{"operation":"document","citation":"CPF 32021018NOA","title":"TEXAS GAS TRANSMISSION, LLC — Notice of Amendment","source_type":"enforcement","agency":"Pipeline and Hazardous Materials Safety Administration","status":"historical","official":true,"published_on":"2021-04-09","effective_on":null,"summary":"CLOSED notice of amendment citing 192.631(a)(1), 192.631(b)(1), 192.631(b)(5), 192.631(c)(1), 192.631(c)(2), 192.631(c)(5), 192.631(e)(2), 192.631(e)(4), 192.631(e)(6), 192.631(h), 192.631(h)(6).","machine_formats":{"json":"https://regulus.evalyn.ai/document/phmsa-enforcement-32021018noa.json","markdown":"https://regulus.evalyn.ai/document/phmsa-enforcement-32021018noa.md"},"app_url":"https://regulus.evalyn.ai/document/phmsa-enforcement-32021018noa","source_url":"https://primis.phmsa.dot.gov/enforcement-data/case/32021018NOA","body":"Notice of Amendment involving TEXAS GAS TRANSMISSION, LLC. PHMSA's enforcement data identifies the cited regulations as 192.631(a)(1),  192.631(b)(1),  192.631(b)(5),  192.631(c)(1),  192.631(c)(2),  192.631(c)(5),  192.631(e)(2),  192.631(e)(4),  192.631(e)(6),  192.631(h),  192.631(h)(6). The case was opened on 2021-04-09 and is reported as closed as of 2021-08-27. Open the official case record for notices, responses, orders, and the latest status.\n\nOfficial case documents:\n\n32021018NOA_Closure Letter_08272021_(20-173061).pdf: https://primis.phmsa.dot.gov/enforcement-documents/32021018NOA/32021018NOA_Closure%20Letter_08272021_(20-173061).pdf\n\n32021018NOA_Closure Letter_08272021_(20-173061)_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/32021018NOA/32021018NOA_Closure%20Letter_08272021_(20-173061)_text.pdf\n\n32021018NOA_Notice of Amendment_04092021_(20-173061).pdf: https://primis.phmsa.dot.gov/enforcement-documents/32021018NOA/32021018NOA_Notice%20of%20Amendment_04092021_(20-173061).pdf\n\n32021018NOA_Notice of Amendment_04092021_(20-173061)_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/32021018NOA/32021018NOA_Notice%20of%20Amendment_04092021_(20-173061)_text.pdf\n\n32021018NOA_Operator Response to Notice_05072021_(20-173061).pdf: https://primis.phmsa.dot.gov/enforcement-documents/32021018NOA/32021018NOA_Operator%20Response%20to%20Notice_05072021_(20-173061).pdf\n\n32021018NOA_Notice of Amendment_04092021_(20-173061)_text.pdf\n\nNOTICE OF AMENDMENT\nVIA ELECTRONIC MAIL TO: stan.horton@bwpipelines.com, dick.keyser@bwpipelines.com\nApril 9, 2021\nStanley C. Horton\nPresident, CEO\nTexas Gas Transmission, LLC\n9 Greenway Plaza, Suite 2800\nHouston, TX 77066\nCPF 3-2021-018-NOA\nDear Mr. Horton:\nFrom June 15 through June 19, 2020, a representative of the Pipeline and Hazardous Materials\nSafety Administration (PHMSA) pursuant to Chapter 601 of 49 United States Code (U.S.C.)\ninspected your subsidiary, Texas Gas Transmission, LLC’s (Texas Gas), Control Room\nManagement Program procedures and records in Owensboro, KY. Texas Gas Transmission is\nthe primary for the CRM Safety Program Relationship which supports the following OPID’s:\n31278 Gulf South Pipeline Company, LLC, 39210 Boardwalk Storage Company, LLC,\n39470 Louisiana Energy and Power Authority. The inspection was conducted remotely.\nThis Notice is in response to PHMSA’s Control Room Management (CRM) Initiative, which is a\nnational level program that includes inspectors from every region. As a result, you may have\nreceived this Notice from a different Regional Director than typical because the CRM Initiative\ninspections are currently separate from the standard inspection program. Notices and\ncorrespondence from other types of inspections will remain unchanged.\n\n\n\nOn the basis of the inspection, PHMSA has identified the apparent inadequacies found within\nTexas Gas’s plans or procedures, as described below:\n1. § 192.631 Control room management.\n(a) General.\n(1) This section applies to each operator of a pipeline facility with a controller\nworking in a control room who monitors and controls all or part of a pipeline\nfacility through a SCADA system. Each operator must have and follow written\ncontrol room management procedures that implement the requirements of this\nsection, except that for each control room where an operator's activities are limited\nto either or both of:\n(i) Distribution with less than 250,000 services, or\n(ii) Transmission without a compressor station, the operator must have and follow\nwritten procedures that implement only paragraphs (d) (regarding fatigue), (i)\n(regarding compliance validation), and (j) (regarding compliance and deviations) of\nthis section.\nTexas Gas’s Control Room Management (CRM) procedure is inadequate because it does not\nstate the criteria or process for how Texas Gas determines which facilities are control rooms, and\nwhich of those facilities in turn are required to follow written control room management\nprocedures that implement the requirements of this section. In its CRM procedure, Texas Gas\nonly provided a simple statement of which locations are control rooms, but no criteria by which\nthe control rooms are identified. There are many facilities that may have the equipment and\npersonnel that may have the ability to control the pipeline. For example, storage field or\ncompressor station SCADA operator desks and Human Machine Interface (HMI’s). These\nfacilities need to be assessed using some established criteria and determined whether or not they\nare control rooms. The process should provide a consistent method to evaluate all facilities as\nwell as clearly communicate which are control rooms and need to follow written control room\nmanagement procedures that implement the requirements of this section.\nThe CRM procedure must be amended to provide a process to evaluate facilities and determine\nwhich facilities are control rooms subject to the requirements of this section.\n2. § 192.631 Control room management.\n(a) . . . .\n(b) Roles and responsibilities. Each operator must define the roles and\nresponsibilities of a controller during normal, abnormal, and emergency operating\nconditions. To provide for a controller's prompt and appropriate response to\noperating conditions, an operator must define each of the following: Each operator\nmust define the roles and responsibilities of a controller during normal, abnormal,\nand emergency operating conditions. To provide for a controller's prompt and\nappropriate response to operating conditions, an operator must define each of the\nfollowing:\n2\n\n\n\n(1) A controller's authority and responsibility to make decisions and take actions\nduring normal operations;\nTexas Gas’s CRM procedure is inadequate because it failed to properly define the roles and\nresponsibilities of a controller during normal, abnormal, and emergency operating conditions.\nThe definitions of the various positions in the control room do not align with the requirements of\nthis section. Texas Gas employs two controllers on duty at any given time, but upon\nquestioning, it was unable to clarify which of the two controller has the authority to make\ndecisions and take actions during normal operations. Also, there is not defined criteria or an\nassessment process to determine competency in fundamental or functional knowledge, which\nincludes the controller's prompt and appropriate response to operating conditions.\nIt does state in section 3.3 that, \"the Gas Controller III and Senior Gas Controller Positions can\nserve as the Primary Controller with operator qualifications (OQ) and fundamental knowledge of\nthe applicable Boardwalk pipeline system.\" Also, in section 3.2 it states that, \"an operator\nqualified Gas Controller with a Level II designation can serve as a Primary Controller ... with\nsufficient functional knowledge to respond to abnormal and emergency operating\nconditions.\" The CRM procedure uses the words “fundamental” and “functional”\nsynonymously, yet fails to provide a definition of either. Texas Gas’s practice is to qualify the\ncontrollers in three identified covered tasks early in the training and development process. Even\nwith the OQ successfully achieved, Texas Gas does not consider the individual competent to\noperate the system, alone, without supervision or direction of a Primary or higher level\ncontroller.\nThe Gas Controller I and Gas Controller II (GCI, GC II) positions are within the controller\npromotional sequence to Primary Controller. The definition of a controller from BWP’s CRM\nprocedure is, “A qualified individual who remotely monitors and controls the safety-related\noperations of a pipeline facility via a SCADA System from a Control Room, and who has\noperational authority and accountability for the remote operational functions of the pipeline\nfacility.” A Primary Controller is defined as, “A qualified Controller designated to be\nresponsible for operational control and monitoring of BWP assets when on shift.” Along with\nthese roles, is a Secondary Controller, but there is no definition for this role. There is also Gas\nControl Management personnel who are defined to be, “Director and Managers of Gas Control\nwith established operator qualifications and functional knowledge of the applicable Boardwalk\npipeline system.” There are no definitions for Controller I or Controller II. In Section 3.2, the\nController I and II Responsibilities state that they, “serve in a junior role while obtaining\noperator qualifications and specific functional knowledge of the applicable Boardwalk pipeline\nsystem. Controllers with Level I and II designations will be assigned as a Secondary Controller\nto assist the Primary Controller.” Deciphering the definitions and comparing/contrasting them\nalong with the oral description of Roles and Responsibilities as provided by Texas Gas\nemployees during the inspection, it becomes evident that the language of the procedure is\nambiguous and creates a lack of clarity among Texas Gas personnel.\nThe intent of Texas Gas’s Control Room operations is that the Controller I and II have no\nauthority to act alone, even if they are qualified and working in the control room. So, even\nthough qualified, they are not functioning controllers. Controllers I and II must have fundamental\n3\n\n\n\nor functional knowledge in addition to OQ to be considered an independent functioning\nController. The definition of a Primary Controller does not include language that requires them\nto have fundamental or functional knowledge. During the inspection, Texas Gas personnel\nstated that to be a Primary Controller, and thus allowed to operate the console\nalone/independently, required OQ and foundational or functional knowledge. Texas Gas has no\nestablished process to define the criteria for, or assessment of, an individual’s competence in this\narea.\nThe procedure must to be amended to define with clarity what is meant by the requirement of\n\"fundamental knowledge of the applicable Boardwalk pipeline system\" in order for a controller\nto operate the system without direction or supervision. It must also be amended to delineate the\nroles and responsibilities of each controller when two are working together on a console.\n3. § 192.631 Control room management.\n(a) . . . .\n(b) Roles and responsibilities. Each operator must define the roles and\nresponsibilities of a controller during normal, abnormal, and emergency operating\nconditions. To provide for a controller's prompt and appropriate response to\noperating conditions, an operator must define each of the following:\n(1) . . . .\n(5) The roles, responsibilities and qualifications of others with the authority to\ndirect or supersede the specific technical actions of a controller.\nTexas Gas’s CRM procedure is inadequate because it does not provide details of how those\nauthorized to direct or supersede the technical actions of a controller are to implement their\nauthority. The CRM procedure does not include the conditions or rules of engagement when the\nsituation arises and a controller is superseded. Additionally, the CRM procedure does not\ninclude an avenue should the controller disagree with the actions the superseding personnel\nproposes to take. Finally, the CRM procedure does not include how the event should be\ncommunicated and documented.\nThe procedure must be amended to include the requisite conditions and rules of engagement for\nhow and when personnel can implement the authority to supersede the technical actions of a\ncontroller, as well as the method of recording the event for those authorized to direct or\nsupersede the technical actions of a controller.\n4. § 192.631 Control room management.\n(a) . . . .\n(c) Provide adequate information. Each operator must provide its controllers with\nthe information, tools, processes and procedures necessary for the controllers to\ncarry out the roles and responsibilities the operator has defined by performing each\nof the following:\n(1) Implement sections 1, 4, 8, 9, 11.1, and 11.3 of API RP 1165 (incorporated by\nreference, see § 192.7) whenever a SCADA system is added, expanded or replaced,\n4\n\n\n\nunless the operator demonstrates that certain provisions of sections 1, 4, 8, 9, 11.1,\nand 11.3 of API RP 1165 are not practical for the SCADA system used;\nTexas Gas’s CRM procedure is inadequate because it does not clearly define the types of\nchanges to the SCADA system(s) that constitute additions, expansions, or replacements. Section\n4.3 of the CRM procedure merely rephrased the language of § 192.631(c). During the\ninspection, Texas Gas personnel articulated the various conditions they considered to mean add,\nexpand or replace, but the CRM procedure did not establish these definitions or conditions in\nwriting.\nThe procedure must be amended to provide the considerations and conditions\nthat constitute additions, expansions, or replacement of a SCADA system.\n5. § 192.631 Control room management.\n(a) . . . .\n(c) Provide adequate information. Each operator must provide its controllers with\nthe information, tools, processes and procedures necessary for the controllers to\ncarry out the roles and responsibilities the operator has defined by performing each\nof the following:\n(1) . . . .\n(2) Conduct a point-to-point verification between SCADA displays and related field\nequipment when field equipment is added or moved and when other changes that\naffect pipeline safety are made to field equipment or SCADA displays;\nTexas Gas’s CRM procedure is inadequate because it did not clearly define the conditions for\nwhen field equipment is added or moved, and when other changes that affect pipeline safety are\nmade to field equipment, or how to conduct a point-to-point (P2P) of SCADA displays.\nWhile Texas Gas’s CRM procedure does state the circumstances for when a P2P should be\ncompleted, it does not define how to complete the P2P test and associated documentation. The\nlack of a standard P2P template and instruction to complete the template became evident while\nreviewing various P2P records. There was no consistency in the process.\nSection 4.4 of the CRM procedure is sparse in language and provides a reference to Texas Gas’s\n6602 Point-to-Point SCADA Verification Task List Information. Texas Gas’s 6602 is a 5-step\ntask/process that addresses, on a very high level, the requirements to complete a P2P. To assure\nthe safe operation of pipeline systems, the CRM procedure for conducting and documenting the\nP2P should include the individuals conducting the verification test, point location, tag name,\nfield end device name, HMI value/status, associated field value status, alarm limits, and the\nvalues/status when alarms are presented to the controller. It should also include verification that\nall screens presenting the values are correct, and that alarms presented with the right message,\npriority, priority color, and any other alarm characteristics, as well as any findings or\nmalfunctions identified and how they are corrected. Texas Gas’s CRM Plan and 6602 Point-to-\nPoint SCADA Verification Task List Information provided no such guidance.\n5\n\n\n\nThe procedure must to be amended to provide instructions on how to complete, accurately\ndocument, and maintain records for P2P to verify between SCADA displays and related field\nequipment when field equipment is added or moved, and when other changes that affect pipeline\nsafety are made to field equipment or SCADA displays.\n6. § 192.631 Control room management.\n(a) . . . .\n(c) Provide adequate information. Each operator must provide its controllers with\nthe information, tools, processes and procedures necessary for the controllers to\ncarry out the roles and responsibilities the operator has defined by performing each\nof the following:\n(1) . . . .\n(5) Establish and implement procedures for when a different controller assumes\nresponsibility, including the content of information to be exchanged.\nTexas Gas’s CRM procedure is inadequate because it does not require the controllers to sign and\ndate, with time, the shift change document for when a different controller assumes\nresponsibility. It also does not provide direction on the electronic process for shift turnover that\nis now in place.\nTexas Gas changed the shift turnover process from a Word Document to an online document\nusing the new SCADA system. Texas Gas did not use a separate controller log and did not\ndocument the events and actions into the shift change log that is reviewed at shift\nturnover. Section 4.7 of Texas Gas’s CRM procedure refers to Task List 6601-NG Shift\nChange-Over, each of which list items to be covered during shift change. In the word document\n(2017 & 2018), and the SCADA log (2019), Texas Gas identified these items as check boxes\nwith no back up information as to what was discussed. If a box is checked next to a particular\nitem, the assumption is that the topic was discussed, but there is no documentation or\ncommentary regarding the specifics of what information was covered and passed along. The\nprocedure does not require any documentation other than a verbal exchange. Documentation or\nwritten notation of what was shared and discussed is necessary to assure the safe operation of the\npipeline system.\nTexas Gas’s CRM procedure also does not require a signature of the shift change for the\noutgoing controller. It does require the incoming controller to initial the document, but it does\nnot require either controller to document the time the shift turnover occurred. The SCADA\nonline form captures this, but it is still a manual entry via a select button and then entry of who\nwere the shifting controllers. The procedure still appears to provide direction to the paper\nprocess and not the electronic process.\nThe Texas Gas CRM procedures must be amended to address the new online process, direct the\ncontrollers to complete the signature and dating process, and better capture topics that were\ndiscussed with sufficient detail for reference.\n6\n\n\n\n7. § 192.631 Control room management.\n(a) General.\n(1) This section applies to each operator of a pipeline facility with a controller\nworking in a control room who monitors and controls all or part of a pipeline\nfacility through a SCADA system. Each operator must have and follow written\ncontrol room management procedures that implement the requirements of this\nsection . . . .\nTexas Gas’s CRM procedure is inadequate because it does not include a process for\nimplementing fatigue mitigation, and evaluating the effectiveness of that criteria, as required by\n§ 192.631(d). Specifically, the factors listed in section 5.5 of the CRM procedure do not\ncorrespond to its 6630 Annual Fatigue Risk Management Procedure Review Task List; which\nprovides as follows:\n Review any fatigue incidents to determine if a change to the Controller work schedule\ncould improve fatigue mitigation.\n Review the overall effectiveness of the Fatigue Risk Management section of the CRM\nPlan and determine if a change will improve fatigue mitigation.\nThe second bullet point above, is the task and purpose of the review. Section 5.5 further\nidentifies the following for review and consideration:\n Review all annually required fatigue awareness training for completion and if not\ncompleted, confirm that the training is scheduled for completion.\n The effectiveness of the Fatigue Education and Training Program will be shared with all\nControllers.\n Controllers will also gauge the effectiveness of the training by which elements are\nmissing from the training content and are encouraged to bring new training opportunities\nand suggestions into the Fatigue Education and Training Program.\n All pipeline accidents that cited Controller fatigue as a contributing factor will be\nreviewed for potential revisions to the Fatigue Education and Training Program.\nWhile some of these review tasks will provide administrative information, the CRM plan fails to\noffer any criteria, metric, or suggested tools to make an effectiveness determination. Without\nthis, it is not possible for Texas Gas to determine if the program is effective in mitigating fatigue.\nThe procedure must be amended to include specific criteria and process used in determining if\nthe fatigue education/training program is effective.\n8. § 192.631 Control room management.\n(a) . . . .\n(e) Alarm management. Each operator using a SCADA system must have a written\nalarm management plan to provide for effective controller response to alarms. An\noperator's plan must include provisions to:\n(1) . . . .\n7\n\n\n\n(2) Identify at least once each calendar month points affecting safety that have been\ntaken off scan in the SCADA host, have had alarms inhibited, generated false\nalarms, or that have had forced or manual values for periods of time exceeding that\nrequired for associated maintenance or operating activities;\nTexas Gas’s CRM procedure is inadequate because it fails to provide a functional process to\nreview points that have had forced or manual values monthly. While stated as a requirement in\nsection 6.5 of the CRM plan, the work tasks 6608 and 6621 do not include it in the process. It\nwas stated, during the inspection, that they seldom force points or put them in manual mode, so\nthere was little need to review this monthly. These work tasks provide the direction for the\nmonthly compliance requirement of § 192.631(e)(2). The result of this inadequacy is that Texas\nGas has no records to demonstrate compliance with the monthly review of points that have had\nforced or manual values.\nThe procedure needs to be amended to include a process to identify at least once each calendar\nmonth points affecting safety that have generated false alarms, or that have had forced or manual\nvalues for periods of time exceeding that required for associated maintenance or operating\nactivities.\n9. § 192.631 Control room management.\n(a) . . . .\n(e) Alarm management. Each operator using a SCADA system must have a written\nalarm management plan to provide for effective controller response to alarms. An\noperator's plan must include provisions to:\n(1) . . . .\n(4) Review the alarm management plan required by this paragraph at least once\neach calendar year, but at intervals not exceeding 15 months, to determine the\neffectiveness of the plan;\nTexas Gas’s CRM procedure is inadequate because it fails to provide clear criteria, metrics or\nfactors that can be used to determine the effectiveness of the plan. The procedure and task list\noffers some considerations that may be employed, but lacks clarity and specificity as to how\ncontrollers are to respond to different alarms. Section 6.8 states, “Alarm management\neffectiveness metrics might include the number of alarms, clarity of alarm descriptions, how\nalarms are displayed or presented to Controllers, etc. Effectiveness could include, but not\nnecessarily mean reduction in number of alarms or reduction in alarm volume.” The\ncorresponding referenced Task List 6610 Annual Alarm/Alert Management Plan Review\nprovides 4 bullet points:\n Review the monthly alarm/alert audits for the current year to identify areas of\nimprovement to minimize the frequency in the alarm/alert count;\n Review all the incident/accident reviews to determine if a change to Alarm Philosophy\ncould improve the alarming process;\n Review monthly Alarm/Alert Counts per Console Report to determine the average\nnumber of alarms/alerts displayed on the Alarm/Alert Monitor screens; and\n8\n\n\n\n Review the overall effectiveness of the Alarm Management Plan and determine if a\nchange to the Plan or the Philosophy will improve controller response.\nThere are no instructions on how to perform the review so that the annual reviews provide\nconsistency as well as relevant analysis and findings. There are no metrics to provide a standard\nto measure against. For example, the second bullet point suggests a review of all incident/\naccident reviews, but if there are none than how does that roll in to effective alarms? The third\nbullet point, above, states, “Review monthly Alarm/Alert Counts per Console Report to\ndetermine the average number of alarms/alerts displayed on the Alarm/Alert Monitor screens.”\nWhile this may be a reasonable item to review, there is no offer of what to do once “average” is\ndetermined; what is the measure to determine too high, too low, or acceptable.\nForm 6610 is used to document the annual review. This form poses 4 questions with a simple\nYES or NO check box. The questions on Form 6610 are:\n Are there areas of improvement to minimize the frequency of alarm/alert count?\n Review all the incident/accident reviews. Would a change in the Alarm Philosophy\nimprove the alarm process?\n Review of the monthly Alarm/Alert Counts per Control Report. What is the average\nnumber of alarms/alert displayed on the Alarm/Alert monitor screen?\n Review the overall effectiveness of the Alarm Management Plan, is a change to the Plan\nor Philosophy necessary to improve controller response? If so, list below.\nWithout criteria or methods to assess this information, the results risk being subjective with\nnothing to substantiate the outcome. The results of a study or review should be framed so the\nevidence directs the findings for effectiveness. There is nothing in Texas Gas’s process that\nlends itself to such a conclusion.\nThe procedure must be amended to better support a thorough evaluation to determine the\neffectiveness of the plan.\n10. § 192.631 Control room management.\n(a) . . . .\n(e) Alarm management. Each operator using a SCADA system must have a written\nalarm management plan to provide for effective controller response to alarms. An\noperator's plan must include provisions to:\n(1) . . . .\n(6) Address deficiencies identified through the implementation of paragraphs (e)(1)\nthrough (e)(5) of this section.\nTexas Gas’s CRM procedure is inadequate because it fails to include provisions for addressing\ndeficiencies identified through implementation of the requirements of the regulation.\nSpecifically, section 6.9 of the CRM plan states that, “[d]eficiencies identified by implementing\nthe requirements of Sections 6.5 through 6.9 are addressed and documented by System\nOptimization/Gas Control.” The procedure lacks a standard process for how controllers are to\nrecord will record corrective actions taken, and how this process will be managed.\n9\n\n\n\nThe procedure must be amended to identify within the process how they will record deficiencies\nand where those records will be maintained.\n11. § 192.631 Control room management.\n(a) . . . .\n(h) Training. Each operator must establish a controller training program and\nreview the training program content to identify potential improvements at least\nonce each calendar year, but at intervals not to exceed 15 months. An operator's\nprogram must provide for training each controller to carry out the roles and\nresponsibilities defined by the operator. In addition, the training program must\ninclude the following elements:\nTexas Gas’s CRM procedure is inadequate because it does not require a review of the training\nprogram content, and the training content is not defined in the procedure. Section 9.10 of the\nCRM procedure rephrases the regulation, but does not offer any language on who, what, or how\nthe training program content must be reviewed. It does refer to Texas Gas procedure 6616:\nAnnual Training Program Review Task List in Appendix 5, and Form BWP-6616: Training\nProgram Review for additional guidance. Three tasks are listed in BWP-6616:\n Review all the lessons learned to determine if a change or addition to Training Program\ncould improve the Controller performance.\n Review the overall effectiveness of the Training Program and determine if a change is\nnecessary to improve Controller performance.\n Determine if additional training is needed to assist the Controllers in performing their\nRoles and Responsibilities.\nThis task requires Texas Gas to “review and determine” and respond with a Yes or No, but lacks\ncriteria or standards to evaluate the effectiveness of the training program content.\nThe procedure must be amended to include more details of what the review must include, as well\nas criteria to determine if the training program content is satisfactory, and if not, to identify\npotential improvements.\n12. § 192.631 Control room management.\n(a) . . . .\n(h) Training. Each operator must establish a controller training program and\nreview the training program content to identify potential improvements at least\nonce each calendar year, but at intervals not to exceed 15 months. An operator's\nprogram must provide for training each controller to carry out the roles and\nresponsibilities defined by the operator. In addition, the training program must\ninclude the following elements:\n(1) . . . .\n(6) Control room team training and exercises that include both controllers and\nother individuals, defined by the operator, who would reasonably be expected to\noperationally collaborate with controllers (control room personnel) during normal,\n10\n\n\n\nabnormal or emergency situations. Operators must comply with the team training\nrequirements under this paragraph by no later than January 23, 2018.\nTexas Gas’s CRM procedure is inadequate because it does not identify, by title or other means,\nthose individuals who would reasonably be expected to operationally collaborates with control\nroom personnel during normal, abnormal or emergency situations. Texas Gas’s CRM procedure\nsection 9.11, Team Training, Scenarios, Involvement, provides the following: “Gas Control\nManagement personnel, individuals that have decision-making ability or the authority to\ninfluence operational control, must participate in all Control Room team training and exercises.\nAlso, included in any trainings are personnel with the ability to direct or supersede the specific\ntechnical actions of a controller and employees that interact with controllers either remotely or\nface-to-face.” This statement provides guidance for identification of the individuals or job titles\nthat is identified in the language as “other individuals”. The regulation requires the operator to\ndefine those “who would reasonably be expected to operationally collaborate with controllers\n(control room personnel) during normal, abnormal or emergency situations.” The expectation is\nto use this guidance to identify either by title or by name, those who meet the definition and\ninclude that in the procedure.\nThe procedure must be amended to identify, with greater specificity, those who can reasonably\nbe expected to operationally collaborate with control room personnel during normal, abnormal or\nemergency situations.\nResponse to this Notice\nThis Notice is provided pursuant to 49 U.S.C. § 60108(a) and 49 C.F.R. § 190.206. Enclosed as\npart of this Notice is a document entitled Response Options for Pipeline Operators in\nEnforcement Proceedings. Please refer to this document and note the response options. Be\nadvised that all material you submit in response to this enforcement action is subject to being\nmade publicly available. If you believe that any portion of your responsive material qualifies for\nconfidential treatment under 5 U.S.C. 552(b), along with the complete original document you\nmust provide a second copy of the document with the portions you believe qualify for\nconfidential treatment redacted and an explanation of why you believe the redacted information\nqualifies for confidential treatment under 5 U.S.C. 552(b).\nFollowing the receipt of this Notice, you have 30 days to submit written comments, revised\nprocedures, or a request for a hearing under § 190.211. If you do not respond within 30 days of\nreceipt of this Notice, this constitutes a waiver of your right to contest the allegations in this\nNotice and authorizes the Associate Administrator for Pipeline Safety to find facts as alleged in\nthis Notice without further notice to you and to issue an Order Directing Amendment. If your\nplans or procedures are found inadequate as alleged in this Notice, you may be ordered to amend\nyour plans or procedures to correct the inadequacies (49 C.F.R. § 190.206). If you are not\ncontesting this Notice, we propose that you submit your amended procedures to my office within\n30 days of receipt of this Notice. This period may be extended by written request for good\ncause. Once the inadequacies identified herein have been addressed in your amended\nprocedures, this enforcement action will be closed.\n11\n\n\n\nIt is requested (not mandated) that Texas Gas-Boardwalk maintain documentation of the safety\nimprovement costs associated with fulfilling this Notice of Amendment (preparation/revision of\nplans, procedures) and submit the total to Gregory A. Ochs, Director, Central Region, Pipeline\nand Hazardous Materials Safety Administration. In correspondence concerning this matter,\nplease refer to CPF 3-2021-018-M and, for each document you submit, please provide a copy in\nelectronic format whenever possible.\nSincerely,\nGregory A. Ochs\nDirector, Central Region, OPS\nPipeline and Hazardous Materials Safety Administration\nEnclosure: Response Options for Pipeline Operators in Compliance Proceedings\ncc: Richard Keyser, Sr. VP Operations dick.keyser@bwpipelines.com\n12\n\n32021018NOA_Closure Letter_08272021_(20-173061)_text.pdf\n\nVIA ELECTRONIC MAIL TO: stan.horton@bwpipelines.com, dick.keyser@bwpipelines.com\nAugust 27, 2021\nStanley C. Horton\nPresident, CEO\nTexas Gas Transmission, LLC\n9 Greenway Plaza, Suite 2800\nHouston, TX 77066\nRe: CPF 3-2021-018-NOA\nDear Mr. Horton:\nFrom June 15 through June 19, 2020, a representative from the Pipeline and Hazardous Materials\nSafety Administration (PHMSA), pursuant to chapter 601 of 49 United States Code, conducted\nan on-site pipeline safety inspection of Texas Gas Transmission, LLC’s (Texas Gas), Control\nRoom Management procedures in Owensboro, Kentucky. As a result of the inspection, Texas\nGas was issued a Notice of Amendment on April 9, 2021, which proposed amendment of your\nprocedures.\nTexas Gas submitted its amended procedures on August 23, 2021. My staff reviewed the\namended procedures, and it appears that the inadequacies outlined in this Notice of Amendment\nhave been corrected.\nThis letter is to inform you no further action is necessary and this case is now closed. Thank you\nfor your cooperation.\nSincerely,\nGregory A. Ochs\nDirector, Central Region, OPS\nPipeline and Hazardous Materials Safety Administration","truncated":false,"body_characters":34324}