Checklist - PUCO · Web viewEach valve, fitting, length of pipe, and other component must be marked as prescribed in the specification or standard to which is was manufactured, except

Public Utilities Commission of OhioService Monitoring and Enforcement

Department180 East Broad Street, 7th Floor

Columbus, OH 43215Mike DeWine, GovernorAsim Z. Haque, Chairman

Construction, Operations and Maintenance Plans and Procedures Review

Inspection ReportInspector Name: Inspection Start Date: Inspection End Date: Date of Exit Interview: Total # of Field Days: Probable Violations?: Yes: No: If “Yes”, attach a draft Notice of Probable Noncompliance form

Operator InformationName of Operator: OP ID #: Operator HQ Address: Records Location:

Persons InterviewedName Title Phone Number / E-mail

Inspection Components: Reporting Procedures (pg. 2) Materials and Construction (pg. 3-10) Operations and Maintenance (pg. 11-22) Damage Prevention Program (pg. 23)

Emergency Response Plans (pg. 24) Public Awareness Program (pg. 25) Operator Qualification Plan (pg. 26) Drug & Alcohol Testing Program (pg. 27)

Inspection Summary/Findings:

S = Satisfactory U = Unsatisfactory N/A = Not Applicable (explain in Comments) N/C = Not Checked (explain in Comments)

1PUCO - Headquarters Inspection FormVersion 19.1

REPORTING PROCEDURES

49 CFR PART 191 S U N/A N/C

191.5

OAC 4901:1-16-05

Does the operator have procedures to give Immediate Notice of Incidents as defined in 49 CFR 191.3 to the National Response Center (NRC) at 1-(800) 424-8802, or electronically at http://www.nrc.uscg.mil, at the earliest practicable moment following discovery? Has the operator followed those procedures?Do operator procedures also require Immediate Notice of Incidents to the State of Ohio One-Call Incident Notification system at 1-844-OHCALL1 (642-2551) at the earliest practical moment following discovery?

191.7Does the operator submit reports (except Safety Related Condition reports) electronically to PHMSA at https://portal.phmsa.dot.gov/pipeline, unless an alternative reporting method is authorized per 191.7(d)?

191.9191.15

Has the operator submitted PHMSA Form 7100.1 (Distribution) or 7100.2 (Transmission/Gathering) as soon as practicable but not more than 30 days after detection of a reportable Incident?

191.11191.17

Has the operator submitted an annual report on PHMSA Form 7100.1-1 (Distribution) or 7100.2-1 (Transmission/Gathering) not later than March 15th for the preceding calendar year?

Did the operator read and follow the instructions for completing the Form 7100.1-1 (Distribution) or 7100.2-1 (Transmission/Gathering) forms available at: http://www.portal.phmsa.dot.gov/pipeline?

Is the information reported on the forms appear to be accurate and complete based on the information available at the time of the inspection?

191.12 (Distribution only) Has the operator submitted a mechanical fitting failure report on PHMSA Form 7100.1-2 for

each mechanical fitting failure that occurs within a calendar year not later than March 15th of the next year?

191.22 Does the operator notify PHMSA of the following no later than 60 days before the event occurs?:

- Construction or any planned rehabilitation, replacement, modification, upgrade, uprate, or update of a facility, other than a section of line pipe, that costs $10 million or more;

- Construction of 10 or more miles of a new pipeline;- Construction of a new LNG plant or LNG facility;- Reversal of product flow direction when the reversal is expected to last more than 30 days; or- A pipeline converted for service under 192.14

191.25 Does the operator submit written reports for Safety Related Conditions as defined in 49 CFR 191.23 within five

working days after the operator determines the condition exists, but not later than 10 working days after the day a representative of the operator discovers the condition?

49 USC60139

(Transmission only) Does the operator have procedures to report an exceedance of MAOP in excess of the build-up allowed for operation of pressure-limiting or control devices, to PHMSA on or before the 5th day following the date on which the exceedance occurs using the reporting process described in 49 CFR 191.25? (see PHMSA Advisory Bulletin “Reporting of Exceedance of MAOP”, 12/21/12)

191.29 (Transmission only) Does the operator submit updates to the National Pipeline Mapping System (NPMS) every

12 months, or report no modifications if none have occurred? (http://www.npms.phmsa.dot.gov/submission/)

Comments:


https://portal.phmsa.dot.gov/pipeline

MATERIALS AND CONSTRUCTION

SUBPART A – GENERAL S U N/A N/C

.14Did operators take appropriate action regarding flow reversals, product changes, and conversion to service?(see PHMSA advisory bulletin 2014-4)

SUBPART B - MATERIALS S U N/A N/C

.55For steel pipe, procedures specify use of pipe manufactured in accordance with an Appendix B specification.

.59 New plastic pipe is qualified for use under this part if it is manufactured in accordance with a listed specification; and it is resistant to chemicals with which contact may be anticipated.

Used plastic pipe is not qualified for use under this part unless it meets the qualifications listed in 192.59(b)

.63 Each valve, fitting, length of pipe, and other component must be marked as prescribed in the specification or standard to which is was manufactured, except that thermoplastic fittings must be marked in accordance with ASTM D2513. Markings must indicate size, material, manufacturer, pressure rating, temperature rating, and (as appropriate) type, grade and model. All markings on plastic pipe must be repeated at intervals of <= 2 ft.

.67 Each operator must have and follow written procedures for the storage and handling of plastic pipe and associated components that meet the applicable listed specifications (effective January 22, 2019)

SUBPART C – PIPE DESIGN S U N/A N/C

.103Pipe designed of sufficient wall thickness, or installed with adequate protection, to withstand anticipated external pressures and loads that will be imposed on the pipe after installation.

.105 - .113

(a) Operators procedures specify use of the design formula for steel pipe including correct calculation of the yield strength, nominal wall thickness, longitudinal joint factor, and temperature derating factor.

.111Procedures accurately reflect how to determine the design factor (F) for steel pipe: Class 1 0.72, Class 2 0.60, Class 3 0.50, Class 4 0.40

- Class 1 piping: 0.6 or less for uncased piping crossing a public road or railway right-of-way, or is supported by a bridge, or used in a fabricated assembly.

- Class 2 piping: 0.5 or less for uncased piping crossing a public road or railway right-of-way.- Class 1 and 2 piping: 0.5 or less for pipe used in a compressor station, regulating or measuring

station, or located in inland navigable waters.

.121Procedures specify the use of one of the listed design formulas for plastic pipe:

- General requirements for Distribution, Class 3,4 Transmission: DF=0.32, design pressure 100 psig.- PE pipe: 125 psig for PE2406 or PE3408 pipe produced between 7/14/04 and 1/22/19 (12” or less).- PE pipe: 125 psig, DF=0.4 for PE2708, PE4710 pipe produced after 1/22/19 (12” or less).- PA-11 pipe: 200 psig, DF=0.4 for PA32312, PA32316 pipe produced between 1/23/09 and 1/22/19

(4” or less).- PA-11, PA-12 pipe: 250 psig, DF=0.4 for PA32316, PA42316 pipe produced after 1/22/19 (6” or less).

* See 192.121 for tables describing nominal pipe size and wall thickness restrictions *

Comments:


SUBPART D – DESIGN OF PIPELINE COMPONENTS S U N/A N/C

.143 Except for EFV’s, each plastic pipeline component installed after 1/22/19 must be able to withstand operating pressures and other anticipated loads in accordance with a listed specification.

.145

Valves must meet the listed minimum design and testing requirements for use. Except for plastic and cast iron, valves must meet the minimum requirements of API 6D, or other standard that provides an equivalent performance level (API 6A, MSS SP70, MSS SP71, or MSS SP78). Plastic valves installed after 1/22/19 must meet the minimum requirements of a listed specification.

.147 Flange and flange accessories (other than cast iron) must meet ASME/ANSI B16.5, MSS SP-44, or equivalent.

.149 Threaded fittings must have a minimum wall thickness. Steel butt welded fittings must have pressure and temperature ratings. Plastic fittings installed after 1/22/19 must meet a listed specification.

.150New Transmission lines and replacements of Transmission pipe, valves, fittings, or other line components are designed and constructed to accommodate the passage of instrumented internal inspection devices.

.151 - .161

Procedures accurately reflect requirements for tapping, prefabricated components, welded branch connections, extruded outlets, and flexibility for thermal expansion/contraction, supports and anchors.

.163 - .173

Compressor stations designed and constructed in accordance with the requirements of 192.163 through 173.

.179Transmission lines are designed with sectionalizing block valves designed and spaced as specified in 192.179.

.181High pressure Distribution systems and associated regulator stations have valves designed and spaced to reduce the time to shut down a section of main in an emergency as specified in 192.181.

.183 - .189

Procedures reflect structural design, accessibility, ventilation, and drainage requirements for vaults.

.195

Pipelines connected to a gas source such that MAOP could be exceeded as a result of pressure control failure or some other type of failure must have pressure relieving or limiting devices meeting 192.199 and 192.201.- Distribution systems must in addition have pressure regulation devices capable of meeting pressure and

load conditions experienced in normal operation, or be designed to prevent accidental over-pressuring.

.197 High pressure Distribution systems have service regulators meeting the requirements of 192.197.

.199 Pressure relief and pressure limiting devices meet the design requirements of 192.199.

.201Pressure relief stations are designed with sufficient capacity to meet the requirements of 192.201.

.203Instrument, Control, and Sampling Pipe and Components meet 192.203(a) & (b)

.204

Risers installed after 1/22/19: Riser designs must be tested to ensure safe performance under anticipated external and internal loads. Factory assembled anodeless risers must be designed and tested in accordance with ASTM F1973-13. All risers connected to regulator stations must be rigid and designed to provide adequate support and resist lateral movement, anodeless risers must have a rigid external casing.

Comments:


SUBPART E – WELDING OF STEEL IN PIPELINES S U N/A N/C

.225 Has the operator qualified welding procedures under Section 5 or 12 of API 1104 or Section IX of the ASME Boiler and Pressure Vessel Code? Are welding procedures recorded in detail, including the results of the qualified test?

.227 Are welders qualified under Section 6 or 12 of API 1104 or Section IX of ASME? (Welders may qualify under Appendix C for piping operating at < 20% SMYS)

.229 (a) Welders may not weld on compressor station piping and components if their qualification is based on a nondestructive test.

(b) Welder must have used welding process within the preceding 6 months .

(c)(1) For welders qualified using API 1104 or ASME, has welding been done in the preceding 6 months and has one weld been tested and found acceptable under Section 6, 9, or 12 of API 1104 or Section IX of the ASME Boiler and Pressure Vessel Code? (Alternately, welders may maintain ongoing qualification by making a weld and having it tested to the above standards at least twice a year at intervals not exceeding 7½ months).

(c)(2) For Appendix C welders, did the operator cut out a production weld and test it to Appendix C within the preceding 7 1/2 months or is the welder re-qualified to Appendix C annually at intervals not exceeding 15 months.

.231 Welding operation must be protected from weather conditions that would impair the quality of the weld.

.233 Do procedures reflect restrictions on miter joints listed in 192.233?

.235 Do procedures require the welding surface to be clean and free of material detrimental to the weld, and the pipe or component to be aligned to provide the most favorable condition for depositing the root bead?

.241 (a) Visual inspection must be conducted by an individual qualified by appropriate training and experience

(b) Welds on a pipeline to be operated at 20% or more of SMYS must be nondestructively tested (for pipe 6”+)

(c) Weld acceptability determined according to the standards in API 1104, Section 9.

.243 (a), (b) Nondestructive testing clearly indicating defects is performed in accordance with written procedures; and by persons trained and qualified in the established procedures and with the equipment employed in testing.

(c) Procedures must be established for the proper interpretation of each nondestructive test.

(d), (e) The percentage of welds tested are determined by applying 192.243(d) and (e).

(f) Each operator must maintain records of nondestructive testing for the life of the pipeline.

.245 Each weld found unacceptable must be removed or repaired

Comments:


SUBPART F - JOINING OF PIPELINE MATERIALS OTHER THAN BY WELDING S U N/A N/C.273 (b) Are joints made in accordance with written procedures that have been proven by test or experience?

(c) Is each joint visually inspected?

.281 (c)(1) A butt heat-fusion joint must be joined by a device that holds the heater element square to the ends of the piping, compresses the heated ends together, and holds the pipe in proper alignment in accordance with a qualified procedure.

(c)(2) A socket heat-fusion joint must be joined by a device that heats the mating surfaces of the joint uniformly and simultaneously to essentially the same temperature.

(c)(3) An electrofusion joint must be joined utilizing the equipment and techniques of the fittings manufacturer or by equipment and techniques shown to be equivalent by testing to the requirements of §192.283(a)(1)(iii).

(e) Each compression type mechanical joint on plastic pipe must comply with (e)(1) through (e)(4).

.283 (a) Procedures for heat fusion, solvent cement and adhesive joints must be qualified by subjecting specimen joints to tests described in 192.283(a)

(b) Procedures for making mechanical plastic pipe joints must be qualified in accordance with a listed specification based on the pipe material.

(c) A copy of each written procedure being used for joining plastic pipe must be available to the persons making and inspecting joints.

.285 (a) Persons making plastic pipe joints are qualified through appropriate training or experience; and making a specimen joint according to the applicable written procedure.

(b) The specimen joints used for qualification must be visually examined during and after assembly; and for heat fusion, solvent cement, or adhesive joints tested in accordance with 192.285(b)(2).

(c) A person must be requalified under an applicable procedure once each calendar year at intervals not exceeding 15 months, or after any production joint is found unacceptable by testing under 192.513.

(d) Each operator shall establish a method to determine that each person making joints in plastic pipelines in the operator’s system is qualified in accordance with this section.

.287 Has the operator established a method to identify persons qualified by appropriate training or experience to evaluate the acceptability of plastic pipe joints made under the applicable joining procedure required by 192.273(c) and 192.285(b)?

Comments:


SUBPART G – CONSTRUCTION REQUIREMENTS for TRANSMISSION LINES and MAINS S U N/A N/C

.307 Each length of pipe and other components must be visually inspected at the site to ensure it has not sustained any visible damage that could impair its serviceability.

.309 (a) Imperfections or damage that impairs the serviceability of steel pipe must be repaired or removed. If a repair is made by grinding, wall thickness must be preserved in accordance with the standards in 192.309(a)(1) and (2)

(b) Dents must be removed from steel pipe to be operated at over 20% SMYS in accordance with 192.309(b)

(c) Each arc burn on steel pipe to be operated at over 40% SMYS must be repaired or removed.

.311 Each imperfection or damage that would impair the serviceability of plastic pipe must be repaired or removed.

.313 Each field bend in steel pipe and each elbow must be installed in accordance with 192.313(a) through (c). Plastic pipe may not be installed with a bend radius that is less than the minimum bend radius specified by the manufacturer for the diameter of pipe installed.

.315 Wrinkle bends may not be made on steel pipe to be operated over 30% SMYS. Each wrinkle bend must comply with 192.315(b)

.317 (a) Transmission lines or Mains must be protected from washouts, floods, unstable soil, landslides, etc.

(b) Each aboveground Transmission line or Main must be protected from vehicular or other external damage.

.319 (a) Transmission lines installed in a ditch must minimize stresses and protect pipe coating from damage.

(b) When backfilling a Transmission line or Main in a ditch, it must be backfilled in a manner that provides firm support under the pipe and prevents damage to the pipe and pipe coating from the backfill material.

.321 Plastic pipe installed in accordance with 192.321 (a) through (h), including the use of tracer wire that is resistant to corrosion damage and where contact with the pipe is minimized?

.323 Installed casings meet the requirements of 192.323?

.325 (a) Transmission lines installed with a minimum of 12” of clearance from other underground structures(b) Mains installed with sufficient clearance to allow for proper maintenance and protect against damage

.327 (a) Transmission lines installed with a minimum cover as specified by the table in 192.327(a)(b) Mains installed with at least 24” of cover (See 192.327(c) and (d) for exceptions).

.329 Plastic pipe and components that are pulled through the ground as part of trenchless excavation must use a weak link to ensure the pipe will not be damaged by any excessive force during the pulling process.

Comments:



SUBPART H - CUSTOMER METERS, SERVICE REGULATORS, and SERVICE LINES S U N/A N/C

.353 Meters and service regulators installed at locations as prescribed under 192.353 (a) thru (d)

.355 (a) Thru (c) Service regulator vents and relief vents installed and protected from damage. Vaults housing meters and regulators protected from loading due to vehicular traffic.

.357 (a) Thru (d) Meters and regulators installed to minimize stresses and insure that potential releases vent to outside atmosphere.

.361 Minimum service line installation requirements as prescribed under 192.361 (a) thru (g)

.365 Location of service-line valves as prescribed under 192.365 (a) thru (c)

.367 (a) thru (b)(3) General requirements for locations of service-line connections to mains and use of compression type connections to mains.

.375 Plastic service lines must be installed below ground level, with some listed exceptions.

.376 Plastic service lines that are pulled through the ground as part of trenchless excavation must use a weak link to ensure the pipe will not be damaged by any excessive force during the pulling process.

.379 Plastic service lines not placed into service upon completion of installation must by physically disconnected from the gas supply with open ends sealed, valve preventing flow of gas closed and locked, or mechanical device preventing the flow of gas installed in the service line or meter assembly.

.381 EFV’s meet listed performance requirements listed in (a), are marked or otherwise identified upon installation, and are located as near as practical to the fitting connecting the service line to its source of gas

.383 (b) EFV’s are installed on new or replaced service lines operating at >10 psig after 4/14/17 for the following: - A single service line to one single family residence (SFR); (effective since 2/12/10) - A branched service line to a SFR installed concurrently with the primary SFR service line; - A branched service line to a SFR installed off a previously installed SFR that does not contain a EFV; - Multifamily residences with known customer loads not exceeding 1,000 SCFH; and - A single small commercial customer served by a single service line with a load not exceeding 1,000 SCFH.(c) Documentation exists when operator claims prior experience with contaminants in the gas stream.(d),(e) Operator has notified customers of their right to request an EFV and has provisions for responding to requests for EFV installation.

.385 (b) Manual service line shut-off valves or EFV’s installed for new or replaced services exceeding 1,000 SCFH.(c) Shut-off valves (“curb valves”) are installed in such a way as to allow accessibility during emergencies and are maintained in a manner consistent with the valve manufacturer’s specifications.

Comments:


SUBPART I – CORROSION CONTROL S U N/A N/C

..455Buried or submerged metallic pipe segments must be externally coated; and cathodically protected within one year after construction (see exceptions in code).(e) Electrically isolated metal alloy fittings installed after 1/22/19 that do not meet the requirements of paragraph (f) must be cathodically protected, and maintained in accordance with the operators IM plan.

.461 Procedures must address the protective coating requirements of the regulations. External coating on steel pipe must meet the requirements of this part.

.463Procedures for the design and installation of cathodic protection systems that can provide a cathodic protection level according to Appendix D criteria.

.467(a) Buried or submerged piping must be electrically isolated from other underground metallic structures(b) Insulating devices must be installed where electrical isolation is necessary to apply corrosion control(c) Pipelines must be electrically isolated from metallic casings.(d) Inspections and electrical tests must be made to assure that electrical isolation is adequate.(e) Insulating devices may not be installed where a combustible atmosphere is anticipated unless precautions are taken to prevent arcing.(f) Protective measures must be taken where the pipeline is in close proximity to electrical transmission lines or other sources of fault currents.

.469

.471Sufficient test stations or other contact points for electrical measurement installed to determine CP adequacy.Test leads installed to be mechanically secure and electrically conductive, and to minimize stress concentrations on the pipe.

.473 (b) Each impressed current type cathodic protection system or galvanic anode system must be designed and installed so as to minimize adverse effects on existing adjacent underground structures.

.476 Transmission lines must be designed and constructed to reduce the risk of internal corrosion (see 192.476)

.491 Maintain records or maps to show the location of cathodically protected piping, cathodic protection facilities, galvanic anodes, and neighboring structures bonded to the cathodic protection system.

Comments:


SUBPART J – TEST REQUIREMENTS S U N/A N/C

.503 Procedures to ensure that the provisions found under 192.503(a) thru (d) for new segments of pipeline, or Return to Service segments of pipeline which have been relocated or replaced are met.

.505 (a)-(e) Strength test requirements for steel pipeline to operate at a hoop stress of 30 percent or more of SMYS.

.507 (a)-(c) Test requirements for pipelines to operate at a hoop stress < 30 percent of SMYS and >= 100 psig.

.509 (a) & (b) Test requirements for pipelines to operate below 100 psig.

.511 (a) Thru (c) Test requirements for service lines.

.513 Test requirements for plastic pipelines.

.515 (a) & (b) Environmental protection and safety requirements.

.517 Specified records for tests performed under .505 and .507 retained for the useful life of the pipeline.

SUBPART K - UPRATING S U N/A N/C

Provisions for meeting the minimum requirements for increasing maximum allowable operating pressure (uprating) for pipelines.

.553 (a) Pressure increments must be increased gradually, at a rate that can be controlled. At the end of each incremental increase, the pressure must be held constant while the segment is checked for leaks.

(b) Records maintained for the life of the pipeline.

(c) Operator has established written procedures that will ensure each applicable requirement of this subpart is complied with.

(d) Operators written procedures reflect that a new maximum allowable operating pressure established under this subpart may not exceed the maximum that would be allowed under 192.619 and 192.621 for a new segment of pipeline constructed of the same materials in the same location.

.555 Operators procedures comply with requirements in 192.555 (a) through (e) for uprating Steel pipelines to a pressure that will produce a hoop stress of 30 % or more of SMYS.

.557 Operator’s procedures comply with requirements in 192.557 (a) through (d) for uprating Steel, Plastic, Iron, and Ductile Iron pipelines to a pressure that will produce a hoop stress less than 30 % of SMYS.

Comments:


OPERATIONS AND MAINTENANCE

SUBPART I - CORROSION CONTROL S U N/A N/C

.453 Corrosion procedures established for the Operation and Maintenance of CP systems, carried out by, or under the direction of, a person qualified in pipeline corrosion control methods

.455 Buried pipelines installed after July 31, 1971 must be externally coated and cathodically protected(see exceptions in code)

.457 (a) All effectively coated steel transmission pipelines installed prior to August 1, 1971, must becathodically protected

(b) If installed before August 1, 1971, cathodic protection must be provided in areas of active corrosion for: bare or ineffectively coated transmission lines, and bare or coated compressor, regulator, and metering stations, and (except for cast iron or ductile iron) bare or coated distribution lines.

.459 Procedures call for examination of buried pipeline that becomes exposed for evidence of external corrosion and/or deteriorated coating, and how to determine appropriate remedial action if corrosion is found.

Are cast iron pipelines examined for evidence of graphitization and, if necessary, remedial action taken?

.461 Application of protective coating must meet the requirements of this part.

.463 Procedures identify a cathodic protection level according to Appendix D criteria. The amount of cathodic protection must be controlled so as not to damage the protective coating of the pipe.

.465 (a) Pipe-to-soil monitoring (1 per yr/15 months)

(b) Rectifier monitoring (6 per yr/2½ months)

(c) Interference bond monitoring (6 per yr 2½ months; or 1 per yr / 15 months – see code)

(e) Electrical surveys (closely spaced pipe to soil) on bare/unprotected lines, cathodically protect active corrosion areas (1 per 3 years/39 months)

.467 (c) Each pipeline must be electrically isolated from metallic casings that are a part of the underground system. If isolation is impractical, other measures must be taken to minimize corrosion of the pipeline inside the casing.

(d) Inspections and electrical tests must be made to assure electrical isolation is adequate (as required)

.473 Procedures address how to identify and mitigate interference currents


SUBPART I - CORROSION CONTROL S U N/A N/C

.475 (a) Operator has procedures to determine if the transported gas is corrosive.

(b) Removed pipe must be inspected for internal corrosion. If found, the adjacent pipe must be inspected to determine extent. Certain pipe must be replaced. Steps must be taken to minimize internal corrosion.

.477 Internal corrosion control coupons or other means of monitoring internal corrosion must be checked two times each calendar year, with internals not exceeding 7 ½ months.

.479 (a) Each exposed pipe must be cleaned and coated (see exceptions under .479(c) – light surface oxide, or testing demonstrating the corrosion will not affect the safe operation of the pipeline before the next scheduled inspection)

Soil-to-air interfaces must be coated

(b) Coating material must be suitable for the prevention of atmospheric corrosion

.481 (a),(b) Atmospheric corrosion control monitoring (1 per 3 yrs, not to exceed 39 months).Special attention required at soil/air interfaces, thermal insulation, under dis-bonded coating, pipe supports, splash zones, deck penetrations, and spans over water

(c) Protection must be provided if atmospheric corrosion is found (per §192.479)

.483 Replacement and required pipe must be coated and cathodically protected (see code for exceptions)

.485 (a) Procedures to replace pipe or reduce the MAOP if general corrosion has reduced wall thickness

(b) Procedures to replace/repair pipe or reduce MAOP if localized corrosion has reduced wall thickness (unless reliable engineering repair method exists)

(c) Procedures to use Rstreng or B-31G to determine remaining wall strength

.487 Remedial measures (distribution lines other than cast iron or ductile iron)

.489 Remedial measures (cast iron and ductile iron pipelines)

.491 Test, survey and inspection records required by this subpart maintained for at least 5 years.Records related to 465(a) and (e), and 475(b) must be retained for the life of the pipe.

Comments:


SUBPART L - OPERATIONS S U N/A N/C

.605 (a) Procedural Manual Review – Operations and Maintenance (review once per yr/15 months) Note: Including review of OQ procedures as suggested by PHMSA - ADB-09-03 dated 2/7/09

(b)(3) Availability of construction records, maps, operating history to the appropriate operating personnel, including contractors

(b)(5) Start up and shut down of the pipeline to assure operation within MAOP plus allowable buildup

(b)(8) Periodic review of personnel work – does the operator have procedures to review the work done by operator personnel (including contractors) to determine the effectiveness and accuracy of normal O&M procedures, and modify the procedures when deficiencies are found?

(b)(9) Taking adequate precautions in excavated trenches to protect personnel from the hazards of unsafe accumulations of vapors or gas, and making available when needed at the excavation, emergency rescue equipment, including a breathing apparatus and a rescue harness and line.

(b)(11) Responding promptly to a report of a gas odor inside or near a building, unless the operator’s emergency procedures under §192.615(a)(3) specifically apply to these reports.

(b)(12) Implementing the applicable control room management procedures required by 192.631.

(c) 192.605(c) applies to Transmission lines only. Procedures for responding to, investigating, and correcting the cause of:

(c)(1)(i) Unintended closure of valves or shut downs

(c)(1)(ii) Increase or decrease in pressure or flow rate outside of normal operating limits

(c)(1)(iii) Loss of communications

(c)(1)(iv) The operation of any safety device

(c)(1)(v) Malfunction of a component, deviation from normal operations or personnel error

(c)(2) Checking variations from normal operation after abnormal operations ended at sufficient critical

(c)(3) Notifying the responsible operating personnel when notice of an abnormal operation is received

(c)(4) Periodic review of personnel work – effectiveness of abnormal operation procedures

(d) (Transmission only) - Safety related condition (SRC) reports. The O&M manual must include instructions enabling personnel to recognize SRC’s subject to the reporting requirements of 191.23

Comments:



Change in Class Location Procedures

.609 Procedures for a required study whenever an increase in population density indicates a change in class location for a segment of existing Steel pipeline operating at a hoop stress of more than 40% SMYS, or for a segment of existing pipeline with hoop stress corresponding to the established MAOP not commensurate with the present class location.

.611 Procedures to confirm or revise MAOP according to 192.611(a). Confirmation or revision of the segment MAOP must be completed within 24 months of the change in class location.

Continuing Surveillance Procedures

.613 (a) Procedures for surveillance and required actions relating to change in class location, failures, leakage history, corrosion, substantial changes in cathodic protection requirements, and unusual operating and maintenance conditions.

(b) Procedures requiring MAOP to be reduced, or other actions to be taken, if a segment of pipeline is in unsatisfactory condition.

PHMSA Area of EmphasisIs the operator monitoring cast iron pipelines for circumferential cracking failures, studying leakage history and other unusual operating conditions?

.614 Damage Prevention Program – see pg. 23

.615 Emergency Plans – see pg. 24

.616 Public Awareness – see pg. 25

Failure Investigation Procedures

.617 Has the operator established procedures to analyze accidents and failures, including selection of failed equipment for laboratory examination where appropriate, for the purpose of determining the cause of failure?

Does the operator review records of accidents and failures for lessons learned, and adjust procedures or practices accordingly to minimize the possibility of a recurrence?

PHMSA Area of EmphasisDoes the operator have procedures to identify any plastic pipe that has shown a record of defects/leaks and mitigate safety concerns

Does the operator have and follow procedures for determining the cause of excavation damages including adequately classifying causes of excavation damage? (GPS recommends using the categories in the Common Ground Alliance damage report field form)

Is the operator aware of their “Damages per Thousand Locate Ticket Requests” number from their 7100 annual report, and are they using this information to track progress?

Comments:



MAOP Procedures

Note: If the operator is operating under a Special Permit, a Waiver or 192.620, the inspector needs to review the special conditions of the Special Permit, Waiver or refer to the GPS Alternative MAOP inspection form for additional .620 requirements.

.619 Has the operator established MAOP so that it is commensurate with the class location?

MAOP cannot exceed the lowest of the following:

(a)(1) Design pressure of the weakest element in the pipeline segment;

(a)(2) Test pressure divided by 1.5 for plastic pipe in all locations, and test pressure divided by the applicable factor listed in (a)(2)(ii) for steel pipe over 100 psig

(a)(3) The highest actual operating pressure to which the segment of line was subjected during the 5 years preceding the applicable date in second column listed in (a)(3), unless the segment was tested according to (a)(2) after the applicable date in the third column, or was uprated according to subpart K.

(a)(4) Maximum safe pressure determined by operator.

(b) Overpressure protective devices must be installed if .619(a)(4) is applicable

(c) The requirements on pressure restrictions in this section do not apply in the following instance:

An operator may operate a segment of pipeline found to be in satisfactory condition, considering its operating and maintenance history, at the highest actual operating pressure to which the segment was subjected during the 5 years preceding the applicable date in the second column of the table in paragraph (a)(3) of this section. An operator must still comply with § 192.611.

.620 Does the operator use Alternate MAOP? (if Yes, attach a GPS Alternative MAOP inspection form) Yes No

.621 Has the operator established MAOP for high pressure distribution systems at a pressure that does not exceed the lowest of:

- 1) Design pressure of the weakest element in the system;- 2) 60 psig unless the service lines are equipped with service regulators meeting 192.197(c);- 3) 25 psig in segments of cast iron pipe with unreinforced bell and spigot joints;- 4) Pressure limits to which a joint could be subjected without the possibility of parting;- 5) Pressure determined by the operator to be the maximum safe pressure considering system

history.

.623 Has the operator established maximum and minimum operating pressures for low pressure distribution systems at pressures at which the safe and continuing operation of any connected and properly adjusted low-pressure gas burning equipment can be assured?

Comments:



Odorization Procedures

.625 A combustible gas in a distribution line must contain a natural odorant or be odorized so that at a concentration in air of one-fifth of the lower explosive limit, the gas is readily detectable by a person with a normal sense of smell.

(f) Each operator must conduct periodic sampling of combustible gases using an instrument capable of determining the percentage of gas in air at which the odor becomes readily detectible. Operator procedures should define “periodic”.

Tapping pipelines under pressure

.627 Procedures call for hot taps must be made by a qualified crew (Reference API RP 2201 for Best Practices).

Pipeline purging procedures

.629 Purging of pipelines must be done to prevent entrapment of an explosive mixture in the pipeline

(a) Lines containing air must be properly purged.

(b) Lines containing gas must be properly purged

Control Room Management Procedures(Use separate Control Room Management long form for control rooms that monitor and control through a SCADA system

250,000 or more distribution services; and/or transmission lines with one or more compressor stations)

.605 (b)(12) For operators who have a controller working in a control room that monitors and controls all or part of a pipeline facility through a SCADA system, does the operator have and follow written control room management (CRM) procedures?

.631 (d) Does the operator implement all of the following methods to reduce risk associated with controller fatigue:

- 1) Establish shift lengths and schedule rotations that provide off duty controllers at least 8 hours of continuous sleep;

- 2) Educate controllers and supervisors in fatigue mitigation strategies;- 3) Train controllers and supervisors to recognize the effects of fatigue, and;- 4) Establish a maximum limit on controller hours of service (which may provide for an emergency

deviation if necessary for the safe operation of a pipeline facility).

(j) Has the operator maintained records as described in 192.631(j)?

Comments:


SUBPART M - MAINTENANCE PROCEDURES S U N/A N/C

.703 (b) Each segment of pipeline that becomes unsafe must be replaced, repaired, or removed from service(c) Hazardous leaks must be repaired promptly

.720 Mechanical leak repair clamps may not be used as a permanent repair method for plastic pipe.(effective 1/22/19)

O.A.C. 4901:1-16-04: LEAK CLASSIFICATION S U N/A N/C

Is the operator classifying hazardous leaks immediately and all other leaks within two business days, using leak detection equipment?

Is the operator classifying leaks utilizing grade one, two, or three classifications?

Is the operator taking immediate action on grade one leaks to protect life and property or taking continuous action until the condition is no longer hazardous?

Is the operator re-evaluating Grade 1 leaks repaired or reclassified through the use of a clamp, tape wrap, etc. after allowing the soil to vent and stabilize, but no more than 30 days after the repair or reclassification?

Is the operator repairing grade two leaks within 15 months of discovery or is pipe replacement taking place within 24 months from the date of discovery?

Are open grade two leaks being reevaluated every six months until the leak is cleared?

Are grade three leaks being reevaluated during the next scheduled survey or within 15 months (whichever is sooner) until the leak is cleared or there is no longer any indication of leakage?


Pipeline Markers – Mains and Transmission Lines

.707 Except as provided in paragraph (b) of this section, a line marker must be placed and maintained as close as practical over each buried main and transmission line 192.707

Comments:


SUBPART M - MAINTENANCE PROCEDURES (Transmission only) S U N/A N/C

Transmission Lines – Patrolling & Leakage Survey Procedures

.705 (a) Each operator shall have a patrol program to observe surface conditions on and adjacent to transmission line right-of-way for indications of leaks, construction activity, and other factors affecting safety and operation. Operator procedures must define methods of patrolling including walking, driving, flying, or other appropriate means of traversing the right-of-way.

(b) Maximum interval between patrols of lines

.706 Leakage surveys – 1 year/15 months

Transmission Record-Keeping Procedures

.709 Records must be maintained

(a) Repairs to the pipe – life of system

(c) Operation (Sub L) and Maintenance (Sub M) patrols, surveys, tests – 5 years or until next one

Transmission Line Field Repair Procedures

.713 Repairs of imperfections and damages on pipelines operating above 40% SMYS

(a) Cut out and replace a cylindrical piece of pipe, or use of a reliable engineering method

(b) Reduce operating pressure to a safe level during the repair

.715 Welds found to be unacceptable under §192.241(c) must be repaired by:

(a) Taking the line out of service and repairing in accordance with §192.245: Cracks longer than 8% of the weld length (except offshore) must be removed For each repaired weld, the defect must be removed down to clean metal and the pipe preheated Repairs must be inspected to ensure acceptability Crack repairs or defect repairs in previously repaired areas must be done in accordance with

qualified written welding procedures

(b) If the line remains in service, the weld may be repaired in accordance with §192.245 if:(b)(1) The weld is not leaking (b)(2) The pressure is reduced to produce a stress that is 20% of SMYS or less (b)(3) Grinding is limited so that ⅛ inch of pipe weld remains

(c) If the weld cannot be repaired in accordance with (a) or (b) above, a full encirclement welded split sleeve must be installed


Class Location At Highway and Railroad Crossings

At All Other Places

1 and 2 2/yr (7½ months) 1/yr (15 months)

3 4/yr (4½ months) 2/yr (7½ months)

4 4/yr (4½ months) 4/yr (4½ months)

SUBPART M - MAINTENANCE PROCEDURES (Transmission only) S U N/A N/C

Transmission Line Field Repair Procedures (continued)

.717 Field repairs of leaks must be made by one of the following methods:

(a) Replace by cutting out a cylinder and replace with pipe similar or of greater design

(b)(1) Install a full encirclement welded split sleeve of an appropriate design unless the pipe is joined by mechanical couplings and operates at less than 40% SMYS

(b)(2) A leak due to a corrosion pit may be repaired by installing a bolt-on leak clamp

(b)(3) For a corrosion pit leak, if a pipe is not more than 40,000 psi SMYS, the pits may be repaired by fillet welding a steel plate. The plate must have rounded corners and the same thickness or greater than the pipe, and not more than ½ the diameter of the pipe size

(b)(4) Submerged offshore pipe or pipe in inland navigable waterways may be repaired with a mechanically applied full encirclement split sleeve of appropriate design

(b)(5) Apply reliable engineering method

.719 (a) Replacement pipe must be pressure tested to meet the requirements of a new pipeline

(b) For lines of 6-inch diameter or larger and that operate at 20% of more of SMYS, the repair must be nondestructively tested in accordance with §192.241(c)

Transmission Valves

.745 (a) Inspect and partially operate each transmission valve that might be required during an emergency (1 per yr/15 months)

(b) Prompt remedial action required, or designate alternative valve

Comments:



Distribution System Patrolling & Leakage Survey Procedures

.721 (a) Frequency of patrolling mains must be determined by the severity of the conditions which could cause failure or leakage (i.e., consider cast iron, weather conditions, known slip areas, etc.)

(b)(1) Patrolling surveys are required in business districts at intervals not exceeding 4½ months, but at least four times each calendar year (operator procedures should define “business districts”).(b)(2) Patrolling surveys are required outside business districts at intervals not exceeding 7½ months, but at least twice each calendar year.

.723 (b)(1) Operator procedures call for leakage surveys to be conducted in business districts at least Once per calendar year (at intervals not exceeding 15 months)

(b)(2) Leakage surveys conducted outside of business districts: Once every 5 calendar years (63 months); For unprotected lines subject to .465(e) where electrical surveys are impractical, leakage surveys conducted: Once every 3 calendar years (39 months).

Test Requirements For Reinstating Service Lines

.725 (a) Except for .725(b), disconnected service lines must be tested the same as a new service line.

(b) Service lines that are temporarily disconnected must be tested from the point of disconnection, the same as a new service line, before reconnect.

OAC4901:113(A)(3)

Minimum Gas Service Standards – prior to re-establishing gas service the gas piping downstream of the meter shall be tested by pressure testing, or dial testing when gas service has been off for less than 30 days.Note – OAC rule 13 does not apply to co-ops, municipalities, or other entities that do not operate under a tariff.

Abandonment or Deactivation of Facilities Procedures

.727 (b) Operator must disconnect both ends, purge, and seal each end before abandoning piping in place.

(c) Except for service lines, each inactive pipeline that is not being maintained under Part 192 must be disconnected from all gas sources/supplies, purged, and sealed at each end.

(d) Whenever service to a customer is discontinued, do the procedures indicate one of the following:

- (1) The valve that is closed to prevent the flow of gas to the customer must be provided with a locking device or other means designed to prevent the opening of the valve by persons other than those authorized by the operator

- (2) A mechanical device or fitting that will prevent the flow of gas must be installed in the service line or in the meter assembly

- (3) Customer piping must be physically disconnected from the gas supply and the open pipe ends sealed

(e) If air is used for purging, the operator shall ensure that a combustible mixture is not present after purging



Compressor Station Procedures

.605 (b)(6) Maintenance procedures, including provisions for isolating units or sections of pipe and for purging before returning to service

(b)(7) Starting, operating, and shutdown procedures for gas compressor units

.731 Inspection and testing procedures for remote control shutdowns and pressure relieving devices (1 per yr/15 months). Any defective or inadequate equipment found must be promptly repaired or replaced.

.736 Compressor buildings in a compressor station must have fixed gas detection and alarm systems (must be performance tested), unless:(a)(1) 50% of the upright side areas are permanently open, or(a)(2) It is an unattended field compressor station of 1000 hp or less

Pressure Limiting and Regulating Station Procedures

.739 (a) Inspection and testing procedures for pressure limiting stations, relief devices, pressure regulating stations and equipment (1 per yr/15 months) to determine that it is:

- (1) In good mechanical condition - (2) Adequate from the standpoint of capacity and reliability of operation for the service in which it

is employed - (3) Set to control or relieve at correct pressures consistent with .201(a), except for .739(b). - (4) Properly installed and protected from dirt, liquids, other conditions that may prevent proper

operation

(b) For steel lines if MAOP is determined per .619(c) and the MAOP is 60 psi gage or more:- Pressure limit is MAOP plus 4% if MAOP produces a hoop stress > 72% of SMYS- A pressure that will prevent unsafe operation of the pipeline considering its operation and

maintenance history and MAOP if MAOP produces a hoop stress that is unknown as a percent of SMYS

.741 (a) Each distribution system supplied by more than one district pressure regulating station must be equipped with telemetering or recording pressure gauges to indicate gas pressure in the district.

(b) On distribution systems supplied by a single district pressure regulating station, the operator shall determine the necessity of telemetering / recording gauges based on the number of customers supplied, operating pressures, capacity of the installation, and other operating conditions.

(c) If there are indications of abnormally high or low pressure, the regulator and auxiliary equipment must be inspected and necessary measures employed to correct any unsatisfactory operating conditions.

.743 (a) Pressure relief devices at pressure limiting /regulating stations checked for capacity (1 per yr/15 months)

(b) If review and calculations are used, are capacity calculations updated to reflect current data?

(c) Prompt action to install additional capacity if required



Distribution Valves

.747 (a) Check and service each valve that may be necessary for the safe operation of a distribution system (1 per yr/15 months). Operator should have criterion for identifying critical valves needed to effectively shut down and isolate any section of main in the system.

(b) Prompt remedial action required, or designate alternative valve

Vaults

.749 (a) Inspection of vaults greater than 200 cubic feet (1 per yr/15 months) - Procedures must reflect safe entry of confined spaces- If gas is found, vault equipment must be inspected for leaks and repaired.- Ventilating equipment must be inspected to determine it is functioning properly- Vault covers must be inspected to assure it does not present a hazard

Prevention of Accidental Ignition Procedures

.751 Procedures must reflect the following to reduce the hazard of fire or explosion:- When a hazardous amount of gas is being vented into open air, each potential source of ignition

must be removed from the area and a fire extinguisher must be provided- Gas or electric welding or cutting may not be performed on pipe or on pipe components that

contain a combustible mixture of gas and air in the area of work- Post warning signs, where appropriate.

Caulked Bell and Spigot Joints Procedures

.753 Cast-iron caulked bell and spigot joint repair:

(a) When subject to more than 25 psig, sealed with mechanical clamp, or sealed with material/device which does not reduce flexibility, permanently bonds, and seals and bonds as prescribed in §192.753(a)(2)(iii)

(b) When subject to 25 psig or less, joints, when exposed for any reason, must be sealed by means other than caulking

Protecting Cast-Iron Pipeline Procedures

.755 Segments of cast iron pipeline must be protected from:

(1) Vibrations from heavy construction equipment, trains, trucks, buses or blasting

(2) Impact forces by vehicles

(3) Earth movement

(4) Other foreseeable outside forces which might subject the segment of pipeline to a bending stress

(5) Provide permanent protection for the disturbed section as soon as feasible

Joining plastic pipe by heat fusion – equipment maintenance and calibration

.756 Equipment used in joining plastic pipe is maintained in accordance with the manufacturers recommended practices or with written procedures proven to produce acceptable joints by tests and experience.

Comments:


DAMAGE PREVENTION PROGRAM PROCEDURES

192.614 – Damage Prevention Program S U N/A N/C

(b) Is the operator an Ohio Utilities Protection Service member? Full Member Limited Base Participant

Has the operator registered the location of its underground pipelines with the Ohio Utilities Protection Service?

If the operator finds errors in its facility location information, or finds new development/streets/roads not shown on One Call base maps, is the Ohio Utilities Protection Service informed?

Does the operator notify the Ohio Utilities Protection Service prior to its own excavations?

(c)(1) Does the operator maintain a current list of excavators in the area in which the pipeline is located?

(c)(2) Does the operator have an awareness program to provide notice to the public and to excavators?

(c)(3) Does the operator have a means of receiving and recording notifications of pending excavations?

Is the operator prepared to receive after-hours calls for emergencies?

Do receiving and recording procedures allow for an accurate definition of the excavation site?

(c)(4) Does the operator provide for actual notification of persons who give notice of their intent to excavate of the type of temporary markings to be provided and how to identify the markings?

For full members, does the operator report the appropriate information to the protection service for its positive response system?

For limited base participants, does the operator directly communicate to the excavator the presence or absence of any conflict between the existing underground facilities and the proposed excavation site?

Does the operator respond to Large Project Meet Tickets from the Ohio Utilities Protection Service in order to meet with excavators and establish a marking schedule for large projects? (see http://www.oups.org/)

(c)(5) Does the operator provide temporary markings for the pipeline before excavation begins?

Does the operator locate and mark its underground pipelines within forty-eight hours of receiving notice?

Does the operator mark underground facilities in accordance with the Ohio universal marking standards?

If the operator cannot accurately mark the pipeline, does the operator mark them to the best of their ability, notify the excavator that the markings may not be accurate, and provide additional guidance to the excavator in locating the facilities as needed during the excavation?

For contract locators, do the contractors have access to the same locate information as company personnel?

(c)(6) Does the operator provide for follow-up inspection of the pipeline where there is reason to believe the pipeline could be damaged by excavation activities? (in the case of blasting, does the inspection include leakage surveys?)

Does the operator have directional drilling/boring procedures which include taking actions necessary to protect their facilities from the dangers posed by drilling and other trenchless technologies?

Comments:


EMERGENCY RESPONSE PROGRAM PROCEDURES

192.615 – Emergency Plans S U N/A N/C

(a)(1) Procedures to receive, identify, and classify notices of events requiring immediate response by the operator

(a)(2) Procedures to establish and maintain communication with appropriate police, fire and other public officials

(a)(3) Procedures to ensure prompt response to:Gas detected inside a building; Fire located near a pipeline; Explosion near a pipeline; Natural disaster

PHMSA Area of EmphasisDoes the operator have emergency response procedures for leaks caused by excavation damage near buildings that adequately address the possibility of multiple leaks and underground migration of gas into nearby buildings?

(a)(4) Procedures to identify the availability of personnel, equipment, instruments, tools, and material required at the scene of an emergency.

(a)(5) Procedures identify actions directed towards protecting people first, then property

(a)(6) Procedures for emergency shutdown or pressure reduction to minimize hazards to life or property

(a)(7) Procedures for making safe any actual or potential hazard to life or property

(a)(8) Procedures for coordinating responses with appropriate public officials required at the emergency scene.

(a)(9) Instructions for restoring service outages after the emergency has been rendered safe

(a)(10) Procedures for investigating accidents and failures as soon as possible after emergency

(a)(11) Actions required to be taken by a controller during an emergency in accordance with 192.631

(b)(1) Furnishing applicable portions of the emergency plan to supervisors responsible for emergency action

(b)(2) Training appropriate employees as to the requirements of the emergency plan and verifying effectiveness of training

(b)(3) Reviewing activities following emergencies to determine if the procedures were effectively followed.

(c) Establish and maintain liaison with appropriate public officials, such that both the operator and public officials are aware of each other’s resources and capabilities in dealing with gas emergencies

Comments:


PUBLIC AWARENESS PROGRAM PROCEDURES

192.616 – Public Awareness S U N/A N/C

(a) Has the operator developed and implemented a written continuing public education program that follows the guidelines provided in the American Petroleum Institute (API) Recommended Practice (RP) 1162?

(b) Does the operator‘s program clearly define the specific pipeline systems covered in the program and assess its unique attributes and characteristics? (I.e. compressor stations, valves, odorizers, storage fields, etc.).

(c) Does the operator’s program define the combination of messages, delivery methods, and delivery frequencies to comprehensively reach all affected stakeholder audiences in all areas in which the operator transports gas?

(d) Does the operator‘s program include provisions to identify and educate the following affected stakeholder audience groups: (1) affected public, (2) emergency officials, (3) local public officials, and (4) excavators?

(d) Do the operators public awareness messages specifically include provisions to educate the public, emergency officials, local public officials, and excavators on the:

- Use of a one-call notification system prior to excavation;- Possible hazards associated with unintended releases from a gas pipeline facility;- Physical indications of a possible release;- Steps to be taken for public safety in the event of a gas pipeline release; and - Procedures for reporting such an event.

(e) Does the operators program include activities to advise affected municipalities, school districts, businesses, and residents of pipeline facility locations?

(c) Did the operator’s delivery for materials and messages meet or exceed the baseline frequencies specified in API RP 1162, Table 2-1 through Table 2-3?

- Twice / year for Distribution operators to deliver baseline awareness materials to the Affected Public who are customers of the gas company.

- Once / year for Distribution operators to deliver baseline awareness materials to the Affected Public who reside along the pipeline system.

- Once every 2 years for Transmission and Gathering operators to deliver baseline awareness materials to the Affected Public who reside along the pipeline system.

- Once a year for all operators to deliver baseline awareness materials to Emergency Officials.- Once every 3 years for all operators to deliver baseline awareness materials to Local Public Officials.- Once / year for all operators to deliver baseline awareness materials to Excavators.

(f) Is the operator’s program and media used comprehensive enough to reach all areas where the operator transports gas?

(g) Is the program conducted in English and other languages understood by a significant number of the population?

(c) Did the operator perform an effectiveness evaluation of its program at least once every 4 years, including a stakeholder survey, to assess and improve program effectiveness? The evaluation must include the following:

- Track actual program outreach for each stakeholder audience- Determine the percentage of individuals or organizations actually reached within the target audience- Assess the percentage of the individuals or organizations reached that understood and retained key

information in the messages received- Determine whether appropriate preventive behaviors are understood and are taking place when needed- Identify and document changes to their program based on the results of the evaluation

Comments:


OPERATOR QUALIFICATIONS

Subpart N – Qualification of Pipeline Personnel S U N/A N/C

.805(a) Did the operator’s plan identify covered tasks by applying the four-part test defined in 192.801(b)?

Has the operator defined Abnormal Operating Conditions (AOC) for each covered task?

Have Distribution piping operators incorporated new construction tasks, including riser installation, into their identified covered tasks as required by O.A.C. 4901:1-16-06(D)?

.805(b) Has the operator established and documented the evaluation method(s) appropriate to each covered task?

Can the qualification status of individuals performing covered tasks be verified?

Does the operator have a method of evaluating and qualifying contract employees prior to performing covered tasks to ensure the contract employees can perform these tasks according to operator specific requirements?

,805(c) Has the operator established provisions to allow non-qualified individuals to perform covered tasks while being directed and observed by a qualified individual?

.805(d).805(e)

Has the operator established provisions to evaluate an individual if the operator has reason to believe: the individual is no longer qualified to perform a covered task; or performance of a covered task may have contributed to an Incident as defined in 49 C.F.R. 191?

.805(f) Does the operator’s plan identify how changes to procedures, equipment, and other elements used by

individuals performing covered tasks are communicated to these individuals (including contractors)?

Are changes incorporated in the evaluation method used to determine qualification?

Did the operator follow their plan and communicate changes in covered tasks to affected individuals?

.805(g) Did the operator specify task-specific re-evaluation intervals for each covered task?

.805(h) Has the operator provided training to ensure that individuals performing covered tasks have the necessary

knowledge and skills to perform the task in a manner that ensures the safe operation of pipeline facilities?

Does this training include recognizing and reacting to task specific AOC’s?

Does the operator provide training to contractors performing covered tasks, or has the operator made provisions to ensure training provided to contractors allow them to perform covered tasks according to operator specific requirements?

.807 Does the operator maintain the following records:

- Identification of qualified individuals;- Identification of the covered tasks the individual is qualified to perform;- Dates of current qualification; and- Qualification method(s) used

Are records of prior qualifications and records of individuals no longer performing covered tasks retained for a period of 5 years?

.809 Does the operator plan reflect that a work performance history review or an observation of on-the-job performance may not be used as the sole method of evaluation?


DRUG AND ALCOHOL TESTING PROGRAM

49 C.F.R. 199 – Drug and Alcohol Testing S U N/A N/C

199.101199.202

Does the company have a written anti-drug and alcohol-misuse plan for employees performing covered functions? (i.e., operations, maintenance, or emergency-response. Requirement includes contract employees)

How many employees performing covered functions does the operator have?:

199.105199.225

Does the company perform random drug testing and on-suspicion alcohol testing (unless they are in a FMCSA pool where it’s random) of employees performing covered functions?(Testing must be spread reasonably throughout the calendar year (best practice is at least quarterly and must meet the minimum required annual testing rate, which was 25% for CY2017 and raised to 50% for CY2018)

199.105 Does the company conduct post-accident testing for affected covered function employees as soon as possible but no later than 32 hours after an Incident?

199.113199.241

Does the operator provide training for Supervisors on the detection of potential drug abuse and alcohol misuse? (The operator must provide at least 60 minutes of training each on the detection of drug use and alcohol misuse)

199.113199.239

Does the operator provide an Employee Assistance Program, including:- Display and distribution of informational material- Display and distribution of a community service hot-line telephone number for employee assistance- Display and distribution of the operator’s policy regarding the use of prohibited drugs

199.115199.245

If the operator employs contractors for covered functions, can the operator demonstrate that:- Drug and alcohol testing, education, and training required by this part is provided by the operator;

and/or

- Drug and alcohol testing, education, and training required by this part is carried out by the contractors and records are made available by the contractor for the purpose of monitoring the operator’s compliance with the requirements of this part.

199.119199.229

For operators with more than 50 covered employees, has the operator submitted an annual Management Information System (MIS) report to PHMSA not later than March 15th of each year for the proceeding calendar year?

199.117199.227

Does the operator retain records required by this part?

Comments:


Documents

Checklist - PUCO · Web viewEach valve, fitting, length of pipe, and other component must be marked as prescribed in the specification or standard to which is was manufactured, except