SUNOCO PIPELINE L.P. — Notice of Amendment

party submissionOfficial PDF420165021M_Operator Response to Notice_07112016.pdf#

420165021M_Closure Letter_02272017_text.pdf, page 1Official PDFCERTIFIED MAIL - RETURN RECEIPT REQUESTED February 27, 2017 Mr. David Chalson Vice President of Operations Sunoco Pipeline L.P. 4041 Market Street Aston, PA 19014 CPF 4-2016-5021M Dear Mr. Chalson: On March 2014 to December 2014, a representative of the Pipeline and Hazardous Materials Safety Administration (PHMSA) pursuant to Chapter 601 of 49 United States Code inspected Sunoco Pipeline L.P. procedures for Operations and Maintenance Plan in Sugarland, Texas. As a result of the inspection, Sunoco was issued a Notice of Amendment (NOA) on June 2, 2016, which proposed amendment of your procedures. Sunoco submitted its final amended procedures on February 13, 2017. My staff reviewed the amended procedures, and it appears that the inadequacies outlined in this Notice of Amendment have been corrected. This letter is to inform you no further action is necessary and this case is now closed. Thank you for your cooperation. Sincerely, R. M. Seeley Director, Southwest Region Pipeline and Hazardous Materials Safety Administration#

420165021M_Notice of Amendment_06022016_text.pdf, page 1Official PDFNOTICE OF AMENDMENT CERTIFIED MAIL - RETURN RECEIPT REQUESTED June 2, 2016 Mr. David Chalson Vice President of Operations Sunoco Pipeline L.P. 4041 Market Street Aston, PA 19014 CPF 4-2016-5021M Dear Mr. Chalson: On March 2014 to December 2014, a representative of the Pipeline and Hazardous Materials Safety Administration (PHMSA) pursuant to Chapter 601 of 49 United States Code inspected Sunoco Pipeline L.P. procedures for Operations and Maintenance, and Integrity Management in Sugarland, Texas. On the basis of the inspection, PHMSA has identified the apparent inadequacy found within Sunoco’s plans or procedures, as described below: 1. §195.402 Procedural manual for operations, maintenance, and emergencies. (c) Maintenance and normal operations. The manual required by paragraph (a) of this section must include procedures for the following to provide safety during maintenance and normal operations: (3) Operating, maintaining, and repairing the pipeline system in accordance with each of the requirements of this subpart and subpart H of this part.#

420165021M_Notice of Amendment_06022016_text.pdf, page 2§195.432 Inspection of in-service breakout tanks1 (a) Except for breakout tanks inspected under paragraphs (b) and (c) of this section, each operator shall, at intervals not exceeding 15 months, but at least once each calendar year, inspect each in-service breakout tank. (b) Each operator must inspect the physical integrity of in-service atmospheric and low-pressure steel aboveground breakout tanks according to API Standard 653 (incorporated by reference, see § 195.3). However, if structural conditions prevent access to the tank bottom, the bottom integrity may be assessed according to a plan included in the operations and maintenance manual under § 195.402(c)(3). 1 Since the time of this inspection, 49 C.F.R. § 195.432 was amended and took effect in March 2015. The current regulation is cited below. §195.432 Inspection of in-service breakout tanks. (a) … (b) Each operator must inspect the physical integrity of in-service atmospheric and low-pressure steel above- ground breakout tanks according to API Std 653 (except section 6.4.3, Alternative Internal Inspection Interval) (incorporated by reference, see §195.3). However, if structural conditions prevent access to the tank bottom, its integrity may be assessed according to a plan included in the operations and maintenance manual under §195.402(c)(3). The risk-based internal inspection procedures in API Std 653, section 6.4.3 cannot be used to determine the internal inspection interval. (1) Operators who established internal inspection intervals based on risk-based inspection procedures prior to March 6, 2015, must re-establish internal inspection intervals based on API Std 653, section 6.4.2 (incorporated by reference, see §195.3). (i) If the internal inspection interval was determined by the prior risk-based inspection procedure using API Std 653, section 6.4.3 and the resulting calculation exceeded 20 years, and it has been more than 20 years since an internal inspection was performed, the operator must complete a new internal inspection in accordance with §195.432(b)(1) by January 5, 2017. (ii) If the internal inspection interval was determined by the prior risk-based inspection procedure using API Std 653, section 6.4.3 and the resulting calculation was less than or equal to 20 years, and the time since the most recent internal inspection exceeds the re-established inspection interval in accordance with §195.432(b)(1), the operator must complete a new internal inspection by January 5, 2017. (iii) If the internal inspection interval was not based upon current engineering and operational information (i.e., actual corrosion rate of floor plates, actual remaining thickness of the floor plates, etc.), the operator must complete a new internal inspection by January 5, 2017, and re-establish a new internal inspection interval in accordance with §195.432(b)(1). (2) [Reserved] (c) Each operator must inspect the physical integrity of in-service steel aboveground breakout tanks built to API Std 2510 (incorporated by reference, see §195.3) according to section 6 of API Std 510 (incorporated by reference, see §195.3). Section 195.432 does not allow the use of the procedures set forth in API Standard 653, section 6.4.3, Alternative Internal Inspection Interval. Forthcoming inspections of the procedures will be based on the current regulation, cited above. 2#

420165021M_Notice of Amendment_06022016_text.pdf, page 3(c) Each operator shall inspect the physical integrity of in-service steel aboveground breakout tanks built to API Standard 2510 according to section 6 of API 510. (d) The intervals of inspection specified by documents referenced in paragraphs (b) and (c) of this section begin on May 3, 1999, or on the operator's last recorded date of the inspection, whichever is earlier. Sunoco’s DOT 195 Maintenance Manual Subpart F: Operation and Maintenance Section 195.432 Inspection of In-Service Breakout Tanks procedure does not adequately described the time intervals for performing out of service internal inspections. Sunoco’s procedure only states the out of service inspections shall be determined according to API 653 Section 6.4. Sunoco must amend their procedure to describe in detail, and specify the time intervals for performing out of service internal inspections and not just state they will follow API 653. Sunoco’s procedure also does not adequately address §195.432(b) which states if structural conditions prevent access to the tank bottom, the bottom integrity may be assessed according to a plan included in the operations and maintenance manual under §195.402(c)(3). Sunoco needs to address bottom integrity inspection plan for their tanks that have concrete liners. In the last five years, Sunoco has needed to replace five floors on tanks that had concrete liners due to internal and external corrosion on the steel bottoms. This demonstrates tanks with concrete liners are susceptible to internal and external corrosion and need to have internal inspection intervals of 10 years. 2. §195.402 Procedural manual for operations, maintenance, and emergencies. (c) (3) see above. 195.577 What must I do to alleviate interference currents. (a) For pipelines exposed to stray currents, you must have a program to identify, test for, and minimize the detrimental effects of such currents. (b) You must design and install each impressed current or galvanic anode system to minimize any adverse effects on existing adjacent metallic structures. Sunoco’s 195 Maintenance Manual, Subpart H (Corrosion Control), Section 195.577 (Interference Currents), revised on 10-31-2010 is inadequate that it does not establish a program to identify, test for, and minimize the detrimental effects of stray currents. Sunoco’s 195 Maintenance Manual, Subpart H (Corrosion Control), Section 195.577 (Interference Currents), Paragraph SPLP Requirement / Process Description (3.b.) states: “Unexpected and/or unusual variations in cathodic protection measurements encountered during normal testing will be evaluated to determine whether these test results may be caused by stray current interference. SPLP will work through corrosion coordinating committees or by direct contact with area utilities or other pipeline operators to resolve whether interference may be the 3#

420165021M_Notice of Amendment_06022016_text.pdf, page 4cause of the unexpected and/or unusual test results and to resolve the stray current interference condition, if it exists”. According to the aforementioned paragraph, Sunoco did not clarify the “Unexpected and/or unusual variations in cathodic protection measurements” in their manual. PHMSA notes that there must be a numerical threshold of Unexpected and/or unusual variations in cathodic protection measurements which triggers Sunoco to determine whether the cathodic protection measurements encountered by stray currents or not. Sunoco must revise its procedure to reflect the numerical value of Unexpected and/or unusual variations in cathodic protection measurements. 3. 195.402 Procedural manual for operations, maintenance, and emergencies. (c) (3) see above. 195.573 What must I do to monitor external corrosion control? (c) Breakout tanks. You must inspect each cathodic protection system used to control corrosion on the bottom of an aboveground breakout tank to ensure that operation and maintenance of the system are in accordance with API Recommended Practice 651. However, this inspection is not required if you note in the corrosion control procedures established under § 195.402(c)(3) why compliance with all or certain operation and maintenance provisions of API Recommended Practice 651 is not necessary for the safety of the tank. Sunoco’s 195 Maintenance Manual, Subpart H Corrosion Control, Section 195.573 Monitoring External Corrosion Control, is inadequate and lacks detail to inspect each cathodic protection system used to control corrosion on the bottom of an aboveground breakout tank to ensure that operation and maintenance of the system are in accordance with API Recommended Practice 651. The procedure also references the regulation and API 651 but does not give details and guidance on inspecting and monitoring cathodic protection for breakout tanks. Sunoco must revise its procedure to give better details and guidance on cathodic protection control for breakout tanks. 4#

420165021M_Notice of Amendment_06022016_text.pdf, page 5Response to this Notice This Notice is provided pursuant to 49 U.S.C. § 60108(a) and 49 C.F.R. § 190.237. Enclosed as part of this Notice is a document entitled Response Options for Pipeline Operators in Compliance Proceedings. Please refer to this document and note the response options. Be advised that all material you submit in response to this enforcement action is subject to being made publicly available. If you believe that any portion of your responsive material qualifies for confidential treatment under 5 U.S.C. 552(b), along with the complete original document you must provide a second copy of the document with the portions you believe qualify for confidential treatment redacted and an explanation of why you believe the redacted information qualifies for confidential treatment under 5 U.S.C. 552(b). If you do not respond within 30 days of receipt of this Notice, this constitutes a waiver of your right to contest the allegations in this Notice and authorizes the Associate Administrator for Pipeline Safety to find facts as alleged in this Notice without further notice to you and to issue a Final Order. If, after opportunity for a hearing, your plans or procedures are found inadequate as alleged in this Notice, you may be ordered to amend your plans or procedures to correct the inadequacies (49 C.F.R. § 190.237). If you are not contesting this Notice, we propose that you submit your amended procedures to my office within 30 days of receipt of this Notice. This period may be extended by written request for good cause. Once the inadequacies identified herein have been addressed in your amended procedures, this enforcement action will be closed. It is requested (not mandated) that Sunoco L.P. maintain documentation of the safety improvement costs associated with fulfilling this Notice of Amendment (preparation/revision of plans, procedures) and submit the total to R. M. Seeley, Director, Southwest Region, Pipeline and Hazardous Materials Safety Administration. In correspondence concerning this matter, please refer to CPF 4-2016-5021M and, for each document you submit, please provide a copy in electronic format whenever possible. Sincerely, R. M. Seeley Director, Southwest Region Pipeline and Hazardous Materials Safety Administration Enclosure: Response Options for Pipeline Operators in Compliance Proceedings 5#