability determination, surveying, locating foreign lines, one call notifications, ditching or excavation, cathodic protection (CP) system surveys, mitigation, and installation, anomaly evaluations and repairs, right of way clean up (including installation of line markers), SCADA control point installation and verification, gas quality monitoring, and quality assurance monitoring. d) ETNG must have SPCI personnel on-site when initial pipeline installation is conducted. ETNG must have SPCI certified joining personnel onsite installing all SPCI end fittings. e) ETNG must develop and make available its COQ plan to the Director, PHMSA Central Region, 30-days prior to beginning construction. PHMSA-2022-0167 – East Tennessee Natural Gas, LLC Special Permit – Composite Pipe – Virginia Page 9 of 29 <<>> 6) Condition 6 - Excavation, Pipe Cover, and Damage Prevention a) Pipe - Inspection for Damage: i) ETNG must develop and implement an inspection training and qualification plan and must send the plan to the Director, PHMSA Central Region, 30 days prior to the start of construction. This plan must define the requirements and training necessary to inspect and evaluate damage to Smartpipe® and fittings. In addition, ETNG must have SPCI employees on site during any insertion activities to not only to advise on any construction related activities but to assist in inspection, evaluation, and repair of any damage indications, should they be encountered. Note: The Smartpipe® configuration referenced below has a C-formed outer cover of 25 mil (.025 inch) thick that is intended to be sacrificial during pull-in. ii) ETNG must certify and document all inspections with date, time, pipeline station, and Smartpipe® product identification number. iii) ETNG must inspect the leading 50 feet of pull-through pipe for damage. All indications of pipe damage must be evaluated and replaced or repaired as follows: (1) Prior to installation a 100-foot section (Beta) of Smartpipe® will be pulled through to verify the host pipe condition and Smartpipe® condition post pull through. If the Smartpipe® body that has a cut through the outer pipe covers greater than 75 mil (0.075 inch) and fully exposes the helical reinforcement fiber bundles, this shall be cause for further cleaning and inspection of the host pipe. A successful Beta run shall be completed before the final pull through. (2) During the Smartpipe® installation, if the Smartpipe® pipe body is cut through the outer round pipe covers greater than 75 mil (0.075 inch) in depth and greater than six inches in length or width exposing the axial reinforcement layers, continue to pull through until there is 25 feet of undamaged section. All indications of pipe damage (as described above) must be evaluated by SPCI qualified personnel and tested, replaced, or repaired as follows: (a) Any cuts greater than 100 mils (0.10 inch) of the outer pipe layers and exposing the axial fiber strength layers (pull tapes) shall be cause for burst testing a section of pull-through pipe. PHMSA-2022-0167 – East Tennessee Natural Gas, LLC Special Permit – Composite Pipe – Virginia Page 10 of 29 <<>> (i) Cut out section, remove outer cover layers for inspection, re-round section and burst test to confirm integrity of helical reinforcement and core pipe. (ii) If burst test is successful, continue termination operations. (b) Any cuts greater than 200 mils (0.200 inch) through the outer pipe layers and axial reinforcement layers and into the of the helical reinforcement fiber bundles shall be cause for rejection of pull through section. (i) Pull through additional pipe to confirm condition. (ii) If pipe does not meet the above criteria, pipe at contingency termination locations will be assessed. iv) During the pre-installation, the operator must develop procedures for internally cleaning the existing 8.625-inch diameter pipe (future casing pipe) to remove liquids and debris and to inspect the casing pipe for any hazards that could damage the Smartpipe® during the casing pull through. See Condition 6(a)(iii)(1) above for Beta section confirmation. v) Prior to insertion, each insertion section of the special permit segment must be pigged with a cleaning pig to verify the cleanness of the section. If any liquids are found as a result of this cleaning pig run, additional cleaning pig runs must be performed until no unwanted liquids are found. vi) During the insertion process, the tensile force on the Smartpipe® must be monitored by use of a calibrated dynamometer, calibrated within six (6) months of use. This tensile force shall be limited to 40,000 pounds which is 44% of the Smartpipe® rating of 90,000 pounds force. b) ETNG must develop and implement O&M Procedures and/or Construction Specifications to remove and replace any Smartpipe® with the following conditions: (1) Damage at any place that exceeds the criteria for wall damage defined in Condition 6(a)(iii)(2). (2) All Smartpipe® must be newly produced after the grant of this special permit and not obtained from inventory. (3) ETNG must not install any Smartpipe® above grade (ground). c) Other possible signs of material damage or unsoundness must be reviewed by qualified personnel, and if the integrity of the Smartpipe® is negatively affected, ETNG must remove and replace such pipe. PHMSA-2022-0167 – East Tennessee Natural Gas, LLC Special Permit – Composite Pipe – Virginia Page 11 of 29 <<>> 7) Condition 7 - Corrosion Control a) ETNG must apply cathodic protection (CP) on all buried Smartpipe® components and joints, and the existing 8.625-inch diameter steel pipe (where used as a casing for the Smartpipe®) within the special permit segment in accordance with 49 CFR Part 192 (except as waived or modified herein). i) Each Smartpipe® end fitting or fitting enclosure must be installed with an anode and CP test station. ii) ETNG must install CP test stations at each metallic end fitting or end fitting enclosure. b) ETNG must perform external corrosion control monitoring on each buried metallic fitting and the existing 8.625-inch diameter steel pipe (where used as a casing for the Smartpipe®) in accordance with 49 CFR 192.465. ETNG must perform CP monitoring at least once each calendar year, not exceeding 15 months. Corrosion control monitoring of the buried metallic fittings by a sampling basis is not permitted. i) Each Smartpipe® end fitting must be installed with a test station and anode, coated and direct buried or inside end fitting enclosure. ii) ETNG must determine the native structure-to-electrolyte potential for each buried metallic fitting prior to energizing the CP system. c) ETNG must seal the pipeline casing ends to prevent water and other debris from entering the casing annulus. 8) Condition 8 - Pressure and Temperature Control and Monitoring a) ETNG must install an annulus monitoring system (Condition 8(d) below) that will provide continuous integrity monitoring of the Smartpipe® to casing annulus. b) Over-Pressure Protection: ETNG must install over-pressure protection equipment necessary to keep the pipeline pressure from exceeding 813 psig plus allowable build-up at any time. Allowable build ups are those conditions which occur due to anomalous conditions outside of the special permit segment. Occurrences resulting in pressures exceeding 813 psig plus allowable build-up of MAOP plus 4%, must be reported to the Director, PHMSA Central Region, within 24 hours or the next business day of the occurrence for their review. c) Pressure Monitoring: ETNG must monitor operating pressures by the installation of pressure transmitters and switches in the piping system that report to the facility’s SCADA system. ETNG must monitor the special permit segment with continuous and redundant pressure PHMSA-2022-0167 – East Tennessee Natural Gas, LLC Special Permit – Composite Pipe – Virginia Page 12 of 29 <<>> transmitters and switches. ETNG must provide a means to inform operator personnel performing work on the pipeline of the pressure on the line. d) Annulus Monitoring: ETNG must install an annulus monitoring system that will provide continuous integrity monitoring of the Smartpipe® to casing annulus: i) ETNG must continuously monitor through SCADA the pressure of the annulus space between the Smartpipe® and casing along the entire special permit segment. These pressure monitoring transmitters and pressure vents must be located at MP 0.64, see Appendix A - Pipeline - Special Permit Segment Maps. ii) The annulus between Smartpipe® and casing is used to monitor casing integrity. This annulus is a pressure containing capable structure that is designed to contain pressure up to 60 psig. Outlets on the end fittings will be outfitted with the necessary tubing to attach pressure transmitters that must be incorporated into SCADA monitoring. With permeated gasses permitted to build to a predetermined level (15 to 25 psig), transmitters will be configured to alarm on indications of high or low pressure outside of the established acceptable range. Continuous pressure readings within acceptable ranges provide real time indication that several key integrity features are functioning as designed. Any breach of the casing will result in a loss in pressure indicated by the “real time” annulus monitoring. This monitoring will alert ETNG that third party damage, casing or liner failure may have occurred, allowing prompt response for further investigation. ETNG will use this monitoring capability and monitor this annular pressure with a SCADA system on a continuous 24-hour basis. iii) The Smartpipe® fittings must be designed to allow the annulus of each segment of pipe to be common with each other, so that monitoring of the annular space can be conducted at one end of the system. iv) A pressure relief valve with a 60 psig set point must be installed with annulus monitoring equipment to maintain the predetermined level of annulus pressure (15 to 25 psig). This relief and the associated annulus monitoring equipment must be located within fenced in locations at mile post 0.64. e) Gas Temperature: ETNG must continuously monitor natural gas temperature at MP 0.64, see Appendix A - Special Permit Segment Maps, in order that the pipeline is not exposed to temperatures exceeding 120 degrees Fahrenheit (°F). If the Smartpipe® is exposed to PHMSA-2022-0167 – East Tennessee Natural Gas, LLC Special Permit – Composite Pipe – Virginia Page 13 of 29 <<>> temperatures exceeding 120°F8 , ETNG must conduct an investigation to demonstrate the integrity of the special permit segment pipeline. The results must be provided to the Director, PHMSA Central Region, for their review. f) Fiber Optic Monitoring: Smartpipe® must be installed with distributed fiber optic sensors along the full length of special permit segment to monitor acoustic signatures, identifying third party intrusion and leak detection. ETNG must continuously monitor the system through SCADA. 9) Condition 9 – Mainline Valve – Monitoring and Remote Control for Ruptures: ETNG must automate mainline valves9 for closure or demonstrate capability to manually close mainline valves in accordance with the requirements of this Condition 9. A special permit segment must have upstream and downstream remote-controlled valves (RCVs) so that the distance between the valves is no greater than 20 miles.10 ETNG must automate mainline valves to close in accordance with the requirements in Condition 9 within 12 months of the grant of this special permit. The special permit segment is on a lateral line. ETNG must automate the valve at MP 0.0 for closure or demonstrate capability to manually close valve in accordance with the requirements of this Condition 9. The special permit segment must have procedures for rupture isolation as follows: a) Valve Locations: RCVs must be installed as shown in Table 2 - Valves and Lateral Locations with Isolations Methods. Each special permit segment must have telemetry connections to the ETNG supervisory control and data acquisition (SCADA) system installed. b) Remote Monitoring and Control: Each special permit segment must be controlled by a SCADA system and must be equipped for remote monitoring and control, or remote monitoring and automatic control, in accordance with 49 CFR 192.620(d)(3)(iii) and the below requirements in this Condition 9(f). 8 Smartpipe® has a maximum operating temperature of 140 degrees Fahrenheit, based on a Product Family Representative as established pursuant to API 15S, Second Edition Testing. 9 A mainline valve is a sectionalizing valve used to isolate or stop gas flow upstream or downstream along the pipeline. 10 If the distance between mainline isolation valves exceeds 20 miles, additional mainline valve(s) must be added. PHMSA-2022-0167 – East Tennessee Natural Gas, LLC Special Permit – Composite Pipe – Virginia Page 14 of 29 <<>> c) Crossover or Lateral Pipe Connection Isolation: If any crossover or lateral pipe11 connects to the isolated segment between the upstream and downstream mainline valves, the nearest valve on the crossover connection(s) or lateral(s) must be isolated such that, when all valves are closed, there is no flow path for gas to flow to the leak or rupture site (except for residual gas already in the shut-off segment). If the nearest valve for a gas receipt or delivery line to the special permit segment is not isolated, isolation valves must be installed within 12 months of the grant of this special permit.12 Valves that are in the ETNG O&M procedures as locked closed and that are only opened when manned by ETNG operating personnel do not require RCVs or ASVs for closure. d) Remote-Control Valve Status: RCVs must be constantly monitored for valve status (open, closed, or partial closed/open), upstream pressure, and downstream pressure. e) Mainline Valve Closure: Closure of the appropriate valves following a pipeline leak or rupture must occur “as soon as practicable” and must not exceed 30 minutes from the “notification of potential rupture” as defined below:13 i) “Notification of Potential Rupture” means any of the following events that involve an unintentional or uncontrolled release of a large volume of gas from a transmission pipeline: (1) A release of gas observed by or reported to ETNG (e.g., by its controller(s) in a control room, field operations personnel, nearby pipeline or utility personnel, the public, local 11 Table 2 - Valves and Lateral Locations with Isolations Methods has a listing of all lateral valves. ETNG must update Table 2 if a lateral or crossover valve (includes any blowdown valve at an isolation valve that can feed gas into the rupture isolation segment) was not identified or is added after the grant of the special permit and submit this update in accordance with Condition 13 – Annual Report. ETNG has identified that no laterals exist between isolation valves for a special permit segment. ETNG must update Table 2 - Valves and Lateral Locations with Isolations Methods if a lateral or crossover valve (includes any blowdown valve at an isolation valve that can feed gas into the rupture isolation segment) was not identified or is added after the grant of the special permit and submit this update in accordance with Condition 13 – Annual Report. 12 Gas delivery or receipt pipelines must have a shutoff valve (gate or ball valve) either at the connection between the isolation valves for a special permit segment or at the delivery or receipt meter station. Any gas delivery or receipt station over 5-miles in length that is connected between the isolation valves for a special permit segment must have a RCV or ASV within 5-miles of the pipeline tie-in. For gas delivery or receipt pipelines manual shutoff valves can be used for isolation but must be closed within 30-minutes of the pipeline leak or rupture confirmation. Check valves cannot be used for pipelines over 8-inch diameter. 13 The pipeline valve section location to be closed and isolated (if there should be a rupture) must be confirmed by ETNG through Gas Control or other field operations personnel monitoring of the appropriate pipeline pressures, pressure changes, or flow rate changes through a compressor discharge section or by location confirmation from responsible persons. PHMSA-2022-0167 – East Tennessee Natural Gas, LLC Special Permit – Composite Pipe – Virginia Page 15 of 29 <<>> responders, or public authorities) that may be representative of an unintentional or uncontrolled release event meeting paragraphs (2) or (3) of this definition; (2) ETNG observes an unanticipated or unplanned pressure loss outside of the pipeline’s normal operating pressures, as defined in ETNG’s written procedures. If ETNG establishes an unanticipated or unplanned pressure loss threshold that is greater than a 10% pressure loss, occurring within a time interval of 15 minutes or less, ETNG must document in its written procedures the need for a greater pressure-change threshold due to pipeline flow dynamics (including the pipeline operating pressure, gas flow rate or volume), that are caused by fluctuations in gas demand, gas receipts, or gas deliveries; or (3) ETNG observes an unexplained flow rate change, pressure change, equipment function, or other pipeline instrumentation indication that may be representative of an event meeting paragraph (2) of this definition. Note: Notification of potential rupture occurs when an event, as defined in this section/paragraphs (2) or (3) above, is first observed by or reported to ETNG. ii) ETNG must evaluate and identify a rupture,14 as defined above, as being either an actual leak event, rupture event, or non-rupture event in accordance with operating procedures and 49 CFR 192.615. f) Gas Control Center Monitoring: The ETNG Gas Control Center must monitor the special permit inspection area 24 hours a day, seven (7) days a week, and must confirm the existence of a leak or rupture as soon as practicable in accordance with ETNG pipeline operating procedures. g) Remote Monitoring: ETNG must maintain remote monitoring and automatic control equipment, mainline valves, mainline valve operators, and pressure sensors in accordance with 49 CFR 192.631 and 192.745. All remote monitoring and automatic control equipment, including pressure sensors, must have backup power to maintain communications and control to the ETNG Gas Control Center during power outages. 14 For all in-service and pressure test failures, ETNG must perform a root cause analysis, including examination of the failed pipe, to determine if the failure is caused by a systemic or non-systemic issue. ETNG must provide the written results of this root cause analysis to the Director, PHMSA Central Region, within 90 days of the failure and must submit a copy of the root cause analysis to the Director, PHMSA Engineering and Re - **truncated:** true - **body characters:** 97219