2018 om final draft 2

Gas O&M Plan – Revision 03.18

CITY OF WAUKEE

Utility

GAS SYSTEM OPERATING AND MAINTENANCE

PLAN

Adopted ______________________Date

DEPARTMENT DIRECTOR: John R. Gibson Public Works Director

X_______________________________________________________


GAS SYSTEM OPERATING AND MAINTENANCE PLAN

A Model Plan from the

IOWA ASSOCIATION OF MUNICIPAL UTILITIES 1735 NE 70th Avenue

Ankeny, Iowa 50021-9353 515/289-1999

Disclaimer of Warranty and Limitation of Liability

This model plan has been developed by the Iowa Association of Municipal Utilities to promote the safe operation and maintenance of municipal gas systems and compliance with federal regulation of gas pipeline operators.

This publication is designed to provide accurate and authoritative information in regard to the subject matter covered. It is furnished with the understanding that neither the Association nor its licensed agent is engaged in rendering legal or other professional service. If legal advice or other professional or expert assistance is required, the services of a competent professional person should be sought. This publication is provided "as is" without warranty of any kind, either expressed or implied, including but not limited to the implied warranties of merchantability and fitness for a particular purpose. The entire risk as to the quality, performance, and accuracy of the manual is with the holder.

© Iowa Association of Municipal Utilities, Revised 2018


SCHEDULE OF O&M ACTIVITES

O&M Sec. Activity Code

Reference Frequency Required

Associated Form

2.1 Review/Update O&M Plan 192.605

Every calendar year

not exceeding 15

months

Annual Review of O&M Plan found in Division 2.1

of the O&M Plan

Emergency Plan

Emergency Training (All Employees)

192.615(b) Once

Annually Employee Emergency

Training Record

Emergency Plan

Review/Update Emergency Plan

192.615(a) Once

Annually

Division 1.3 of Emergency Plan & Employee

Emergency Training Record

Emergency Plan

Emergency Training (Operating Personnel)

192.615(b) Once

Annually Employee Emergency

Training Record

Emergency Plan

Emergency Training (Police & Fire Liaison)

192.615(c) Once

Annually

First Responders & Public Officials Emergency

Training Record

3.6 Public Education/Public

Awareness 192.616

At least annually

Public Awareness Plan, API RP 1162 1st Edition

3.6 Update/Review Excavator

List 192.614(c)(1)

192.616 Once

Annually Public Awareness Plan, API

RP 1162 1st Edition

4.2 Transmission/Distribution

Patrolling 192.705 192.721

Determined by Class

Location, up to 4 per year

Trans/Dist Patrolling Report found in Division 10 of the

O&M Plan.

4.3 Transmission/Distribution

Leak Survey's 192.706 192.723

Determined by Class

Location and system

designation.

Leak Survey Report found in Division 10 of the O&M

Plan

4.4 Emergency (Key) Valve

Maintenance 192.745 192.747

Every calendar year

not exceeding 15

months

Valve Inspection & Maintenance Log found in Division 10 of the O&M

Plan

4.5, 4.6 Regulator Station & Relief

Valve Inspection 192.739 192.743

Every calendar year

not exceeding 15

months

Regulator Station Inspection Log found in Division 10 of

the O&M Plan

4.6.2 Farm Tap Regulator & Relief Valve Inspection

192.740

Every 3 years not to exceed 39

months

Farm Tap Regulator and Relief Inspection Form

found in Division 10 of the O&M Plan


4.7 Vault Maintenance 192.749

Every calendar year

not exceeding 15

months

Regulator Station Inspection Log found in Division 10 of

the O&M Plan

5.22.3 Manual Service Line Shut-

off Valve (Curb Valve) Maintenance

192.385


months

Manual Shut-off (Curb Valve) Installation and

Maintenance Form found in Division 10

6.3, 6.6 Corrosion Control

Monitoring 192.465

Every calendar year

not exceeding 15

months

Anode Test Station Report found in Division 10 of the

O&M Plan

6.8 Atmospheric Corrosion

Control Survey 192.481


months

Atmospheric Corrosion Survey found in Division 10

of the O&M Plan

8.1 Odorant Usage 192.625 4 per

calendar year (quarterly)

Rate of Odorization Report found in Division 10 of the

O&M

8.2 Odorant Level 192.625 4 per

calendar year (quarterly)

Odorometer Test Report found in Division 10 of the

O&M

None Lost and Unaccounted -

for-Gas None Annually

Lost and Unaccounted-for-Gas found in Division 10 of

the O&M.

None Annual PHMSA

Distribution Report 191.11

Due by March 15 for the previous calendar year

Form can be accessed through the PHMSA Portal

None Mechanical Fitting Failure

Report 191.12



None Annual PHMSA

Transmission Report 191.17



None National Pipeline Mapping

System Annual Update (Transmission lines)

191.29


Update guidance can be found at

www.npms.phmsa.dot.gov

This schedule does not include all required reporting and recordkeeping. Special PHMSA requirements apply to non-scheduled events, such as incident reports. Other scheduled activities are required under regulations of the Iowa Utilities Board, such as the Annual Report (MG-1) and periodic testing of customer meters

Gas O&M Plan – Revision 03.18 i

GAS OPERATING AND MAINTENANCE PLAN TABLE OF CONTENTS

DIVISION ONE -- PURPOSE AND CONSTRUCTION

1.1 Scope ....................................................................................................................1 1.1.1 Reference Materials.……………………………………………………….…....1 1.2 Purpose .................................................................................................................1 1.3 Construction .........................................................................................................2 1.4 Definitions............................................................................................................2

DIVISION TWO -- EMPLOYEE RESPONSIBILITIES

2.1 O&M Plan Administrator ....................................................................................4 2.2 General Employee Responsibilities and Instructions ..........................................6 2.3 Anti-Drug Plan .....................................................................................................6 2.4 Annual Review of Facilities.................................................................................6 2.5 Additional Responsibilities and Instructions .......................................................6 2.6 National Registry of Pipeline ...............................................................................7

DIVISION THREE -- DAMAGE PREVENTION

3.1 Damage Prevention Program ...............................................................................8 3.2 One Call Notice Required ....................................................................................8 3.2.1 Written Procedures for One-Call Notifications.……………………………….12 3.3 Line Markers ..................................................................................................…13 3.4 Utility Inspection of Excavation Activities........................................................13 3.5 Personnel Precautions in Excavated Trenches ...................................................15 3.6 Public Information & Public Awareness ...........................................................15

DIVISION FOUR -- PIPELINE INSPECTION AND MAINTENANCE

4.1 Pipeline Inspection and Maintenance Procedures (General) .............................17 4.2 Scheduled Patrolling ..........................................................................................18 4.3 Leakage Surveys ................................................................................................20 4.4 Key Valves (Emergency Valves) .......................................................................22 4.5 Regulator Stations ..............................................................................................23 4.6 Testing of Relief Devices at Regulator Stations ................................................24 4.6.1 Pressure Limiting & Regulating Stations: Telemetering or Recording Gauges 25 4.6.2 Pressure Regulating, Limiting & Overpressure Protection (Farm Taps)……...26 4.7 Vault Maintenance .............................................................................................26 4.8 Monitor and Control of Downstream Pressure While By-Passing Regulator Equipment ..........................................................................................................27 4.9 Reporting Safety Regulated Conditions.............................................................27

4.10 Investigation of Failure and Accidents ..............................................................28 4.11 Prevention of Accidental Ignition ......................................................................28 4.11.1 General Prevention of Accidental Ignition........................................................29 4.11.2 General Welding, Cutting and Other Hot Work................................................30 4.11.3 General Isolating Pipeline Segments on Planned Work to Minimize the

Potential of Ignition............................................................................................31

Gas O&M Plan – Revision 03.18 ii

4.11.4 Notifications Prior to Purge of Blowdown.......................................................32 4.11.5 Purging of Pipelines..........................................................................................32 4.12 Transmission Line Record Keeping.................................................................34 4.12.1 Transmission Lines: General Requirements for Repair Procedures.................34 4.12.2 Transmission lines: Permanent Field Repair of Imperfections and Damages..34 4.12.3 Transmission lines: Permanent Field Repair of Welds.....................................35 4.12.4 Transmission lines: Permanent Field Repair of Leaks......................................35 4.12.5 Transmission lines: Testing of Repairs............................................................35

DIVISION FIVE -- OPERATING PROCEDURES

5.0 Operating Procedures (General) ........................................................................36 5.1 General Construction Requirement ....................................................................36 5.2 MAOP Determination and Review ....................................................................40 5.3 Uprating MAOP .................................................................................................40 5.4 Testing for Reinstating Service Lines ................................................................41 5.5 Abandonment or Inactivation of Facilities ........................................................41 5.6 Accidental Ignition of Gas .................................................................................42 5.7 Pipeline Materials (General) ..............................................................................42 5.8 Steel Pipe ...........................................................................................................43 5.9 Plastic Pipe .........................................................................................................44 5.10 Marking of Materials .........................................................................................45 5.11 Qualifying Components .....................................................................................45 5.12 Valves ................................................................................................................46 5.13 Flanges and Flange Accessories ........................................................................46 5.14 Standard Fittings ................................................................................................47 5.15 Tapping ..............................................................................................................47

5.16 Components Fabricated by Welding ..................................................................48 5.17 Pipeline Construction and Leak Repair .............................................................48 5.18 Extruded Outlets ................................................................................................49 5.19 Flexibility ...........................................................................................................49 5.20 Supports and Anchors ........................................................................................49 5.21 Customer Meters/Regulators .............................................................................50 5.21.1 Reinstatement or Installing of Service Lines at Customer Meter ......................52 5.22 Service Lines ......................................................................................................53 5.22.1 Excess Flow Valve (EFV) Performance Standards ...........................................55 5.22.2 Excess Flow Valve (EFV) Installation Requirements………….……………...57 5.22.3 Manual Service Line Shut-off Valve (Curb Valve) Installation………………58 5.23 Cast Iron Pipe .....................................................................................................60 5.24 Pressure Testing Mains and Services .................................................................60

5.25 Pressure Testing Transmission Lines.................................................................61

DIVISION SIX -- CORROSION CONTROL

6.1 Corrosion Control Program................................................................................65 6.2 Protective Coating ..............................................................................................65 6.3 Cathodic Protection ............................................................................................66 6.4 Corrosion Control Requirements (Pipelines Installed After July 31, 1971) .................................67 6.5 Corrosion Control Requirements (Pipelines Installed Before August 1, 1971)..............................67 6.6 Corrosion Control Monitoring ...........................................................................68

Gas O&M Plan – Revision 03.18 iii

6.7 Inspecting Uncovered Pipeline ..........................................................................70 6.8 Atmospheric Corrosion Control and Inspection ................................................71 6.9 Internal Corrosion Control .................................................................................71

DIVISION SEVEN -- WELDING AND JOINING

7.1 Welding and Joining ..........................................................................................73

DIVISION EIGHT -- ODORIZATION

8.1 Odorization (General) ........................................................................................75 8.2 Testing of Odorant Level ...................................................................................75 8.3 Follow-Up Action for Sniff Test Report Over 20% LEL ..................................75

DIVISION NINE -- PEAK SHAVING

9.1 Peak Shaving (General) .....................................................................................76 9.2 Installation and Maintenance .............................................................................76 9.3 Emergency Procedures - Tank Leak ..................................................................76 9.4 Operating Instructions (Reserved) .....................................................................76

DIVISION TEN -- GAS OPERATING AND MAINTENANCE PLAN FORMS………………………………………………………………………...………...77

DIVISION ELEVEN -- DRUG AND ALCOHOL PROGRAM.……………………….122 (Operator to insert their Drug and Alcohol Program)

Gas O&M Plan – Revision 03.18 1

DIVISION ONE PURPOSE AND CONSTRUCTION

1.1 SCOPE

This Operating and Maintenance Plan (O&M Plan) prescribes minimum requirements for inspection, operation and maintenance of all gas pipeline facilities operated by the utility. It is adopted pursuant to requirements of the Code of Federal Regulations, Title 49, section 192.603, 192.13(c), 192.601, 192.605 and is subject to modification from time to time to conform to changes in regulations and utility policy. All work performed on gas pipeline facilities will be in accordance with the O&M Plan. It shall be the utility's responsibility to ensure that all contractors and consultants complete work in accordance with the O&M Plan and to maintain records of work performed under the plan.

1.1.1 REFERENCE MATERIALS

The following is a list of all reference materials that are incorporated into this plan. Any of the additional reference materials or procedures that are used and followed by the gas utility shall be maintained and made available online, stored digitally, or in a separately bound volume.

1. Pipeline Safety Regulations 49 CFR Part 191 Transportation of Natural & Other Gas By Pipeline; Annual Reports, Incident Reports & Safety Related Condition Reports

2. Pipeline Safety Regulations 49 CFR Part 192 Transportation of Natural &Other Gas By Pipeline: Minimum Federal Safety Standards

3. Pipeline Safety Regulations 49 CFR Part 199 Drug and Alcohol Testing 4. Guidance Manual for Operators of Small Gas Systems 5. IAMU Mutual Aid Program 6. IAMU OQ Program 7. NFPA 54 National Fuel Gas Code 8. Iowa Code Chapter 480 9. Iowa Code Chapter 199 10. IAMU Pipeline Welding Manual 11. API Standard 1104 Section 5 &6 of Appendix A & Section 6 & 12 of Appendix B 12. ASME Boiler or Pressure Vessel Code Section

1.2 PURPOSE

The purpose of the plan is to ensure safe and efficient gas service by:

• Protect life first and then property; • Establishing written procedures for inspection, operation and maintenance; • Operating the utility in conformance with the plan; and • Maintaining necessary records to administer the plan.


1.3 CONSTRUCTION (Interpretation)

The plan conforms to and implements applicable provisions of the U.S. Department of Transportation's "Pipeline Safety Regulations" and should be construed in such a manner as to avoid conflict with those provisions.

REFERENCE: 49 CFR Part 191 (including amendments 1 through 8) and Part 192 (including amendments 1 through 65). Content of the plan is based on 49 CFR 192.605 including amendment 59 and on the "Guidance Manual for Operators of Small Gas Systems".

1.4 DEFINITIONS

Unless another meaning is specifically indicated, when used in the plan:

1. Cathodic Protection means the procedure by which underground metallic pipe is protected against corrosion. It is a method for controlling the corrosion or deterioration of steel pipe and connected metallic equipment.

2. Corrosion means the rusting of a metal caused by an electro-chemical reaction between the metal and its surroundings.

3. Customer Meter means a device used to measure the volume of gas transferred from the utility to a customer.

4. Gas means manufactured gas, natural gas, other hydrocarbon gases, or any mixture of gases produced, transmitted, distributed or furnished by the utility.

5. Gas Operator means the utility and its employees and representatives.

6. High Pressure Distribution System means a distribution system in which the gas pressure in the main is higher than the pressure at which gas is provided to the customer.

7. Low Pressure Distribution System means a distribution system in which the gas pressure in the main is substantially the same as the pressure at which gas is provided to the customer.

8. Main means a gas distribution line that serves as a common source of supply for more than one service line.

9. Maximum Allowable Operating Pressure (MAOP) means the maximum allowable pressure at which a pipeline or segment of a pipeline may be operated under 49 CFR 192. MAOP is established by past operating history, pressure testing, and pressure ratings.

10. Meter, without other qualification, means any device or instrument, which is used by the utility in measuring a quantity of gas.

11. No-Flow Test means to turn the gas meter on and observe the test hand (dial) on the meter for 5 minutes. If no movement of the dial is observed for 5 minutes, then it is determined that the no-flow test is successful and the system is ready to be reinstated.


12. Overpressure Protection means equipment installed to prevent pressure in a system from exceeding the maximum pressure limit for safe operation of the system.

13. Pipeline means all parts of those physical facilities through which gas moves in transportation, including pipe, valves, compressor units, metering stations, regulator stations, delivery stations, holders, fabricated assemblies, and other attachments.

14. Pressure is an expression of pounds per square inch above atmospheric pressure, i.e., gauge pressure (abbreviated "psig").

15. Pressure Regulating/Relief Station means an installation designed to automatically reduce and control gas pressure downstream from a high-pressure source of gas into a system operating at a lower pressure. It includes any enclosures, relief devices, ventilating equipment, and any piping and auxiliary equipment, such as valves, regulators, control instruments or control lines.

16. Operating Pressure means the pressure maintained on the gas system. The operating pressure may be less than, but cannot exceed, the MAOP.

17. Riser means the section of a service line that extends out of the ground and is often near the wall of a building. This usually includes a shut-off valve, a regulator, and a unit meter.

18. Service Line means a distribution line that transports gas from a common source of supply to a customer meter or the connection to a customer's piping, whichever is farther downstream, or the connection to a customer's piping if there is not a meter. A customer meter is the meter that measures the transfer of gas from the utility to a customer.

19. Service Regulator means a device that reduces and limits gas pressure to the customer.

20. Shut-Off Valve means a valve used to shut off the gas supply to a customer. The valve may be located ahead of the service regulator, below ground at the property line, or where the service line connects to the main.

21. Transmission Line means a pipeline, other than a gathering line, that:

a. Transports gas from a gathering line or storage facility to a distribution center or storage facility;

b. Operates a hoop stress of 20 percent or more of SMYS; c. Transports gas within a storage field; or d. A large volume customer may receive similar volumes of gas as a distribution

center, and includes factories, power plants, and institutional users of gas.

22. Utility means the municipal gas utility adopting this plan.


DIVISION TWO EMPLOYEE RESPONSIBILITIES

2.1 PLAN ADMINISTRATOR

The following person has primary responsibility for the administration of this plan (also see separate Emergency Plan):

Title (preferred) or Name

Plan administration includes: maintenance of the complete O&M plan, including materials incorporated by reference; distribution of the plan or appropriate parts of the plan to personnel or locations where operation and maintenance activities are conducted; periodic review and update at intervals not exceeding 15 months, but at least once each calendar year; recordkeeping necessary to administer the plan; and, personnel training and work review intended to determine the effectiveness and adequacy of procedures and modification of procedures when deficiencies are found.

REFERENCE: 49 CFR 192.605

ANNUAL REVIEW OF O&M PLAN

Date of Review Sections Reviewed

Reviewed By

3/20/18 ALL 1-11 2018 REVISIONS DDZ,CK,TR,JD,JM

Gas Superintendent


ANNUAL REVIEW OF O&M PLAN

Date of Review Sections Reviewed

Reviewed By


2.2 GENERAL EMPLOYEE RESPONSIBILITIES AND INSTRUCTIONS

The instructions contained in this O&M Plan cover operating and maintenance procedures, which shall be followed during normal operations and while making repairs. REFERENCE: 49 CFR 192.605(a)

Gas department employees and office personnel who may take gas leak calls or requests for pipeline locating are expected to be knowledgeable about those portions of the O&M Plan covering operating and maintenance procedures during normal operation & repairs. Information from any call concerning any abnormal operating condition shall be provided immediately to the operator in charge. All utility employees -- regardless of specific responsibility -- shall be expected to know general procedures to prevent accidental ignition of gas when strong gas odor is detected [see Emergency Plan] as well as utility procedures regarding statements to representatives of the news media or general public.

Personnel who work on pressure control equipment, or who would respond to an emergency at a pressure control station, must be given authority to shut off the gas when pressure control is lost.

In addition to maintaining maps at these locations, pertinent data concerning construction and historical records shall be kept and made available to appropriate operating personnel.

2.3 ANTI-DRUG PLAN

In accordance with 49 CFR 199 (Drug and Alcohol Testing) and 49 CFR 40 (Procedures for Transportation Workplace Drug Testing Programs), an anti-drug plan has been established by the utility under separate cover. All provisions for complying with 49 CFR Parts 199 and 40 are included in the Drug & Alcohol Testing program, which shall be considered part of these operating procedures. All employees and/or contractors who are engaged in operation, maintenance or emergency response functions covered by pipeline safety standards in 49 CFR Part 191 or 192 shall be included in a Drug & Alcohol Testing program.

2.4 ANNUAL REVIEW OF FACILITIES

Each operator will, at least annually, survey and review facilities for changes in class location, failures, leakage history, corrosion, substantial changes in cathodic protection requirements and other unusual operating and maintenance conditions.

2.5 ADDITIONAL RESPONSIBILITIES AND INSTRUCTIONS

Check here if additional instructions are included with this division. Such instructions may include references to other personnel procedures, safety requirements, or communication guidelines not covered in other divisions of this O&M Plan.


2.6 NATIONAL REGISTRY OF PIPELINE

An operator must notify the Pipeline and Hazardous Materials Safety Administration (PHMSA) of any construction, planned rehabilitation, replacement, modification, upgrade, uprate, or updating of your facility, other than a section of line pipe, that costs $10 million or more, 60 days before the event; if it is an emergency, then as soon as practicable. This 60 day notice is also required for construction of 10 or more miles of new or replacement pipeline, an acquisition or divestiture of 50 or more miles of pipeline or pipeline system subject to Part 192, a change in the primary entity responsible for running the system, a change in the entity (ownership), a change in the name of the operator, or an operator converting a pipeline from service not previously covered by 49 CFR Part 192.14.

Reporting: an operator must use their Operator Identification Number (OPID) issued by PHMSA for all reporting requirements.



DIVISION THREE DAMAGE PREVENTION

3.1 DAMAGE PREVENTION PROGRAM (General)

The program outlined in this part is intended to protect lives and property by reducing the chance of damage to utility pipelines during excavation activities.

Each operator is required to notify each customer, in writing, no later than 90 days after the customer first receives gas at a particular location, as per 49 CFR 192.16.

3.2 ONE CALL NOTICE REQUIRED

Any person planning excavation activities is required to contact the "Statewide One Call" toll free number 811 or 800/292-8989 at least 48 hours prior to commencement of the planned excavation, excluding Saturdays, Sundays and legal holidays. All requests for locates received by the Iowa One Call notification center after 5:00 p.m. will be processed as if received at 8:00 a.m. the next business day. Prior to commencement of excavation, the person must obtain verification of the absence or the presence of underground facilities, which shall be marked to identify those facilities. The only exception shall be when an emergency exists. Under such conditions, operations can begin immediately, provided reasonable precautions are taken to protect the underground facilities. The excavator shall notify the notification center as soon as practical. Otherwise excavation shall not commence until locate verification has been received from the utility.

REFERENCE: Chapter 480, Code of Iowa

1. The following information is required for locate requests:

a. The name of the person providing the notice; b. The precise location of the proposed area of excavation, including the range, township, section and quarter section and/or the GPS coordinates, if known; c. The name and address of the excavator; d. The excavator's telephone number; e. The type and extent of the proposed excavation; f. Whether the discharge of explosives in anticipated; and g. The date and time when excavation is scheduled to begin.

For purposes of statutory requirements, an excavation commences the first time excavation occurs in an area that was not previously identified by the excavator in an excavation notice.

2. Responsibilities of the Utility and Excavators -- When the utility receives notice from the One-Call center, it will mark the horizontal location of its underground facilities in accordance with section 480.4(c) Code of Iowa and the excavator shall use due care in excavating in the marked area to avoid damaging the underground facility.

The utility shall complete such locating and marking within 48 hours after receiving the notice, excluding Saturdays, Sundays, and legal holidays, unless otherwise agreed by the utility and the excavator. The locating and marking of the underground facilities shall be


completed at no cost to the excavator. If, in the opinion of the utility, the planned excavation requires that the precise location of the underground facilities be determined, the excavator, unless otherwise agreed upon between the excavator and the utility, shall hand dig test holes to determine the location of the facilities unless the utility specifies an alternate method.

The marking required under this subsection shall be done in a manner that will last for a minimum of five working days on any nonpermanent surface, or a minimum of ten working days on any permanent surface. If the excavation will continue for any period longer than such periods, the utility shall remark the location of the underground facility upon the request of the excavator. The request shall be made through the notification center.

If the utility receives notice from the One-Call center and determines that there are no underground facilities located within the proposed area of excavation, it shall make a reasonable attempt to notify the excavator concerning this determination prior to the indicated date of commencement of excavation.

3. Receiving and Recording Locate Requests -- The utility shall maintain a log of requests for pipeline location, which will be retained for a minimum of five years following the request. Part of the information that needs to be recorded on the locate tickets is the name of the locator and the dates and times of the locate to demonstrate compliance with Iowa One Call laws and OQ requirements.

Upon completing the locating and marking of their underground facilities or that no lines exist and it is all clear, all underground facility operators shall notify (positive response) the Iowa One Call (IOC) notification center that the marking is complete within forty-eight hours after receiving the locate notice from Iowa One Call, excluding Saturdays, Sundays, and legal holidays. All operators shall use the web-based Electronic Positive Response System (EPRS) to provide this notice (“ticket status”) to the IOC notification center.

4. Excavators will be required to “white-line” the proposed area of excavation (with exceptions). At the time of giving notice to the Iowa One Call notification center, an excavator shall use white paint, white flags, white stakes, or a combination thereof, to mark the proposed area of excavation unless one of the following applies:

a. The precise location, direction, size, and length of the proposed excavation area can be clearly and adequately defined and described at the time the notice is made to the notification center or during an onsite preconstruction meeting.

b. Electronic means of white-lining is supported by the notification center and used by the excavator. c. Physical pre-marking can be shown to be impractical.

Other methods of communications, agreed upon by the operator/locator and the excavator, may provide additional communications alternatives to white-lining.


5. Verification and Marking -- The utility shall determine the presence of municipal pipelines in the work area and provide temporary marking where utility lines are present. The utility shall complete such locating and marking within 48 hours after receiving the notice, excluding Saturdays, Sundays and legal holidays, unless otherwise agreed by the utility and the excavator.

Pipelines shall be marked with flags, paint, or stakes using the following color code:

Yellow = Natural Gas Red = Electric Blue = Water Orange = Communications Green = Sewer Fluorescent Pink = Temporary Survey Markings Fluorescent White = Proposed Excavation

Excavators should never use line markers as absolute guides for close proximity digging with power equipment.

6. If all of the locating and marking of underground facilities has been completed prior to the expiration of the forty-eight-hour period then the excavator may proceed with

excavation upon being notified by the Iowa One Call Electronic Positive Response System that the locating and marking of all underground facilities is complete.

7. No excavation can occur within twenty-five feet of a natural gas transmission pipeline, unless there is a representative of the pipeline present at the proposed area of excavation (with exceptions). Unless otherwise agreed by the operator and excavator in writing, no excavation shall be performed within twenty-five feet of an underground natural gas transmission line as defined in 49 C.F.R. 192.3 unless a representative of the operator of the underground natural gas transmission line is present at the planned excavation area. This requirement shall not apply, however, when a representative of the operator fails to be present at the proposed excavation area at the time the work is scheduled to commence or as otherwise agreed by the operator and the excavator in writing. In this event, the excavator shall notify the operator that the representative failed to appear, and then excavation operations can begin, provided the excavator uses due care to avoid damaging the underground facilities.

DOCUMENTATION: Excavation “Stand-by” Report

8. Damage Report to Utility -- An excavator shall, as soon as practical, notify the utility when any damage occurs to an underground facility as a result of an excavation. If a major emergency occurs 911 also needs to be called, whether caused by excavator or operator. The notice shall include the type of facility damaged and the extent of the damage. If damage occurs, an excavator shall refrain from back filling in the immediate area of the underground facilities until the damage has been investigated by the utility, unless the utility authorizes otherwise. If the damage results in an emergency, the excavator shall take all reasonable actions to alleviate the emergency, including, but not limited to, the evacuation of the affected area. The excavator shall leave all equipment situated where the equipment was at the time the emergency was created and


immediately contact the utility and appropriate authorities and necessary emergency response agencies.

9. After-hours Emergency Locate Requests -- The utility shall have a process in place so that the Iowa One Call center has after-hour contact information available to them to contact the utility for emergency locates.

10. Life of a Ticket -- All locate notices shall be valid for twenty calendar days from the date the notice, as provided by the excavator, was received by the Iowa One Call notification center. If an excavation will continue for periods longer than twenty calendar days, the excavator shall notify the Iowa One Call notification center and request a new locate ticket.

11. While the EPRS shall be the only method used for transmitting electronic ticket status, excavators, operators and the notification center are not precluded from engaging in other forms of communication as needed.

12. If a utility finds errors or omissions in their facility location information or has new streets and/or developments, Iowa One Call needs to be contacted so that One Call maps are updated.

REFERENCE: 49 CFR 192.603, 192.614, 192.615, Chapter 480, Code of Iowa


3.2.1 WRITTEN PROCEDURES FOR ONE-CALL NOTIFICATIONS

The following notification procedure is provided for receiving locate requests from Iowa One-Call during working hours and for after-hours emergency locate requests.

Fax #:

Email:

Phone #:

Fax#:

Email:

One-Call Notification Procedures

(or name of Locating Service)

Receiving and recording notification of excavation activities in your area.

Working Hours Procedures

Office Address:

(list all #'s provided to One-Call as emergency

contacts)

Pager # (if applicable):

Qualified Locating Personnel:

Primary method of receiving One-Call notice(fax, email, both):

Once received, the notification is forwarded on to:(If required to be forwarded on to the Operator, list

Operator names and/or name of Locating Service)

After Hours/Emergency Locate Procedures

Emergency # provided to One-Call:


3.3 LINE MARKERS

Line markers are placed over buried pipelines and along above-ground pipelines in accordance with the requirements of applicable federal regulations. Some provisions of the program are carried out in lieu of the installation of line markers on mains in Class 3 locations, although the utility may install line markers at locations where additional safeguards are deemed prudent.

1. Buried Mains & Transmission Pipelines -- A line marker must be placed and maintained as close as practical over each buried distribution main and/or transmission pipelines at each crossing of a highway, street, or railroad. A line marker must also be placed wherever necessary to identify the location of the main to reduce the possibility of damage or interference. Because the utility participates in a statewide One-Call system, line markers are not required for buried mains in Class 3 or 4 locations and when transmission lines are in Class 3 or 4 locations where placement of a line marker is impractical.

NOTE: Class locations are defined in 49 CFR 192.5

2. Mains & Transmission Pipelines above Ground -- Line markers must be placed and maintained along each section of a main and/or transmission pipeline that is located

above ground in an area accessible to the public. This includes above ground valves and regulator stations.

3. Markers -- The following must be written legibly on a background of sharply contrasting color on each line marker:

a. The words "Warning," "Caution," or "Danger" followed by the words "Gas (or name of gas transported) Pipeline." Letters must be at least 1 inch high with ¼ inch stroke. b. The name of the utility and the telephone number (including area code) where the

utility can be reached at all times. c. The One-Call number for locate requests will also be listed and identified.


3.4 UTILITY INSPECTION OF EXCAVATION ACTIVITIES

1. The utility shall make on-site inspections whenever there is reason to believe the activities could damage gas pipe. In determining the frequency and extent of inspection, the utility shall consider the following:

a. Type and duration of activities. b. Proximity of pipelines to excavation. c. Type of excavation equipment being used. d. Consequences of pipeline hit at work site. e. Past experience with excavator. f. Pipeline material.

In any case where excavation has included blasting, a subsequent leak survey shall be made using gas detection equipment.


1. SUBSTRUCTURE DAMAGE PREVENTION GUIDELINES FOR DIRECTIONAL DRILLING AND OTHER TRENCHLESS TECHNOLOGIES -- These guidelines are general in nature and contain some recommended procedures. Precautions recommended by manufacturers of trenchless technology equipment should be reviewed prior to construction. Applicable state and local requirements for damage prevention should be followed. When installing gas facilities by directional drilling, precautions to take may include the following:

a. Using one-call notification system(s), if available, to have facilities within the immediate area located and marked; and, directly contacting known, non-participating utility owners for facility location.

b. Ensuring that known facilities are located and marked prior to commencing work. c. Exposing facilities within the immediate work area by hand excavation (also

includes vacuum exposing) before starting a bore if the depths of the facilities are not established by other means. Check depth by; either by exposing all existing underground facilities or verifying the depth locator equipment prior to construction by making a practice run checking the depth, and exposing the line and measuring the depth.

d. Considering sewer systems within the area. Sewer systems are especially vulnerable to damage from boring operations for the following reasons:

i. Lines are often non-metallic, making them difficult to locate. ii. Clean-outs or other indications of laterals may be hidden or no existent. iii. Damage may not be readily apparent when a sewer, particularly a gravity

flow system, is pierced by a boring machine. e. Notifying residential and business neighbors in the area of impending work. f. Checking local regulations for the minimum separation distances between the new

gas line and the other facilities. g. Making arrangements with local authorities for traffic control, as necessary. h. Ensuring adequate clearance of overhead electric, telephone, or cable lines.

2. PROTECTING EXISTING GAS FACILITIES -- When excavations near gas facilities will be conducted with directional drilling or by using other trenchless technologies (either by the operator or by a third party), the operator should consider the following:

a. When it is anticipated that the bore will cross or come within a zone (established by the operator or governing regulatory body) near the edge of an underground facility, expose that facility to determine its precise location to ensure adequate separation between the existing and proposed facilities.

b. When the bore will run parallel to an existing facility, expose that facility (pothole) or use locating technology to verify that adequate clearance is maintained between the bore and the existing facilities during the boring operation (for both the drilling of the pilot hole and the back reaming operation). Calculation of the separation distance should account for the largest diameter back reamer that will be used in the boring process.

c. Where potholes are used for visual inspection, they should be placed at intervals that will ensure that clearance is maintained during boring operations. Factors to consider for pothole intervals, include the following:

i. Proximity of proposed bore path to the pipeline facilities. ii. Type of facility (existing and proposed). iii. Type of soil.


iv. Size and controllability of the bore. d. Locating the existing facility and the newly installed facility to ensure that the

installation is in the intended location. e. Conducting a leakage survey over pipelines that could have been affected by the trenchless installation.


3.5 PERSONNEL PRECAUTIONS IN EXCAVATED TRENCHES

Adequate precaution shall be taken to protect personnel from the hazards of unsafe accumulations of vapor or gas. The definition of an unsafe accumulation of gas is a reading of 10% of the Lower Explosive Limit (L.E.L.). When required, emergency rescue equipment, including but not limited to, breathing apparatus, fire protection suit, fire extinguisher placed upwind as close to the excavation as possible, rescue harness and lines shall be provided at the excavation site. In a trench that contains gas, there shall be at least one other person present to provide aid to the person in the trench (i.e. pull rescue line, operate the fire extinguisher, etc.) if needed.


3.6 PUBLIC INFORMATION & PUBLIC AWARENESS

For maximum effectiveness of the damage prevention program and safety of the general public, program information shall be disseminated to persons known to engage in excavation activities, the general public, public officials and emergency responders. See Public Awareness Program for specific program requirements.

1. The utility policy shall be, periodically throughout the year, the program manager shall establish a Public Awareness Program to inform customers, the general public, excavators, public officials and emergency responders how to recognize, report and respond to a gas emergency.

The manager shall be responsible for local supervision of a designated person to schedule periodic informational data.

2. Information data required shall be:

a. Information about gas. b. How to recognize gas odors. c. The do's and don'ts when gas odor is strong. d. 24-hour emergency and office telephone numbers. e. Information shall be in English and in other languages commonly understood by a significant number and concentration of the non-English speaking population in the operator’s area. f. Iowa one-call system. g. Prior to any excavation, an excavator must contact the notification center (Iowa one-call system) and provide notice of the planned excavation. This notice must be given at least 48-hours prior to the commencement of the excavation, excluding Saturday, Sunday, and legal holidays.


h. The information shall be conveyed to the public by: i. Hand-outs at the office. ii. Bill stuffers if applicable. iii. Radio and TV (if available). iv. Newspaper. v. Service man contacts. vi. Public meetings.

i. Customer Owned Piping: i. New customer shall be notified within 90 days of receiving service as

required by 49 CFR 192.16. If the operator does not maintain customer owned piping then the operator needs to give the customer the following information periodically. Below is an example of the notification that can also be found on the IAMU website.

As your natural gas distributor, City of Waukee Municipal Utilities, in accordance with federal regulations, wishes to make you aware of certain safety recommendations regarding your underground natural gas piping.

City of Waukee Municipal Utilities operates our gas system with an emphasis on safety. We are required to design, operate and maintain our underground natural gas pipeline in accordance with prescribed federal safety standards. The gas system does not maintain the gas piping that is customer owned, after our meter and regulator. These lines feeding a structure or a gas burning appliance are the responsibility of the customer who owns that piping. If the buried pipe is not properly maintained, it may be subject to corrosion (if the piping is metallic) and/or leakage.

To ensure the continued safe and reliable operation of these lines, the buried piping should be leak checked periodically. When excavating, the piping should be located in advance, and any excavation of the pipeline should be done by hand. You (or the building owner) are advised to contract a licensed plumber or heating contractor to assist you in locating and inspecting your buried gas piping. If any unsafe condition is discovered, repairs should be made ASAP.

If we can answer any questions regarding this notice, please give us a call at 515-978-7920. Please disregard this notice if you do not have or no longer have buried piping beyond the gas meter.

Documentation must be made of all new customers who receive the “Customer Owned Piping” notification proving the receipt of the notice within 90 days of receiving service. These records must be maintained for at least 3 years.

Documentation: Customer Owned Piping & EFV Notification Record may be used as a record keeping form.

REFERENCE: 49 CFR 192.16, 192.614; 192.616


DIVISION FOUR PIPELINE INSPECTION AND MAINTENANCE

4.1 PIPELINE INSPECTION AND MAINTENANCE PROCEDURES (General)

The inspection and maintenance procedures contained in this part shall constitute a minimum plan and procedures for inspecting and maintaining the utility's pipeline. Patrolling, leakage surveys, and the inspection and servicing of key valves and regulator station components shall be in accordance with these procedures. In addition to scheduled inspections, all utility personnel are expected to watch for and report any operating conditions and activities that may present a hazard to the continued safe operation of the system.

1. Continuing Surveillance: The operator shall have a procedure for continuing surveillance of its facilities to determine and take appropriate action concerning changes in class locations, failures, leakage history, corrosion, substantial changes in cathodic protection requirements, and other unusual operating and maintenance conditions.

If a segment of pipeline is determined to be in unsatisfactory condition but no immediate hazard exists, the operator shall initiate a program to recondition or phase out the segment involved, or, if the segment cannot be reconditioned or phased out, reduce the maximum allowable operating pressure in accordance with 49 CFR 192.619 (a) and (b).

2. The operator must take all practicable steps to protect each transmission line or main from washouts, floods, unstable soil, landslides, or other hazards that may cause the pipeline to move or to sustain abnormal loads.

Each aboveground transmission line or main, not located offshore or in inland navigable water areas, must be protected from accidental damage by vehicular traffic or other similar causes, either by being placed at a safe distance from the traffic or by installing barricades.

Any unsafe section of the pipeline that is determined to be unsafe must be repaired, replaced, or removed from service.

DESIGN: Any new construction must meet the requirements of 49 CFR 192 Subpart D.

All new construction must be inspected according to 49 CFR 192 Subpart G before putting into service.

REFERENCE: 49 CFR 192.605, 192.613, 192.703, Subpart G, H, L & M, Leak Investigation Report


4.2 SCHEDULED PATROLLING

1. Distribution system: The utility shall inspect mains located in places or on structures where anticipated physical movement or external loading (weight, traffic) could cause failure or leakage. These places or structures include bridges, railroad or highway crossings, waterways, land slide areas, areas susceptible to earth subsidence (cave-ins), or areas of construction activity. Patrolling in business districts of these mains must be at quarterly intervals (not exceeding 4-1/2 months but at least four times each calendar year). Patrolling outside business districts at least twice each calendar year (not to exceed 7-1/2 months). Patrolling can be done by walking along the pipeline and observing factors affecting safe operation.

DOCUMENTATION: Leak Survey Report and Transmission & Distribution Patrolling Report (For Patrols of Areas Susceptible to Abnormal Physical Movement). The Transmission & Distribution Patrolling Report is to be completed for all scheduled patrols and may be completed to document unscheduled patrols. REFERENCE: 49 CFR 192.721

2. Transmission lines: The utility shall inspect surface conditions on and adjacent to the transmission line right-of-way for indications of leaks, construction activity, and other factors affecting safety and operation.

The frequency of patrols is determined by the size of the line, the operating pressures, the class location, terrain, weather, and other relevant factors.

Intervals between patrols may not be longer than prescribed in the following table:

Method of patrolling includes walking, driving, flying, or other appropriate means of traversing the right-of-way.

3. Patrolling Transmission Line for the Integrity Management Plan (IMP): Frequency of patrolling the transmission line is set forth in the table above. Documentation of these patrols are required as part of an integrity management inspection. Patrols and evaluations in regards to the integrity management rule need to evaluate for new information that may trigger a High Consequence Area (HCA) along a segment of the pipeline. Include in the evaluation the following issues:

Maximum Interval Between Patrols

Class location of line

At highway and railroad crossings At all other places

1, 2 7-1/2 months; but at least twice each

calendar year. 15 months; but at least once each

calendar year.

3 4-1/2 months; but at least four times each

calendar year. 7-1/2 months; but at least twice

each calendar year.

4 4-1/2 months; but at least four times each

calendar year. 4-1/2 months; but at least four

times each calendar year.


a. Changes in pipeline MAOP,

b. Pipeline modifications affecting piping diameter,

c. Changes in commodity transported,

d. Identification of new construction in the vicinity of the pipeline that results in additional buildings intended for human occupancy or additional identified sites,

e. Change in the use of existing buildings (e.g., hotel or house converted to nursing home,

f. Installation of new pipeline,

g. Change in pipeline class location,

h. Pipeline rerouted,

i. Corrections to erroneous pipeline center line data,

j. Field design changes (addition of taps, maintenance, pressure settings, etc.) affecting line pressure, diameter, or pipeline location.

4. When newly identified HCAs are identified due to such things as when a population

distribution changes or new sites that are occupied by 20 or more persons are identified.

Operators must consider such changes to determine whether new HCAs have been

created. A newly identified HCA must be incorporated into an integrity management

program (including the baseline assessment plan) within one year of its identification.

5. Under § 192.903 the definition of high consequence area (HCA); Method 2 was used along the entire transmission line to identify the HCA areas by using the potential impact radius (PIR).

The potential impact radius is calculated for the transmission pipeline using the

following formula:

PIR = 0.69 *

Where:

PIR = Potential Impact Radius (in feet)

p = maximum allowable operating pressure (in pounds per square inch)

d = pipe outer diameter (in inches)

Example: a transmission line has 4.5” OD pipe and the MAOP is 100#. Calculate –

4.5² x 100# = 2025, 2025 = 45 x 0.69 = 31.05’ or rounded up to 32’

MAOP Pipe OD PIR 100# 4.5” 32’

2*dp


6. Identified Sites: An identified site is an area where people congregate near the pipeline meeting one of three criteria:

a. It is an outside area or open structure occupied by 20 or more persons on more than 50 days in any 12-month period (the days need not be consecutive).

b. It is a building occupied by 20 or more persons on at least 5 days a week for 10 weeks in any 12-month period (the days and weeks need not be consecutive), or

c. It is a facility occupied by persons of limited mobility, e.g., hospitals, prisons, day-care facilities, schools, retirement communities or assisted living centers.

See below for a brief overview of the class locations:

Class 1 10 or fewer buildings intended for human occupancy.

Class 2 10 - 46 buildings intended for human occupancy.

Class 3 (1) 46 or more buildings intended for human occupancy.

(2) Pipeline lies within 100 yards of specified heavily

used facilities.

Class 4 Buildings are mostly four or more stories above ground.

7. Each year transmission operators are required to file one National Pipeline Mapping

System (NPMS) submission. The submission reflects data as of December 31 of the

previous year and that it is submitted between January 1 and March 15. Go to

www.npms.phmsa.dot.gov for more information.

REFERENCE: 49 CFR 192.721, 192.705, 192.905

4.3 LEAKAGE SURVEYS ON THE DISTRIBUTION & TRANSMISSION SYSTEMS

Note: Gas leak detection equipment must be calibrated according to the manufacturer’s recommended procedures for that specific instrument. Any instrument without a valid calibration shall not be used for any type of gas detection until the instrument has been calibrated.

Leak surveys shall be conducted at scheduled intervals and at other times when conditions warrant. Reports of suspected leaks shall be treated as leaks and inspected in the manner prescribed in the Emergency Procedures Manual. In the event a leak is found, procedures (including documentation) outlined in the Emergency Procedures Manual shall be followed.

DOCUMENTATION: Leak Survey Report or a written report from a qualified contractor.

REFERENCES: 49 CFR 192.723 For general information on methods of leak detection see the "Guidance Manual for Operators of Small Gas Systems" current edition. Survey frequencies are indicated as minimum and if special conditions including but not limited to; material makeup, age of pipe, operating pressure, class location, construction, blasting or heavy traffic, the survey schedule will be increased.


1. Distribution Leak Survey Frequency

a. Survey of Business District -- A survey of the business district using gas detection equipment shall be conducted at intervals not exceeding 15 months, but at least once each calendar year. The survey shall include tests of the atmosphere of all utility manholes, storm sewer inlets, cracks in pavement and sidewalks, and at other locations providing an opportunity for finding gas leaks.

b. Survey of Outside Business Area -- Areas outside the principal business districtshall be surveyed at intervals of five calendar years not to exceed 63 months. The survey shall be conducted with gas detection equipment. In the case of lines that do not have cathodic protection and on which electrical surveys for corrosion are impractical, survey intervals will be 3 calendar years not to exceed 39 months.

2. Transmission Leak Survey Frequency

a. Transmission lines will be surveyed each calendar year at intervals not to exceed 15 months, but at least once each calendar year.

b. Transmission lines with unodorized gas must be surveyed using leak detection equipment. Intervals are as follows:

i. In Class 3 locations, at intervals not exceeding 7-1/2 months, but at least twice each calendar year; and

ii. In Class 4 locations, at intervals not exceeding 4-1/2 months, but at least four times each calendar year.

c. Pipelines operating under 30% SMYS in a Class 3 or 4 locations but not in a high consequence area.

i. Perform semi-annual leak surveys (quarterly for unprotected pipelines or cathodically protected pipelines where electrical surveys are impractical).

AND

ii. Either monitor excavations near the pipeline, or conduct patrols as required by §192.705 of the pipeline at bi-monthly intervals. If an operator finds any indication of unreported construction activity, the operator must conduct a follow up investigation to determine if mechanical damage has occurred.

REFERENCES: 49 CFR 192.605(e), 192.615, 192.706, 192.723, 192.935


4.4 KEY VALVES (Emergency Valves)

Valves necessary for the safe operation of the distribution and transmission system shall be inspected and maintained to ensure that they can be found, accessed, and operated for the purpose for which they are intended. Key valves are necessary to shut down the system or a portion of the system in case of emergency. The criteria for determining the necessity of "key" designation include consideration of the time required to restore service by available personnel. Key valves shall be clearly marked on a system map, readily available to operating personnel.

Each regulator station controlling the flow or pressure of gas in a distribution system must have a valve installed on the inlet piping at a distance from the regulator station sufficient to permit the operation of the valve during an emergency that might preclude access to the station.

NOTE: When an operator relies on gas suppliers valve as an emergency shut off, the operator must obtain a copy of the valve maintenance records.

1. Maintenance Schedule -- Key valves shall be checked at intervals not exceeding 15 months, but at least once each calendar year. In the event that a valve is re-designated, i.e., given a designation other than key valve, maintenance would be done at intervals not exceeding three years.

2. Maintenance Requirements -- All valves shall be fully operated at the time of inspection. If full operation is not feasible, the valve shall be operated a minimum of 1/8th turn. Valves directly upstream of a regulator that are fully operated shall be gradually reopened to avoid potential regulator damage.

3. Valves requiring lubrication shall be lubricated in accordance with the manufacturer's recommended procedures. Care shall be exercised to avoid over lubrication, particularly on valves directly upstream of regulators.

4. Below grade installations with valve boxes shall be cleared of debris so that the valve stem is accessible for proper operation. Vault floors shall also be cleared so that they are reasonably free from debris. Valves, except valve box installations, shall be checked for adequate paint to prevent atmospheric corrosion.

5. If a key valve is found to be inaccessible or inoperable the operator must start remedial action within 90 days of discovery to correct the valve, and complete repairs prior to next inspection date within next 12 months not to exceed 15 months, unless the operator designates an alternative valve.

DOCUMENTATION: Valve Inspection and Maintenance Log

REFERENCES: 49 CFR 192.181, 192.745, 192.747


4.5 REGULATOR STATIONS

At annual intervals, not exceeding 15 months but within each calendar year, all district regulator and pressure relief devices must be inspected for parts showing damage or excessive wear. The regulators must be cleaned of valve grease or other foreign materials, checked for free operation and inspected for damage.

If lockup is obtained within the parameters specified for that regulator and the set points are checked, no further testing is required. If lockup cannot be obtained, regulators shall be rebuilt or replaced, and orifices must be carefully checked for nicked or uneven edges against which valve discs seat.

The set point has to be checked on each monitor regulator and relief valve to insure that it will operate within the pressure override range allowed by federal regulations (192.201). To avoid creating problems internally it is recommended that you isolate the relief and check set point with air or gas.

When a gas supplier(s) provides pressure control, the operator must obtain the regulator station annual inspection reports from that gas supplier(s).

NOTE: Verify that supplier equipment, regulators or relief has not changed since last inspection. In the event of abnormal regulation conditions for which no other cause can be located and corrected, regulators must be serviced as described in the preceding paragraph at that time.

A general inspection must be made of district regulator stations including by-pass piping. Part failures must be examined and piping cleaned for rust and foreign material. Supports for piping assembly must be checked to assure that they are supporting and not straining the assemblies on which they bear. By-pass valves must be operated to assure free movement. Corrosion or any abnormal condition should be noted and corrective action taken as indicated.

1. Location -- Regulator stations are marked on the system map(s).

2. Inspection -- Inspections of regulator stations shall be made to ensure that equipment and facilities are:

a. In good mechanical condition. b. Adequate for capacity and reliability. c. Set to function at correct pressure. (The over pressure protection device must not be

set higher than the MAOP plus allowable override.) d. Properly installed and protected in accordance with manufacturer's specifications

retained for reference by the utility.

3. Start up and shut down procedures -- As part of the regular inspection and at any time shut down is required, the procedures listed below shall be followed.

a. Removing district regulator station from service: i. Turn off downstream flow valve. ii. Turn off upstream valve and pilot valves. iii. Turn off downstream pilot valves. iv. District regulator station is now out of service.


b. Returning district regulator station to service: i. Turn on upstream valve and pilot valves. ii. Turn on downstream pilot valves. iii. Visually check gauges for regulator lock-up pressure. iv. Slowly turn on downstream flow valve, monitoring the pressure gauge until

fully open to insure MAOP and allowable build-up is not exceeded. v. District regulator station is now back in service.

A simple lock up test will be performed annually in accordance with the manufacturer's specifications. In the event district-type regulators are not designed to lock up, they will be tested in accordance with manufacturer's specifications. Permanent records of inspections will be kept, including a record of as-found and as-left set points.

NOTE: When a gas supplier(s) provides pressure control, the operator must obtain the regulator station annual inspection reports from that gas supplier(s).

DOCUMENTATION: Regulator Station Inspection Report and Relief Valve Inspection Report. REFERENCES: 49 CFR 192.195, 192.199, 192.203, 192.605, 192.739, 192.741, and 192.743. For general information on regulators and relief devices see the "Guidance Manual for Operators of Small Gas Systems."

4.6 TESTING OF RELIEF DEVICES AT REGULATOR STATIONS

Testing of relief devices shall be in accordance with the following:

1. Pressure relief devices at pressure limiting stations and pressure regulating stations must have sufficient capacity to protect the facilities to which they are connected. Except as provided in Section 5.5 of this plan, the capacity must be consistent with the pressure limits of §192.201(a). This capacity must be determined at intervals not exceeding 15 months, but at least once each calendar year, by testing the devices in place or by review and calculations.

2. If review and calculations are used to determine if a device has sufficient capacity, the calculated capacity must be compared with the rated or experimentally determined relieving capacity of the device for the conditions under which it operates, i.e. inspecting for changes made that would alter the capacities of the regulator or relief devises. After the initial calculations, subsequent calculations need not be made if the annual review documents that parameters have not changed to cause the rated or experimentally determined relieving capacity to be insufficient.

3. If the relieving device is of insufficient capacity, a new or additional device must be installed to provide the additional capacity required.


4. Records of inspections must be retained in a permanent file to show that the relief capacity or the validity of the relief calculations was checked each year. Station inspections should include a check for anything that might affect the validity of the calculations.

NOTE: When a gas supplier(s) provides pressure control, the operator must obtain the regulator station annual inspection reports from that gas supplier(s) and review the capacities.

DOCUMENTATION: Relief Valve Inspection Report REFERENCE: 49 CFR 192.199, 192.201, 192.739, and 192.743

4.6.1 PRESSURE LIMITING AND REGULATING STATIONS: TELEMETERING OR RECORDING GAUGES

Multiple pressure regulating stations controlling distribution pressure must have either telemetering or recording gauges.

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

On distribution systems supplied by a single district pressure regulating station, the operator shall determine the necessity of installing telemetering or recording gauges in the district, taking into consideration the number of customers supplied, the operating pressures, the capacity of the installation, and other operating conditions.

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

REFERENCE: 49 CFR 192.199, 192.741, Subpart D


4.6.2 PRESSURE REGULATING, LIMITING & OVERPRESSURE PROTECTION: INDIVIDUAL SERVICE LINES CONNECTED TO TRANSMISSION LINES (FARM TAPS)

1. This procedure applies to any service line directly connected to a production, gathering, or transmission pipeline. Example: Farm taps.

2. Each pressure regulating or limiting device, relief device (except rupture discs), automatic shutoff device, and associated equipment must be inspected and tested at least once every 3 calendar years, not exceeding 39 months, to determine that it is:

a. In good mechanical condition. b. The regulator and relief are adequate from the standpoint of capacity and reliability

for the service they are installed on. c. Set to control or relieve at the correct pressure consistent with the pressure limits of

§ 192.197. Limit the pressure on the inlet of the service regulator to 60 psi gauge or less in case the upstream regulator fails to function properly.

d. Properly installed and protected from dirt, liquids, or other conditions that might prevent proper operation.

NOTE: Farm tap pressure regulating and relief inspections may be recorded on the Farm Tap Regulator & Relief Inspection Form located in Division 11 of this O&M.

REFERENCE: 49 CFR 192.740, Subpart M

4.7 VAULT MAINTENANCE

Vault maintenance shall be in accordance with the following:

1. Each vault housing pressure regulating and pressure limiting equipment, and having a volumetric internal content of 200 cubic feet or more, must be inspected at intervals not exceeding 15 months, but at least once each calendar year, to determine that it is in good physical condition and adequately ventilated.

2. If gas is found in the vault, the equipment in the vault must be inspected for leaks, and any leaks found must be repaired.

3. The ventilating equipment must be inspected to determine that it is functioning properly.

4. Each vault cover must be inspected to assure that it does not present a hazard to public safety.



4.8 MONITOR AND CONTROL OF DOWNSTREAM PRESSURE WHILE BY- PASSING REGULATOR EQUIPMENT

If it is necessary to bypass pressure controlling or regulating equipment during maintenance or in an emergency, the person that controls the bypass valve with full authority to shut the gas off, will also monitor the downstream pressure gauge and will keep the downstream pressure at or below the system MAOP. If the person that is controlling the bypass valve cannot see the downstream pressure gauge, then a second person will monitor the downstream pressure and shall be in constant communication with the person that is controlling the bypass valves to assure the system pressure never exceeds the MAOP. The bypass valves will be manned continually and the downstream pressure monitored until the pressure control equipment is back in service and the downstream pressure has been properly regulated. Be sure to verify the SYSTEM MAOP before shutting down regulating equipment.

REFERENCES: 49 CFR 192.619, 192.621, 192. 623

4.9 REPORTING SAFETY RELATED CONDITIONS

Each operator must report any of the following safety related conditions involving facilities in service:

1. In case of a pipeline, general corrosion that had reduced the wall thickness to less than that required for the maximum allowable operating pressure and localized corrosion pitting to a degree where leakage might result.

2. Unintended movement or abnormal loading by environmental causes such as earthquake, landslide, or flood that impairs the serviceability of a pipeline.

3. Any material defect or physical damage that impairs the serviceability of a pipeline that operates at a hoop stress of 20% or more of its Specified Minimum Yield Strength (SMYS).

4. Any malfunction or operating error that causes the pressure of a pipeline to rise above its maximum allowable operating pressure plus the buildup allowed for operation of pressure limiting or control devices.

5. A leak in a pipeline that contains or processes gas that constitutes an emergency.

6. Any safety related condition that could lend to an imminent hazard and causes, for purposes other than abandonment, a 20% or more reduction in operating pressure or shutdown of operation of pipeline that contains or processes gas.

Reports of safety related conditions are NOT required for a safety related condition that:

7. Became an incident before September 29, 1988.

8. Exists on a pipeline more than 220 yards from a building intended for human occupancy or outdoor places of assembly. Exception: reports are required for conditions within the right-of-way of an active railroad, paved road, street or highway.


9. Is corrected by repair or replacement in accordance with applicable safety standards before the deadline for filing the safety related condition report. Exception: reports are required for corrosion conditions described in “a” (above); other than localized corrosion pitting on an effectively coated and cathodically protected pipeline.

REFERENCE: 49 CFR Part 191.23

4.10 INVESTIGATION OF FAILURE AND ACCIDENTS

In the event of a failure and/or accident an investigation must be conducted to determine the cause of the event and thereby minimize the possibility of a recurrence. If human error or negligence was the cause, then a review may be appropriate of management techniques involving procedures, training or staffing. If excavation damage was the cause, a review of the dig-in damages shall be made to find the root cause of the accident or incident.

A complete report of a failure must be made including the following information, where applicable:

1. Location and time of failure. 2. How was the failure detected? 3. The manufacturer, type, and year installed of failed component. 4. Origin of the failure. 5. Type of repair made. 6. Personal injury and/or property damage resulting from failure.

A preliminary report of failures and/or accidents must be made available to the manager of Gas Operations.

When appropriate, samples of failed facilities or equipment must be kept for laboratory examination.

REFERENCE; 49 CFR Part 192.617

4.11 PREVENTION OF ACCIDENTAL IGNITION:

Each operator must take steps to minimize the danger of accidental ignition of gas in any structure or area where the presence of gas constitutes a hazard of fire or explosion, including the following:

1. 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.

2. 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.

3. Post warning signs, where appropriate.

REFERENCE: 49 CFR Part 192.751


4.11.1 GENERAL PREVENTION OF ACCIDENTAL IGNITION:

1. Smoking and open flames, should be prohibited in the following locations:

a. In structures or areas containing gas facilities where possible leakage or presence of gas constitutes a hazard of fire or explosion.

b. In the open when accidental ignition of gas-air mixture might cause personal injury or property damage.

2. Accidental electric arcing. To prevent accidental ignition by electric arcing, the following should be considered:

a. Flashlights, portable floodlights, extension cords, and any other electrically powered tool or equipment should be of a type approved for use in hazardous atmospheres.

b. Internal combustion engines that power trucks, cars, compressors, pumps, generators and other equipment should not be operated in suspected or known hazardous atmospheres.

c. Bonding to provide electrical continuity should be considered around all cuts separating metallic pipes that may have natural gas present. This bond should be installed prior to cutting and maintained until all reconnections are completed or a gas free environment exists. Bond cables should be installed in such a manner to ensure that they do not become detached during construction and that they provide minimal electrical resistance between pipe sections.

3. Static electricity on plastic pipe. A static electric charge can build up on both the inside and outside of plastic pipe due to the dielectric properties of plastic. Discharging of the static electricity going to ground can cause an arc that will cause ignition if a flammable gas-air mixture is present. In plastic pipe operations, it is essential to avoid the accumulation of a flammable gas-air mixture and the arcing of a static electrical discharge. When conditions exist that a flammable gas-air mixture may be encountered and static charges may be present, such as when repairing a leak, squeezing-off an open pipe, purging, making a connection, etc., arc preventing safety precautions are necessary. The following should be considered:

a. Leaking or escaping gas should be eliminated by closing valves or excavation and squeezing-off in a separate excavation at a safe distance from the escaping gas.

b. If escaping gas cannot be effectively controlled or eliminated and it is necessary to work in an area of escaping gas, safety provisions should be considered such as dissipating or preventing the accumulation of a static electrical charge, venting the gas from the trench, and grounding those tools used in the area. Additionally, flame-resistant clothing treated to prevent static buildup and respiratory equipment should be used. Acceptable methods of dissipation or preventing the accumulation of static electricity include wetting the exposed area with an electrically conductive liquid (e.g., soapy water with glycol added when ambient temperatures are below freezing) and using a anti-static polyethylene (PE) film or wet non-synthetic cloth wound around or laid in contact with the entire section of exposed pipe and grounded with a brass pin driven into the ground. Commercially available


electrostatic discharge systems may be considered as a means of eliminating static electricity from both the inside and outside of PE pipe.

c. A plastic pipe vent or blowdown stack should not be used due to the possibility that venting gas with a high scale or dust content could generate an internal static electrical charge that could ignite the escaping gas. Metal vent stacks should be grounded before placement in the escaping gas stream.

d. To reduce potential sources of ignition, all tools, including squeeze-off tools, used in gaseous atmospheres should be grounded or the non-sparking type.

4. Other sources of ignition. Care should be taken in selecting the proper hand tools for use in hazardous atmospheres and in handling tools to reduce the potential for a spark.


4.11.2 GENERAL WELDING, CUTTING AND OTHER HOT WORK

Prior to welding, cutting, or other hot work in or around a structure or area containing gas facilities, a thorough check should be made with a gas detector for the presence of a combustible gas mixture. Prior to entering pipe, tanks, or similar confined spaces, appropriate instruments should be used to ensure a safe, breathable atmosphere. Work should begin only when safe conditions are indicated. The atmosphere should be tested periodically for oxygen deficiency and combustible mixtures.

1. Pipeline filled with gas. When a pipeline or main is to be kept full of gas during welding or cutting operations, the following are recommended:

a. A slight flow of gas should be kept moving towards the cutting or welding operation.

b. The gas pressure at the site of the work should be controlled by suitable means. c. All slots or open ends should be closed with tape, tightly fitted canvas, or other

suitable material immediately after a cut is made. d. Two openings should not be uncovered at the same time.

2. Pipelines containing air.

a. Before the work is started, and at intervals as the work progresses, the atmosphere in the vicinity of the zone to be heated should be tested with a combustible gas indicator or by other suitable means.

b. Unless a suitable means (such as an air blower) is used to prevent a combustible mixture in the work area, welding, cutting or other operations that could be a source of ignition should not be performed on a pipeline, main or auxiliary apparatus that contains air and is connected to a source of gas.

c. When the means noted in subsection 2 (above) are not used, one or more of the following precautions are suggested, depending upon the job site circumstances.

i. The pipe or other equipment upon which the welding or cutting is to be done should be purged with an inert gas.

ii. The pipe or other equipment upon which the welding or cutting is to be done should be continuously purged with air in such a manner that combustible mixture does not form in the facility at the work area.


4.11.3 GENERAL ISOLATING PIPELINE SEGMENTS ON PLANNED WORK TO MINIMIZE THE POTENTIAL OF IGNITION

Planned work on gas facilities should incorporate procedures to shut off or minimize the escape of gas. No portion of a pipeline, large service, or main should be cut out under pressure, unless the flow of gas is shut off or minimized by the line valves, line plugging equipment, bags, stoppers, or pipe squeezers. Where 100 percent shutoff is not feasible, the following precautions are recommended:

1. Plan the job to minimize the escape of gas and sequence steps to limit the time and amount of gas to which personnel are exposed.

2. The size and position of the cut should allow the gas to vent properly even with an employee in the excavation.

3. Protection of personnel working in a gaseous atmosphere under an overhang, in a tunnel, or in a manhole.

Isolating pipeline segments.

4. Preliminary action. The operator should conduct a pre-work meeting(s) to review the following with the personnel involved.

a. The method of isolation. b. The purpose of each activity. c. Drawings, procedures, and schematics, as applicable. d. Responsibilities of each individual, including the designation of an individual in

charge of the operation.

5. Isolation precautions.

a. Isolation equipment left unattended should have a positive means of preventing unauthorized operation.

b. Positive means should be provided at the work site to alert and protect personnel from unintentional pressuring. Consideration should be given to the use or installation of items such as:

i. Relief valves. ii. Rupture discs. iii. Pressure gauges. iv. Pressure recorders. vi. Vents. vii. Pressure alerting devices. viii. Other pressure detecting devices.

c. Isolation equipment should be inspected and maintained prior to use. d. Temporary closures capable of withstanding full line pressure should have a means

to determine pressure build-up, such as gauges and vents.


e. Consideration should be given to the following to prevent the uncontrolled release of liquid hydrocarbons when cutting into offshore pipelines or other pipelines that might contain significant quantities of these liquids.

i. The elevation difference between the blow-down valve and cut location. ii. The impact of water displacement on liquid hydrocarbons in those instances

where water may enter into the pipeline segment.

6. Monitoring isolated segments.

a. Monitoring procedures should be established based on the pressure, volumes, closures, and other pertinent factors.

b. Personnel assigned to operate isolation equipment should have a means to determine pressures build-ups, such as gauges and vents.

c. Personnel monitoring at remote locations should have communication with the work site and the individual in charge of the operation.

4.11.4 NOTIFICATIONS PRIOR TO PURGE OF BLOWDOWN

Public officials The appropriate public officials should be notified prior to a purge or blowdown in those situations where the normal traffic flow through the area might be disturbed, or where it is anticipated that there will be calls from the public regarding the purge or blowdown.

Public in vicinity of gas discharge The public in the vicinity of the gas discharge should be notified prior to a purge or blowdown if it is anticipated that the process might affect the public. The primary considerations for determining the need for notification are noise, odor, and the possibility of accidental ignition.

4.11.5 PURGING OF PIPELINES

1. Removal from ServiceWhere existing gas piping is opened, the section that is opened shall be isolated from the gas supply and the line pressure vented in accordance with “Placing in Operation” procedures below. The residual fuel gas in the piping shall be displaced with an inert gas.

2. Placing in OperationWhere the gas piping containing air is placed into service, the air in the piping shall first be displaced with fuel gas in accordance with 49 CFR 192.629.

a. Outdoor Discharge of Purged Gas – The open end of a piping system being pressure vented or purged shall discharge directly to an outdoor location. Purging operations shall be as follows:

b. The point of discharge shall be controlled with a shutoff valve. c. The point of discharge shall be located at least 10 ft. from sources of ignition, at

least 10 ft. from building openings and at least 25 ft. from mechanical air intake openings.

d. During discharge, the open point of discharge shall be continuously attended and monitored with gas detection equipment that is capable to numerically display the readings.


e. Purging operations introducing fuel gas shall be stopped when 90 percent fuel gas by volume is detected within the pipe.

f. Persons not involved in the purging operation shall be evacuated from all area within 10 ft. of the point of discharge.

3. Piping System Allowed to Be Purged Indoors or Outdoors

a. Purging Procedure – The piping system shall be purged in accordance with one or more of the following:

i. The piping shall be purged with fuel gas and shall discharge to the outdoors. ii. The piping shall be purged with fuel gas and shall discharge to the indoors

or outdoors through an appliance burner not located in a combustion chamber. Such burner shall be provided with a continuous source of ignition.

iii. The piping shall be purged with fuel gas and shall discharge to the indoors or outdoors through a burner that has a continuous source of ignition and that is designed for such purpose.

iv. The piping shall be purged with fuel gas that is discharged to the indoors or outdoors, and the point of discharge shall be monitored with gas detection equipment. Purging shall be stopped when fuel gas is detected.

v. The piping shall be purged by the gas supplier in accordance with written procedures.

b. Purging Appliances and Equipment – After the piping system has been placed in operation, appliances and equipment shall be purged before being placed into operation.

4. Purging Process at a Meter Stop

a. Purging Procedure i. Turn on and adjust gas detection equipment. ii. Slowly crack open meter stop and allow gas to flow out of service at a

moderately fast rate. If purging services with an Excess Flow Valve EFV), purging too quickly may trip the EFV. If the EFV trips, close the meter stop and wait until the EFV resets. NOTE: when purging next to a building the point of discharge shall be located at least 10 ft. from sources of ignition, at least 10 ft. from building openings and at least 25 ft. from mechanical air intake openings

iii. Use gas detection equipment for checking the presence of gas while purging.

iv. Close the meter stop once the presence of gas has been verified with gas detection equipment.

v. Install gas meter connections and complete the project. vi. If a gas meter will not be installed at this time, lock the meter stop in the

closed position.

NOTE: All purging procedures the operator must follow all safety rules for personal protection for purging and dealing with blowing gas. A fire extinguisher shall be made available in the area of purging if a potentially hazardous volume of gas is to be purged. REFERENCES: 49 CFR 192.629, 192.751, NFPA 54 National Fuel Gas Code


4.12 TRANSMISSION LINE RECORD KEEPING:

Each operator shall maintain the following records for transmission lines for the periods specified:

1. The date, location, and description of each repair made to pipe (including pipe-to-pipe connections) must be retained for as long as the pipe remains in service.

2. The date, location, and description of each repair made to parts of the pipeline system other than pipe must be retained for at least 5 years. However, repairs generated by patrols, surveys, inspections, or tests required by 49 CFR Part 192 subparts L and M must be retained in accordance with subpart (3) of this section.

3. A record of each patrol, survey, inspection, and test required by 49 CFR Part 192 subparts L and M of this part must be retained for at least 5 years or until the next patrol, survey, inspection, or test is completed, whichever is longer.

4.12.1 Transmission lines: General requirements for repair procedures.

1. Each operator shall take immediate temporary measures to protect the public whenever:

a. A leak, imperfection, or damage that impairs its serviceability is found in a segment of steel transmission line operating at or above 40 percent of the SMYS; and

b. It is not feasible to make a permanent repair at the time of discovery. c. As soon as feasible, the operator shall make permanent repairs. d. Except as provided in §192.717(b)(3), no operator may use a welded patch as a

means of repair.

4.12.2 Transmission lines: Permanent field repair of imperfections and damages.

1. Each imperfection or damage that impairs the serviceability of pipe in a steel transmission line operating at or above 40 percent of SMYS must be—

a. Removed by cutting out and replacing a cylindrical piece of pipe; or b. Repaired by a method that reliable engineering tests and analyses show can

permanently restore the serviceability of the pipe.

2. Operating pressure must be at a safe level during repair operations.

4.12.3 Transmission lines: Permanent field repair of welds.

1. Each weld that is unacceptable under §192.241(c) must be repaired as follows:

a. If it is feasible to take the segment of transmission line out of service, the weld must be repaired in accordance with the applicable requirements of §192.245.

b. A weld may be repaired in accordance with §192.245 while the segment of transmission line is in service if:

i. The weld is not leaking;


ii. The pressure in the segment is reduced so that it does not produce a stress that is more than 20 percent of the SMYS of the pipe; and

iii. Grinding of the defective area can be limited so that at least 1/8-inch (3.2 millimeters) thickness in the pipe weld remains.

c. A defective weld which cannot be repaired in accordance with paragraph (a) or (b) of this section must be repaired by installing a full encirclement welded split sleeve of appropriate design.

4.12.4 Transmission lines: Permanent field repair of leaks.

1. Each permanent field repair of a leak on a transmission line must be made by—

a. Removing the leak by cutting out and replacing a cylindrical piece of pipe; or b. Repairing the leak by one of the following methods:

i. Install a full encirclement welded split sleeve of appropriate design, unless the transmission line is joined by mechanical couplings and operates at less than 40 percent of SMYS.

ii. If the leak is due to a corrosion pit, install a properly designed bolt-on-leak clamp.

iii. If the leak is due to a corrosion pit and on pipe of not more than 40,000 psi (267 Mpa) SMYS, fillet weld over the pitted area a steel plate patch with rounded corners, of the same or greater thickness than the pipe, and not more than one-half of the diameter of the pipe in size.

iv. If the leak is on a submerged offshore pipeline or submerged pipeline in inland navigable waters, mechanically apply a full encirclement split sleeve of appropriate design.

v. Apply a method that reliable engineering tests and analyses show can permanently restore the serviceability of the pipe.

4.12.5 Transmission lines: Testing of repairs.

Testing of replacement pipe: If a segment of transmission line is repaired by cutting out the damaged portion of the pipe as a cylinder, the replacement pipe must be tested to the pressure required for a new line installed in the same location. This test may be made on the pipe before it is installed.

1. Testing of repairs made by welding: Each repair made by welding in accordance with §192.713, 192.715, and 192.717 must be examined in accordance with §192.241.

REFERENCES: 49 CFR 192.241, 192.245, 192.709, 192.711, 192.713, 192.715, 192.717, 192.719 and Subparts L & M


DIVISION FIVE OPERATING PROCEDURES

5.0 OPERATING PROCEDURES (General)

Procedures in this part shall be followed in the general operation of the system.

REFERENCE: 49 CFR 192 Subpart L, The procedures and other information in this division are largely derived from the "Guidance Manual for Operators of Small Gas Utilities” current edition.

5.1 GENERAL CONSTRUCTION REQUIREMENTS

This section prescribes minimum requirements for constructing transmission lines and mains under 49 CFR 192 Subpart G.

1. Each transmission line or main must be constructed in accordance with comprehensive written specifications or standards.

2. Each transmission line or main must be inspected.

3. Each length of pipe and each other component must be visually inspected at the site of installation to ensure that it has not sustained any visually determinable damage that could impair its serviceability.

4. Each imperfection or damage that impairs the serviceability of a length of pipeline of steel pipe must be repaired or removed. If a repair is made by grinding, the remaining wall thickness must a least be equal to either:

a. The minimum thickness required by the tolerances in the specification to which the pipe was manufactured; or

b. The design pressure of the pipeline.

5. Each of the following dents must be removed from steel pipe to be operated at a pressure that produces a hoop stress of 20 percent, or more, of SMYS, unless the dent is repaired by a method that reliable engineering tests and analyses show can permanently restore the serviceability of the pipe:

a. A dent that contains a stress concentrator such as a scratch, gouge, groove, or arc burn.

b. A dent that affects the longitudinal weld or a circumferential weld. c. In pipe to be operated at a pressure that produces a hoop stress of 40 percent or

more of SMYS, a dent that has a depth of: i. More than ¼ inch (6.4 millimeters) in pipe 12¾ inches (324 millimeters) or

less in outer diameter; or ii. More than 2 percent of the nominal pipe diameter in pipe over 12 - 3/4

inches (324 millimeters).


For the purpose of this section, a "dent" is a depression that produces a gross disturbance in the curvature of the pipe wall without reducing the pipe-wall thickness. The depth of a dent is measured as the gap between the lowest point of the dent and a prolongation of the original contour of the pipe.

6. Each arc burn on steel pipe to be operated at a pressure that produces a hoop stress of 40 percent or more, of SMYS must be repaired or removed. If a repair is made by

grinding, the arc burn must be completely removed and the remaining wall thickness must be at least equal to either:

a. The minimum wall thickness required by the tolerances in the specification to which the pipe was manufactured; or

b. The nominal wall thickness required for the design pressure of the pipeline.

7. A gouge, groove, arc burn, or dent may not be repaired by insert patching or by pounding out.

8. Each gouge, groove, arc burn, or dent that is removed from a length of pipe must be removed by cutting out the damaged portion as a cylinder.

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

10. All Bends and elbows and Wrinkle bends will be done in accordance to 192.313 and 192.315

11. Protection from Hazards

a. The operator must take all practicable steps to protect each transmission line or main from washouts, floods, unstable soil, landslides, or other hazards that may cause the pipeline to move or to sustain abnormal loads. b. Each above ground transmission line or main, not located offshore or in inland navigable water areas, must be protected from accidental damage by vehicular traffic or other similar causes, either by being placed at a safe distance from the traffic or by installing barricades. c. Installation of pipe in a ditch

12. When installed in a ditch, each transmission line that is to be operated at a pressure producing a hoop stress of 20 percent or more of SMYS must be installed so that the pipe fits the ditch so as to minimize stresses and protect the pipe coating from damage.

13. When a ditch for a transmission line or main is backfilled, it must be backfilled in a manner that:

a. Provides firm support under the pipe; and b. Prevents damage to the pipe and pipe coating from equipment or from the backfill material.


14. Installation of plastic pipe

a. Plastic pipe must be installed below ground level except as provided by paragraphs (g) and (h) of this section.

b. Plastic pipe that is installed in a vault or any other below grade enclosure must be completely encased in gas-tight metal pipe and fittings that are adequately protected from corrosion

c. Plastic pipe must be installed so as to minimize shear or tensile stresses. d. Thermoplastic pipe that is not encased must have a minimum wall thickness

of 0.090 inch (2.29 millimeters), except that pipe with an outside diameter of 0.875 inch (22.3 millimeters) or less may have a minimum wall thickness of 0.062 inch(1.58 millimeters)

e. Plastic pipe that is not encased must have an electrically conducting wire or other means of locating the pipe while it is underground. Tracer wire may not be wrapped around the pipe and contact with the pipe must be minimized but is not prohibited. Tracer wire or other metallic elements installed for pipe locating purposes must be resistant to corrosion damage, either by use of coated copper wire or by other

f. Plastic pipe that is being encased must be inserted into the casing pipe in a manner that will protect the plastic. The leading end of the plastic must be closed before insertion.

g. Uncased Plastic pipe may be temporarily installed above ground level under the following conditions:

i. The operator must be able to demonstrate that the cumulative aboveground exposure of the pipe does not exceed the manufacturer's recommended maximum period of exposure or 2 years, whichever is less.

ii. The pipe either is located where damage by external forces is unlikely or is otherwise protected against such damage.

iii. The pipe adequately resists exposure to ultraviolet light and high and low temperatures.

h. Plastic pipe may be installed on bridges provided that it is: i. Installed with protection from mechanical damage, such as installation in a

metallic casing ii. Protected from ultraviolet radiation; and iii. Not allowed to exceed the pipe temperature limits specified in §192.123.

15. Casings

Each casing used on a transmission line or main under a railroad or highway must comply with the following:

a. The casing must be designed to withstand the superimposed loads. b. If there is a possibility of water entering the casing, the ends must be sealed. c. If the ends of an unvented casing are sealed and the sealing is strong enough to

retain the maximum allowable operating pressure of the pipe, the casing must be designed to hold this pressure at a stress level of not more than 72 percent of SMYS.


d. If vents are installed on a casing, the vents must be protected from the weather to prevent water from entering the casing.

e. Cathodic protection monitoring will be as required under 49 CFR 192.467

16. Underground Clearance

a. Each transmission line must be installed with at least 12 inches (305 millimeters) of clearance from any other underground structure not associated with the transmission line. If this clearance cannot be attained, the transmission line must be protected from damage that might result from the proximity of the other structure.

b. Each main must be installed with at least 12 inches of separation from underground electric utilities (unless encased) as well as enough clearance from any other underground structure to allow proper maintenance and to protect against damage that might result from proximity to other structures.

c. In addition to meeting the requirements of paragraphs (a) or (b) of this section each plastic transmission line or main must be installed with sufficient clearance, or must be insulated, from any source of heat so as to prevent the heat from impairing the serviceability of the pipe.

d. Each pipe-type or bottle-type holder must be installed with a minimum clearance from any other holder as prescribed in §192.175(b).

17. Cover

a. Except as provided in paragraphs (c), (e), (f), and (g) of this section, each buried transmission line must be installed with a minimum cover as follows:

Location Normal soil Consolidated rock Inches (Millimeters)

Inches (Millimeters)

Class 1 locations 30 (762) 18 (457) Class 2, 3, and 4 locations 36 (914) 24 (610) Drainage ditches of public roads and railroad crossings 36 (914) 24 (610)

b. Except as provided in paragraphs (c) and (d) of this section, each buried main must be installed with at least 24 inches (610 millimeters) of cover.

c. Where an underground structure prevents the installation of a transmission line or main with the minimum cover, the transmission line or main may be installed with less cover if it is provided with additional protection to withstand anticipated external loads.

d. A main may be installed with less than 24 inches (610 millimeters) of cover if the law of the State or municipality:

i. Establishes a minimum cover of less than 24 inches (610 millimeters); ii. Requires that mains be installed in a common trench with other utility lines;

and, iii. Provides adequately for prevention of damage to the pipe by external forces.

e. Except as provided in paragraph (c) of this section, all pipe installed in a navigable river, stream, or harbor must be installed with a minimum cover of 48 inches (1,219 millimeters) in soil or 24 inches (610 millimeters) in consolidated rock between the top of the pipe and the underwater natural bottom (as determined by recognized and generally accepted practices).


18. Regulator Stations

a. Must be installed according to manufacturers’ specifications b. Will be adequately protected (barricades, buildings, fence, etc.)

REFERENCES:192.301, 192.303, 192.305, 192.307, 192.309, 192.311, 192.313, 192.315, 192.317, 192.319, 192.321, 192.323, 192.325,192.199

5.2 MAOP DETERMINATION AND REVIEW

The utility will establish maximum allowable operating pressure (MAOP) for steel or plastic pipelines as prescribed in 49 CFR 192.112, 192.619 and 192.621. Design pressure shall be limited by the weakest component in the segment consistent with 49 CFR 192, Subparts C and D. MAOP shall be documented and kept for the life of the system.

DOCUMENT: Determination of MAOP in Natural Gas Pipelines REFERENCES: 49 CFR 192.619, 192.621, 192. 623

5.3 UPRATING MAOP

Each operator who uprates a segment of pipeline shall establish a written procedure that will ensure that each applicable requirement of 192 Subpart K is complied with.

Pressure increases must be made gradually, in increments, and at a rate that can be controlled. The pressure must be constant at the end of each increase while the affected section of the distribution system is checked for leaks. Use the following sequence:

1. Review the design, operating and maintenance history of the segment of pipeline. 2. Make a leakage survey and repair any leaks that are found. 3. Make any repairs, replacements or alterations in the segment of pipeline that are

necessary for safe operation at the increased pressure. 4. Reinforce or anchor offsets, bends and dead ends in pipe joined by compression

couplings or bell and spigot joints to prevent failure of the pipe joint, of the offset, bend or dead end if exposed in an excavation.

5. Isolate the segment of pipeline in which the pressure is to be increased from any adjacent segment that will continue to be operated at a lower pressure.

6. If the pressure in mains or service lines, or both, is to be higher than the pressure delivered to the customer, install a service regulator on each service line and test each regulator to determine that it is functioning. Pressure may be increased as necessary to test each regulator, after a regulator has been installed on each pipeline subject to the increased pressure.

7. The increase in maximum allowable operating pressure must be in increments that are equal to 10 p.s.i.g. or 25% of the pressure increase, whichever produces the fewer number of increments. Whenever the requirements of “f” (above) apply, there must be at least two approximately equal incremental increases.

8. At the end of each incremental increase, the pressure must be held constant while the entire segment of pipeline that is affected is checked for leaks.

9. Each leak detected must be repaired before a further pressure increase is made. The exception being when a leak is determined not to be potentially hazardous. It may not


need to be repaired if it is monitored during the pressure increase and it does not become potentially hazardous.

NOTE: The MAOP of uprated lines must meet the pressure test requirements of 192.619 (a) (2), (see section 6.24 (a) of this plan for requirements).

Each operator who uprates a segment of pipeline must retain for the life of the segment, a record of each investigation, of all work performed and of each pressure test conducted with the uprating.

For plastic pipe, the MAOP after uprating cannot exceed the test pressure (either a previous documented pressure test or the maximum test pressure during the uprating) divided by 1.5, as required by 192.619(a)(2)(i).

For steel pipe to be operated at 100 psi or more, the MAOP after uprating cannot exceed the test pressure (either a previous documented pressure test or the maximum pressure during the uprating) divided by the appropriate factor from the table in 192.619(a)(2)(ii).

REFERENCE: 49 CFR 192.553, and Subpart K. The written plan for uprating shall be as described in the "Guidance Manual for Operators of Small Gas Systems" current edition.

5.4 TESTING FOR REINSTATING

Disconnected lines shall be tested in the same manner as new lines. If the line is temporarily disconnected from the main, it should be tested from the point of disconnection to the service line valve. After final tie-in operator must perform a soap test to check for leakage. If provisions are made to maintain continuous service, such as by installation of a bypass, any part of the original line used to maintain continuous service, need not be tested.

DOCUMENTATION: Pipeline Test Report, Pipeline Purge Test Report. REFERENCES: 49 CFR 192.725. Procedures for testing service lines can be found in the "Guidance Manual for Operations of Small Gas Utilities" current edition.

5.5 ABANDONMENT OR INACTIVATION OF FACILITIES

Inactive pipelines, other than service lines, and all abandoned pipeline shall be disconnected, purged, and sealed at both ends. If air is used, a test must be conducted to ensure there is not a combustible atmosphere. However, pipeline smaller than four inches in diameter need not be purged if the line is depressurized and if the volume of gas were so small there would be no potential hazard. Records must be kept on all facilities abandoned. This includes location, date, and method of discontinuing service (abandoning the facility).

1. Abandoning Mains -- Mains that are abandoned in place shall be physically disconnected from active pipeline. The open end of the abandoned main shall be bled down and purged with nitrogen, or air, and closed with a welded cap or other suitable material.

2. Abandoning Service Lines -- Service lines abandoned in place shall be cut and capped at both ends. However, where both the main and service line are being abandoned, the service line need not be cut at the main.


3. Disconnection of Service Lines for Administrative Reasons Including Non-Payment of a Bill -- When service to a customer is temporarily disconnected for administrative reasons, one of the following must be done:

a. The valve must be closed to prevent the flow of gas to the customer and secured with a lock or other device to prevent opening of the valve by unauthorized people;

b. A mechanical device or fitting that will prevent the flow of gas must be installed in the service line or meter assembly; or

c. The customer's piping must be physically disconnected from the gas supply and the open end sealed.

DOCUMENTATION: Report of Abandoned Facilities, Pipeline Purge Test Report, Exposed Pipe/Bell Hole Report. The Abandoned Facilities form need not be used for temporary disconnections because other documents, such as records of tests for reinstatement and customer disconnect notices provide adequate record. REFERENCE: 49 CFR 192.727.

5.6 ACCIDENTAL IGNITION OF GAS

The utility will take every precaution to prevent accidental ignition of gas. Gas alone is not explosive but when it is mixed with air in the proper ratio, it can ignite or explode with tremendous force. When it is necessary to vent gas into air, whether by accidental rupture or because of operational necessity, a fire extinguisher must be available. Every possible effort, including warning signs, shall be made to protect property and the public.

5.7 PIPELINE MATERIALS (General)

Whenever possible, manufacturer's data specific to the vintage and/or type shall be maintained for use in planning leakage surveys, replacement and repairs. Minimum requirements for the selection and qualification of pipe and components for use in pipelines shall be as stated in the following subsections.

1. Materials for pipe and components must be:

a. Able to maintain the structural integrity of the pipeline under temperature and other environmental conditions that may be anticipated;

b. Chemically compatible with any gas that they transport and with any other material in the pipeline with which they are in contact; and

c. Qualified in accordance with the applicable requirements in 49 CFR Subpart B & C.

REFERENCES: 49 CFR 192.53, 192.103, 192.199, 192.281, 192.307


5.8 STEEL PIPE

Criteria for use of steel pipe are determined by both its use (operating pressure) and its age, according to provisions of this subsection and applicable regulations.

1. New steel pipe is qualified for use if:

a. It was manufactured in accordance with a listed specification; b. It meets the requirements of 49 CFR 192, Appendix B, Paragraph II or, if it was

manufactured before November 12, 1970, if it meets the requirements of 49 CFR 192 Appendix B, Paragraphs II or III;

c. It is used in accordance with subparagraphs "c" or "d" of this subsection.

2. Used steel pipe is qualified for use if:

a. It was manufactured in accordance with a listed specification and it meets the requirements of 49 CFR 192, Appendix B, Paragraph II(C);

b. It meets the requirements of 49 CFR 192, Appendix B, Paragraph II or, if it was manufactured before November 12, 1970, it meets the requirements of 49 CFR 192, Appendix B, Paragraphs II or III;

c. It has been used in an existing line of the same or higher pressure and meets the requirements of 49 CFR 192, Appendix B, Paragraph II(C); or

d. It is used in accordance with subparagraph "c" of this subsection.

3. New or used steel pipe may be used at a pressure resulting in a hoop stress of less than 6,000 p.s.i.g. where no close coiling or close bending is to be done, if visual examination indicates that the pipe is in good condition and that it is free of split seams and other defects that would cause leakage. If it is to be welded, steel pipe that has not been manufactured to a listed specification must also pass the weld ability tests prescribed in 49 CFR 192, Appendix B, Paragraph II (B).

4. Welding material must be chosen in accordance with the compatibility requirements of material to be joined and location to be welded.

NOTE: Refer to the utility's qualified welding standards and supporting documents, such as the IAMU Pipeline Welding Manual.

5. Steel pipe that has not been previously used may be used as replacement pipe in a segment of pipeline if it has been manufactured prior to November 12, 1970, in accordance with the same specification as the pipe used in constructing that segment of pipeline.

6. New steel pipe that has been cold expanded must comply with the mandatory provisions of API Specification 5L.

REFERENCES: 49 CFR 192.53, 192.55, 192.307


5.9 PLASTIC PIPE

Criteria for use of plastic pipe are determined by both its use (operating pressure) and its age, according to provisions of this subsection and applicable regulations.

NOTE: The design pressure for thermoplastic pipe produced after July 14, 2004 may exceed a gauge pressure of 100 psig provided that the design pressure does not exceed 125 psig, the material is a PE2406 or PE3408 as specified within ASTM D2513-99. Design limitation for plastic pipe, see 49 CFR 192.123(e)

1. New plastic pipe is qualified for use under this part if:

a. It is manufactured in accordance with a listed specification; and b. It is resistant to chemicals with which contact may be anticipated.

2. Used plastic pipe is qualified for use under this part if:

a. It was manufactured in accordance with a listed specification; b. It is resistant to chemicals with which contact may be anticipated; c. It has been used only in natural gas service; d. Its dimensions are still within the tolerances of the specification to which it was

manufactured; and e. It is free of visible defects.

For the purpose of subparagraphs "1 (a)" and "2 (a)" of this subsection, where pipe of a diameter included in a listed specification is impractical to use, pipe of a diameter between the sizes included in a listed specification may be used if it:

a. Meets the strength and design criteria required of pipe included in that listed specification; and

b. Is manufactured from plastic compounds which meet the criteria for material required of pipe included in that listed specification.

3. An electrical conductor must be installed with direct burial plastic pipe (preferably 2" to 6" from the pipe, where practical) to facilitate locating with an electronic detector unless other means are available for locating the pipe underground. This conductor can be bare or coated metal wire or a coated tape, and should be corrosion-resistant. Leads into curb boxes, valve boxes, and on service risers can be used for direct connection of locating equipment. (Prudent option - anodes on the tracer wire to prevent its corrosion.)

4. Any PE above grade including anode less risers and incased bridge crossings must be selected for higher temperatures.

Squeeze-off of plastic pipe: After a squeeze-off of plastic pipe has been performed make sure to permanently mark the area by using duct or electrical tape around the area of squeeze-off to alert operators in the future never to perform a squeeze-off in that same area of pipe again.

NOTE: 49 CFR 192.321 requires that plastic pipe that is not encased must have an electrically conductive wire or other means of locating the pipe while it is underground. PHMSA has alerted


all operators of gas pipeline facilities that wrapping an electrically conductive tracer wire around plastic pipe has resulted in conducting lightning through the tracer wire, thereby damaging and causing the plastic pipe to leak. Accordingly, each gas pipeline operator using a tracer wire as a means to comply with Section 192.321 should lay the tracer wire along the plastic pipe with 2" to 6" separation when possible, rather than wrap the tracer wire around the plastic pipe.

REFERENCES: 49 CFR 192.53, 192.59, 192.121, 192.123, 192.321, 192.251, 192.361.

5.10 MARKING OF MATERIALS

Materials shall be marked in accordance with the provisions of this section and applicable regulations.

1. Except as provided in paragraph "d" of this section, each valve, fitting, length of pipe, and other component must be marked as prescribed in the specification or standard to which it was manufactured, except that thermoplastic fittings must be marked in accordance with ASTM D2513-87, or must be marked to indicate size, material, manufacturer, pressure rating, and temperature rating, and as appropriate, type, grade, and model.

2. Surfaces of pipe and components that are subject to stress from internal pressure may not be field die stamped.

a. If any item is marked by die stamping, the die must have blunt or rounded edges that will minimize stress concentrations.

b. Paragraph "a" of this section does not apply to items manufactured before November 12, 1970 that meet all of the following:

i. The item is identifiable as to type, manufacturer, and model; and ii. Specifications or standards giving pressure, temperature, and other

appropriate criteria for the use of items are readily available.

REFERENCES: 49 CFR 192.63

5.11 QUALIFYING COMPONENTS

1. Notwithstanding any standard incorporated by reference in 49 CFR 192, Appendix A, a metallic component manufactured in accordance with other editions of those standards is qualified for use under that part if:

a. It can be shown through visual inspection of the cleaned component that no defect exists which might impair the strength or tightness of the component; and

b. The edition of the standard under which the component was manufactured has equal or more stringent requirements for pressure testing, materials, and pressure and temperature ratings than the edition of that standard currently listed in Appendix A.



5.12 VALVES

The following criteria shall apply to valves:

1. Except for cast iron and plastic valves, each valve must meet the minimum requirements, or equivalent, of API 6D. A valve may not be used under operating conditions that exceed the required pressure temperature ratings.

2. Each cast iron and plastic valve must comply with the following:

a. The valve must have a maximum service pressure rating for temperatures that are equal to or exceed the maximum service temperature. b. The valve must be tested as part of the manufacturing as follows:

i. With the valve in the fully open position, the shell must be tested with no leakage to a pressure at least 1.5 times the maximum service rating.

ii. After the shell test, the seat must be tested to a pressure no less than 1.5 times the maximum service pressure rating. Except for swing check valves, test pressure during the seat test must be applied successively on each side of the closed valve with the opposite side open. No visible leakage is permitted.

iii. After the last pressure test is completed, the valve must be operated iv. through its full travel to demonstrate freedom from interference.

3. Each valve must be able to meet the anticipated operating conditions.

4. No valve having shell components made of ductile iron may be used at pressures exceeding 80% of the pressure ratings for comparable steel valves at their listed temperature. However, a valve having shell components made of ductile iron may be used at pressures up to 80% of the pressure ratings for comparable steel valves at their listed temperature, if:

a. The temperature adjusted service pressure does not exceed 1,000 p.s.i.g.; and b. Welding is not used on any ductile iron component in the fabrication of the

valve shells or their assembly.

5. No valve having pressure-containing parts made of ductile iron may be used in the gas pipe components of compressor stations.


5.13 FLANGES AND FLANGE ACCESSORIES

The following criteria apply to flanges and flange accessories:

1. Each flange or flange accessory (other than cast iron) must meet the minimum requirements of ANSI B16.5 MSS SP-44, or the equivalent. Full thread engagement is required on all flange nuts and bolts.


2. Each flange assembly must be able to withstand the maximum pressure at which the pipeline is to be operated and to maintain its physical and chemical properties at any temperature to which it is anticipated that it might be subjected in service.

3. Each flange on a flange joint in cast iron pipe must conform in dimensions, drilling, face and gasket design to ANSI B16.1 and be cast integrally with the pipe, valve, or fitting.


5.14 STANDARD FITTINGS

The following criteria apply to standard fittings:

1. The minimum metal thickness of threaded fittings may not be less than specified for the pressures and temperatures in the applicable standards referenced in this part, or their equivalent.

2. Each steel butt-weld fitting must have pressure and temperature ratings based on stresses for pipe of the same or equivalent material. The actual bursting strength of the fitting must at least equal the computed bursting strength of pipe of the designated material and wall thickness, as determined by a prototype that was tested to at least the pressure required for the pipeline to which it is being added.


5.15 TAPPING

Each tap made on a pipeline under pressure must be performed by a crew qualified to make hot taps, using the manufactures’ hot tap procedures. The following criteria apply to tapping.

1. Each mechanical fitting used to make a hot tap must be designed for at least the operating pressure of the pipeline.

2. Where a ductile iron pipe is tapped, the extent of full-thread engagement and the need for the use of outside sealing service connections, tapping saddles, or other fixtures must be determined by service conditions.

3. Where a threaded tap is made in cast iron or ductile iron pipe, the diameter of the tapped hole may not be more than 25% of the nominal diameter of the pipe unless the pipe is reinforced, except that:

a. Existing taps may be used for replacement service, if they are free of cracks and have good threads; and b. A 1-1/4 inch tap may be made in a 4-inch cast iron or ductile iron pipe, without

reinforcement. However, in areas where climate, soil, and service conditions may create unusual external stresses on cast iron pipe, un-reinforced taps may be used only on 6 inch or larger pipe.

REFERENCES: 49 CFR 192.151, 192.627


5.16 COMPONENTS FABRICATED BY WELDING: The following criteria apply to components fabricated by welding:

REFERENCES: 49 CFR 192, Subparts B, C, and D. General information on material standards can be found in the "Guidance Manual for Operators of Small Gas Systems" current edition.

1. Except for branch connections and assemblies of standard pipe and fittings joined by welds made around the circumference of the pipe or fitting, the design pressure of each component fabricated by welding, whose strength can't be determined, must be established in accordance with paragraph UG-101 of section VIII of the ASME Boiler and Pressure Vessel Code.

2. Each prefabricated unit that uses plate and longitudinal seams must be designated, constructed, and tested in accordance with the ASME Boiler and Pressure Vessel Code, except for the following:

a. Regularly manufactured butt welding fittings. b. Pipe that has been produced and tested under a specification listed in Appendix B to

this part of 49 CFR Part 192. c. Partial assemblies such as split rings or collars. d. Prefabricated units that the manufacturer certifies have been tested to at least twice

the maximum pressure to which they will be subjected under the anticipated operating conditions.

3. Orange-peel bull plugs and orange-peel swages may not be used on pipelines that are to operate at a hoop stress of 20% or more of the SMYS of the pipe.

4. Except for flat closures designed in accordance with section VIII of the ASME Boiler and Pressure Code, flat closures and fish tails may not be used on pipe that either operates at 100 p.s.i.g. or more, or is more than 3 inches nominal diameter.

5. Each welded branch connection made to pipe in the form of a single connection, or in a header or manifold as a series of connections, must be designed to ensure that the strength of the pipeline system is not reduced, taking into account the stresses in the remaining pipe wall due to the opening in the pipe or header, the shear stresses produced by the pressure acting on the area of the branch opening, and any external loading due to thermal movement, weight and vibration.

5.17 PIPELINE CONSTRUCTION AND LEAK REPAIR

Pipeline shall be installed in accordance with accepted standards and shall be tested before being placed in service.

All new construction and repairs made on transmission lines have to accommodate internal inspection devices, if the technology exists for the pipe size.

A 12 inch separation is to be provided between pipelines and underground electric lines, unless encased.

DOCUMENTATION: Pipeline Test Report, Pipeline Purge Test Report RFERENCES: 49 CFR 192.150, Subparts D, E, F, and J, 19.8(6), Code of Iowa. Refer to IAMU Pipeline Welding Manual for procedures and tables of specifications. The "Guidance Manual for Operators of Small Gas Systems" current edition.


5.18 EXTRUDED OUTLETS

Each extruded outlet must be suitable for anticipated service conditions and must be at least equal to the design strength of the pipe and other fittings in the pipeline to which it is attached.

5.19 FLEXIBILITY

Each pipeline must be designed with enough flexibility to prevent thermal expansion or contraction from causing excessive stresses in the pipe or components, excessive bending or unusual loads at joints, or undesirable forces or movements at points of connection to equipment, or at anchorage or guide points.


5.20 SUPPORTS AND ANCHORS

The following criteria apply to the use of supports and anchors:

1. Each pipeline and its associated equipment must have enough anchors or supports to:

a. Prevent undue strain on connected equipment; b. Resist longitudinal forces caused by a bend or off set in the pipe; and c. Prevent or damp out excessive vibration.

2. Each exposed pipeline must have enough supports or anchors to protect the exposed pipe joints from the maximum end force caused by internal pressure and any additional forces caused by temperature expansion or contraction or by the weight of the pipe and its contents.

3. Each support or anchor on an exposed pipeline must be made of durable, non-combustible material and must be designed and installed as follows:

a. Free expansion and contraction of the pipeline between supports or anchors may not be restricted.

b. Provision must be made for the service conditions involved. c. Movement of the pipeline may not cause disengagement of the support equipment.

4. Each support on an exposed pipeline operated at a stress level of 50% or more of SMYS must comply with the following:

a. A structural support may not be welded directly to the pipe. b. The support must be provided by a member that completely encircles the pipe. c. If an encircling member is welded to a pipe, the weld must be continuous and cover

the entire circumference.

5. Each underground pipeline that is connected to a relatively unyielding line or other fixed object must have enough flexibility to provide for possible movement, or it must have an anchor that will limit the movement of the pipeline.


6. Except for offshore pipelines, each underground pipeline that is being connected to new branches must have a firm foundation for both the header and the branch to prevent detrimental lateral and vertical movement.

REFERENCES: 49 CFR 192.357, 192.161

5.21 CUSTOMER METERS/REGULATORS

1. Location: Customer meters and regulators shall be installed in accordance with applicable provisions of 49 CFR 192, Subpart D and H, which prescribes minimum requirements for installing customer meters, service regulators, service lines, service line valves, and service line connections to mains.

a. Each meter and service regulator, whether inside or outside a building, must be installed in a readily accessible location and be protected from corrosion and other damage, including, if installed outside a building, vehicular damage that may be anticipated. However, the upstream regulator in a series may be buried.

b. Each service regulator installed within a building must be located as near as practical to the point of service line entrance.

c. Each meter installed within a building must be located in a ventilated place and not less than 3 feet from any source of ignition or any source of heat which might damage the meter.

d. Where feasible, the upstream regulator in a series must be located outside the building, unless it is located in a separate metering or regulating building.

e. Each meter set installed outdoors must be installed no less than 3 feet from any possible ignition sources or any openings into buildings. This includes air conditioners, electric meters, windows, doors, dryer and/or furnace vents, etc. SEE DIAGRAM BELOW FOR INSTALLATION REQUIREMENTS.


2. Installation

a. Each meter and each regulator must be installed so as to minimize anticipated stresses upon the connecting piping and the meter.

b. When close all-thread nipples are used, the wall thickness remaining after the threads are cut must meet the minimum wall thickness requirements.

c. Connections made of lead or other easily damaged material may not be used in the installation of meters or regulators.

d. Each regulator that might release gas in its operation must be vented to the outside atmosphere.

3. Protection from damage: Service regulator vents and relief vents must terminate outdoors, and the outdoor terminal must:

a. Be rain and insect resistant; b. Be located at a place where gas from the vent can escape freely into the atmosphere

and away from any opening into the building; and c. Be protected from damage caused by submergence in areas where flooding may

occur. d. Each pit or vault that houses a customer meter or regulator at a place where

vehicular traffic is anticipated must be able to support that traffic.

4. Control of the pressure of gas delivered from high-pressure distribution systems.

If the maximum actual operating pressure of the distribution system is 60 p.s.i. (414 kPa) gage, or less and a service regulator having the following characteristics is used, no other pressure limiting device is required:

a. A regulator capable of reducing distribution line pressure to pressures recommended for household appliances.

b. A single port valve with proper orifice for the maximum gas pressure at the regulator inlet.

c. A valve seat made of resilient material designed to withstand abrasion of the gas, impurities in gas, cutting by the valve, and to resist permanent deformation when it is pressed against the valve port.

d. Pipe connections to the regulator not exceeding 2 inches (51 millimeters) in diameter.

e. A regulator that, under normal operating conditions, is able to regulate the downstream pressure within the necessary limits of accuracy and to limit the build-up of pressure under no-flow conditions to prevent a pressure that would cause the unsafe operation of any connected and properly adjusted gas utilization equipment.

f. A self-contained service regulator with no external static or control lines.

If the maximum actual operating pressure of the distribution system is 60 p.s.i. (414 kPa) gage, or less, and a service regulator that does not have all of the characteristics listed in paragraph (a) of this section is used, or if the gas contains materials that seriously interfere with the operation of service regulators, there must be suitable protective devices to prevent unsafe overpressuring of the customer's appliances if the service regulator fails.


If the maximum actual operating pressure of the distribution system exceeds 60 p.s.i. (414 kPa) gage, one of the following methods must be used to regulate and limit, to the maximum safe value, the pressure of gas delivered to the customer:

g. A service regulator having the characteristics listed in paragraph (a) of this section, and another regulator located upstream from the service regulator. The upstream regulator may not be set to maintain a pressure higher than 60 p.s.i. (414 kPa) gage. A device must be installed between the upstream regulator and the service regulator to limit the pressure on the inlet of the service regulator to 60 p.s.i. (414 kPa) gage or less in case the upstream regulator fails to function properly. This device may be either a relief valve or an automatic shutoff that shuts, if the pressure on the inlet of the service regulator exceeds the set pressure (60 p.s.i. (414 kPa) gage or less), and remains closed until manually reset.

h. A service regulator and a monitoring regulator set to limit, to a maximum safe value, the pressure of the gas delivered to the customer.

i. A service regulator with a relief valve vented to the outside atmosphere, with the relief valve set to open so that the pressure of gas going to the customer does not exceed a maximum safe value. The relief valve may either be built into the service regulator or it may be a separate unit installed downstream from the service regulator. This combination may be used alone only in those cases where the inlet pressure on the service regulator does not exceed the manufacturer's safe working pressure rating of the service regulator, and may not be used where the inlet pressure on the service regulator exceeds 125 p.s.i. (862 kPa) gage. For higher inlet pressures, the methods in paragraph (c) (1) or (2) of this section must be used.

j. A service regulator and an automatic shutoff device that closes upon a rise in pressure downstream from the regulator and remains closed until manually reset.

REFERENCES: 49 CFR Subpart D & H, 192.197, 192.353, 192.355, 192.357. Additional information can be found in the "Guidance Manual for Operators of Small Gas Systems" current edition.

5.21.1 REINSTATEMENT OR INSTALLING OF SERVICES AT CUSTOMER METER (NO-FLOW TEST)

No-flow test must be done when installing or reinstating service. Close all internal appliance valves, mark index test hand on the meter for its location (either ½ or 2 foot), turn on inlet gas valve and leave on for 5 minutes and check to see if there is movement of test hand. If no movement of test hand has occurred, the no-flow test has been successful and system is ready to be reinstated.

REFERENCE: 19.8(3), Code of Iowa, & No Flow Test Report

5.22 SERVICE LINES

Service line installation must be as follows:

1. Depth: Each buried service line must be installed with at least 12-inches of cover when on private property. Streets and roads must have at least 18-inches of cover. Service lines must also be installed with at least 12 inches of separation from underground electric utilities, unless encased. Exception: where an underground structure prevents installation


at the required depths, the service line must be able to withstand any anticipated external load.

2. Support and backfill: Each service line must be properly supported on undisturbed or well-compacted soil. The materials used for backfill must be free of materials that could damage the pipe or its coating.

3. Grading for drainage: Where condensate in the gas might cause interruption in the gas supply to the customer, the service line must be graded so as to drain into the main or into drip legs at the low points in the service line.

4. Protection against piping strain and external loading: Service lines must be installed so as to minimize anticipated piping strain and external loading.

5. Installation of service lines into buildings: Underground service lines installed below grade through the outer foundation wall of a building must:

a. Metal service lines must be protected against corrosion; b. Plastic service lines must be protected from shearing action and backfill settlement;

and c. Be sealed at the foundation wall to prevent leakage into the building.

6. Installation of service lines under buildings: Where an underground service line is installed under a building:

a. It must be encased in a gas tight conduit; b. The conduit and service line must, (if the service line supplies the building it

underlies), extend into a normally usable and accessible part of the building; and c. The space between the conduit and the service line must be sealed to prevent gas

leakage into the building and, if the conduit is sealed at both ends, a vent line from the annular space must extend to a point where gas would not be a hazard, and extend above grade, terminating in a rain and insect resistant fitting.

7. Valve requirements: a. Service lines must have a service line valve that meets the requirements of subparts

“B” and “D” of Part 192. A valve incorporated in a meter bar, that allows the meter to be bypassed, may not be used as a service-line valve.

b. A soft seat service line valve may not be used if its ability to control the flow of gas could be adversely affected by exposure to anticipated heat.

c. Each service-line valve on a high-pressure service line, installed above ground or in an area where the blowing of gas would be hazardous, must be designed and constructed to minimize the possibility of the removal of the core of the valve with other than specialized tools.

8. Location of valves:

a. Relation to regulator of meter: service-line valves must be installed upstream of the regulator or, if there is no regulator, upstream of the meter.

b. Outside valves: each service line must have a shut-off valve in a readily assessable location that, if feasible, is outside of the building.


c. Underground valves: each underground service-line valve must be located in a covered durable curb box or standpipe that allows ready operation of the valve and is supported independently of the service lines.

9. General requirements for connections to main piping:

a. Location: each service line connection to a main must be located at the top of the main or, if that is not practical, at the side of the main, unless a suitable protective device is installed to minimize the possibility of dust and moisture being carried from the main into the service lines.

b. Compression-type connection to main: each compression-type service line to main connection must:

i. Be designed and installed to effectively sustain the longitudinal pull-out or thrust forces caused by contraction or expansion of the piping, or by anticipated external or internal loading; and

ii. If gaskets are used in connecting the service line to the main connection fitting, have gaskets that are compatible with the kind of gas in the system.

10. Connections to cast iron or ductile iron mains:

a. Every service line connected to a cast iron or ductile iron main must be connected by a mechanical clamp, by drilling and tapping the main, or by another method meeting the requirements of 192.273 “Cast iron and ductile iron”.

b. If a threaded tap is being inserted, the requirements of 192.151 (b) and (c) must be met.

11. Steel:

a. Each steel service line to be operated at less than 100 p.s.i.g. must be constructed of pipe designed for a minimum of 100 p.s.i.g.

12. Cast iron and ductile iron: (No cast iron pipe in Iowa)

a. Cast or ductile iron pipe less than 6-inches in diameter may not be installed as service lines.

b. If cast iron pipe or ductile iron pipe is installed for use as a service line, the part of the service line that extends through the building wall must be of steel pipe.

c. A cast iron or ductile iron service line may not be installed in unstable soil or under a building.

13. Plastic:

a. Every plastic service line outside a building must be installed below ground level in accordance with 49 CFR Part 192.321, except that:

i. Plastic pipe installed in a vault or any other below grade structure must be completely encased in gas-tight metal pipe and fittings and adequately protected from corrosion.

ii. Uncased plastic pipe may be temporarily installed above ground level as long as the operator can demonstrate that the cumulative above ground


exposure has not exceeded the manufacturers recommended maximum period of exposure or 2 years, whichever is less.

iii. Plastic pipe may not terminate above ground level unless the plastic pipe is encased and protected against deterioration, external damage, and is not used to support external loads.

iv. Plastic pipe that is encased and terminates above ground must be designed to exceed the temperature limits specified in 49 CFR 192.123.

b. Each plastic service line inside a building must be protected against external damage.

14. Copper:

a. Each copper service line installed within a building must be protected against external damage.

15. New service lines not in use: Each service line that is not placed in-service upon completion of installation must comply with one of the following until the customer is supplied with gas:

a. 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.

b. A mechanical device or fitting that will prevent the flow of gas must be installed in the service line or in the meter assembly.

c. The customer’s piping must be physically disconnected from the gas supply and the open pipe ends sealed.

REFERENCE: 49 CFR 192.361, 192.363, 192.365, 192.367, 192.371, 192.373, 192.375, 192.377, 192.379

5.22.1 EXCESS FLOW VALVE (EFV) PERFORMANCE STANDARDS

1. As of February 12th, 2010, Federal rule requires that EFV’s shall be installed on all new or replaced single family residence service lines that operate continuously throughout the year at a pressure not less than 10 p.s.i.g. must be manufactured and tested by the manufacturer according to an industry specification, or the manufacturer’s written specification, to ensure that each valve will:

a. Function properly up to the maximum operating pressure at which the valve is rated;

b. Function properly at all temperatures reasonably expected in the operating environment of the service line;

c. At 10 p.s.i.g.; i. Close at, or not more that 50 percent above, the rated closure flow rate

specified by the manufacturer; and ii. Upon closure, reduce gas flow—

1) For an excess flow valve designed to allow pressure to equalize across the valve, to no more than 5 percent of the manufacturer’s specified closure flow rate, up to a maximum of 20 cubic feet per hour (0.57 cubic meters per hour); or


2) For an excess flow valve designed to prevent equalization of pressure across the valve, to no more than 0.4 cubic feet per hour (.01 cubic meters per hour).

d. Not close when the pressure is less than the manufacturer’s minimum specified operating pressure and the flow rate is below the manufacturer’s minimum specified closure flow rate.

2. An excess flow valve must meet the applicable requirements of subparts “B” and “D” of Part 192.

3. An operator must mark or otherwise identify the presence of an excess flow valve in the service line. This shall be completed by placing an ID tag or some sort of identification

at the meter set in a location that is readily visible and not likely to be damaged or removed.

4 An operator must install an excess flow valve as near as practical to the fitting connecting the service line to the main, and accurately map the location of the installation.

5. If the main is located under pavement, the operator may choose to install the EFV at a location nearest to the curb line allowing easier access for maintenance and replacement. If the operator chooses to install the EFV at the curb line, the installation location must be documented and accurately mapped.

6. If a single family residence service line is damaged and repairs or replacement is required, an EFV shall be installed ONLY if the fitting that connects the service line to the main is replaced or the piping directly connected to this fitting is replaced.

7. An operator shall not install an excess flow valve on a service line where the operator has prior experience with contaminants in the gas stream, where these contaminants could be expected to cause the excess flow valve to malfunction or where the excess flow valve would interfere with necessary operation and maintenance activities on the service, such

as blowing liquids from the line.

8. An operator is to track the number of EFV’s installed on the system each year and record on the annual report.

9. EFV Installation Records: A permanent record of the EFV installations must be maintained. The operator must include in records the manufacturer, type and size of EFV installed. The total number of EFV’s installed in a calendar year as well as the total number of EFV’s installed in the system must be recorded on the PHMSA Annual Distribution Report.

DOCUMTENTATION: Pipeline Test Report &/or Material Installation Record

REFERENCE: 192.381, 192.382, 192.383


5.22.2 EXCESS FLOW VALVE (EFV) INSTALLATION REQUIREMENTS

Division Definitions: EFV – Excess Flow Valve SFR – Single Family Residence SCFH – Standard Cubic Feet per Hour

1. Installation Requirements: After April 14, 2017, each operator must install an EFV on any new or replaced service line serving the following types of services before the line is activated:

a. A single service line to one SFR; b. A branched service line to a SFR installed at the same time as the primary SFR

service line (i.e., a single EFV may be installed to protect both service lines); c. A branched service line to a SFR installed off a previously installed SFR service

line that does not contain an EFV; d. Multifamily residences with known customer loads not exceeding 1,000 SCFH per

service, at time of service installation based on installed meter capacity, and e. A single, small commercial customer served by a single service line with a known

customer load not exceeding 1,000 SCFH, at the time of meter installation, based on installed meter capacity.

2. Installation Exceptions: An operator need not install an excess flow valve if one or more of the following conditions are present:

a. The service line does not operate at a pressure of 10 psig or greater throughout the year;

b. The operator has prior experience with contaminants in the gas stream that could interfere with the EFV’s operation or cause loss of service to a customer;

c. An EFV could interfere with necessary operation or maintenance activities, such as blowing liquids from the line; or

d. An EFV meeting the performance standards in 49 CFR Part 192.381 is not commercially available to the operator.

3. Customer Requests Installation: Existing service line customers who desire an EFV on service lines not exceeding 1,000 SCFH and who do not qualify for one of the exceptions under Part (2) may request an EFV to be installed on their service lines. If an eligible service line customer requests an EFV installation, an operator must install the EFV at a mutually agreeable date. The operator’s rate-setter determines how and to whom the costs of the requested EFVs are distributed.

4. Customer Notification: Operators must notify customers of their right to request an EFV in the following manner:

a. Except as specified in Part (2) above and subpart (e) of this section, each operator must provide written or electronic notification to customers of their right to request the installation of an EFV. Electronic notification can include emails, website postings, and e-billing notices.

b. The notification must include an explanation for the service line customer of the potential safety benefits that may be derived from installing an EFV. The


explanation must include information that an EFV is designed to shut off the flow of natural gas automatically if the service line breaks.

c. The notification must include a description of EFV installation and replacement costs. The notice must alert the customer that the costs for maintaining and replacing an EFV may later be incurred, and what those costs will be to the extent known.

d. The notification must indicate that if a service line customer requests installation of an EFV and the load does not exceed 1,000 SCFH and the conditions of Part (2) are not present, the operator must install an EFV at a mutually agreeable date.

e. Operators of master-meter systems and liquefied petroleum gas (LPG) operators with fewer than 100 customers may continuously post a general notification in a prominent location frequented by customers.

5. Documentation of Customer Notification: An operator must make a copy of the notice or notices currently in use available during PHMSA inspections or State inspections conducted under a pipeline safety program certified or approved by PHMSA under 49 U.S.C. 60105 or 60106.

6. Reporting: Except for operators of master-meter systems and LPG operators with fewer than 100 customers, each operator must report the EFV measures detailed in the annual PHMSA Distribution Report as required by 49 CFR Part 191.11.

7. EFV Installation Procedures: Procedures for the installation of an EFV on any service line with a meter capacity less than 1,000 SCFH and is not exempt under part (2) of this section can be found in Division 6.22.1 of this O&M Plan.

5.22.3 MANUAL SERVICE LINE SHUT-OFF VALVE INSTALLATION (Curb Valve)

Division Definitions - Manual service line shut-off valve: A curb valve or other manually operated valve located near the service line that is safely accessible to operator personnel or other personnel authorized by the operator to manually shut off gas flow to the service line, if needed.

1. Installation requirements: The operator must install either a manual service line shut-off valve or, if possible, based on sound engineering analysis and availability, an EFV for any new or replaced service line with installed meter capacity exceeding 1,000 SCFH.

2. Accessibility and maintenance: Manual service line shut-off valves for any new or replaced service line must be installed in such a way as to allow accessibility during emergencies. Manual service shut-off valves installed under this section are subject to regular scheduled maintenance, as documented by the operator and consistent with the valve manufacturer’s specification.

3. Manual Shut-Off Valve (Curb Valve) Installation Procedures:

a. The Operator shall install a manual shut-off valve that meets the requirements of 49 CFR Part 192 Subpart B “Materials” and Subpart D “Design of Pipeline Components” on all service lines that have a meter capacity exceeding 1,000 SCFH


unless based on sound engineering analysis and availability an EFV shall be installed.

b. The manual shut-off valve, if installed below ground, must be installed in a valve box that allows the Operator to gain access to that valve from above ground at all times.

c. The manual shut-off valve (curb valve) shall be installed on the service line as close to the main as possible unless the Operator determines by sound judgement that a location nearest to the main may possibly hinder the ability to gain access to the valve at all times. Therefore, the Operator shall determine on a case-by-case basis the most appropriate location for the installation of the manual shut-off valve.

4. Location factors to consider:

a. Is the main under concrete? If so, the valve may be installed at the curb line with access to the valve box at all times.

b. If the valve must be installed in a wall-to-wall concrete area, the appropriate valve box and lid must be considered before installation.

c. Is the valve installation location in a low lying area where the valve box may be inaccessible during periods of heavy rain or snow? If so, the location of the valve may need to be moved in a direction that allows access to the valve at all times.

5. Farm Tap Installations:

a. A manual shut-off valve located on the inlet or outlet side of the hairpin first cut regulator on a farm tap setting is to be considered the manual shut-off valve.

6. Manual Shut-Off Valve (Curb Valve) Maintenance Procedures:

a. The manual shut-off valve (curb valve) shall be inspected and maintained at least once every 5 years not to exceed 63 months.

b. Items to Inspect & Maintain: i. If below ground, the valve box shall be inspected for accessibility. If the

valve box is found inaccessible for any reason, the Operator must start remedial action within 90 days of discovery to correct the problem.

ii. If below ground, the valve box shall be inspected for proper alignment. If access to the valve cannot be obtained due to misalignment of the valve box, the Operator must start remedial action within 90 days of discovery to correct the problem.

iii. If the manual shut-off valve is found inoperable, complete repairs or replacement, if needed, must be completed within 12 months.

iv. All manual shut-off valves shall be operated at least 1/8th of a turn. If fully operated, the valve shall be opened and closed slowly to avoid potential damage to any downstream regulator.

v. Any manual shut-off valves requiring lubrication shall be lubricated according to the manufacturers recommended procedures and care shall be taken to avoid over lubrication.


7. Record Keeping:

a. The following items shall be documented on the Manual Shut-Off (Curb Valve) Installation & Maintenance Form found in Division 11 of this O&M Plan or a similar form containing all of the following required information.

i. Installation performed by (name of operator) ii. Date of installation. iii. Address and location of the installation of the manual shut-off valve. iv. Type and size of valve. v. Print line off of valve. vi. Date of maintenance performed.

REFERENCES: 49 CFR Part 192.381, 192.383 & 192.385, Subpart H

5.23 CAST IRON PIPE (No Cast Iron in Iowa)

The utility will provide seal, mechanical clamp or material or device for spigot joint or cast iron caulked bell subjected to 25 psig or more in accordance with 49 CFR 192.753. Seals and bonds will meet requirements of sections 192.53 and 192.143. Buried cast iron pipeline will be protected in accordance with section 192.755.

5.24 PRESSURE TESTING MAINS and SERVICES

1. Steel and Plastic Mains and Services:

a. All steel or plastic mains and service lines shall be tested with air or inert gas, at 90 psig or 1½ times the MAOP whichever is greater.

b. All steel or plastic service lines up to and including 2 inch, 200 feet or less shall be tested for a minimum of 15 minutes. Each additional 50 feet of service line shall be tested for an additional 5 minutes. (Example; a 330 foot service line would require a 30 minute test). Service lines larger than 2 inch shall be tested as mains.

c. Where practical the service tapping tee should be tested with the service line. d. All steel or plastic mains up to and including 4 inch, 1500 feet or less, shall be

tested for a minimum of 1 hour. Each additional 500 feet of main shall be tested for an additional 15 minutes, total test time not required over 8 hours. (Example; a 5350 foot main would require a 3 hour test.)

e. All steel or plastic mains larger than 4 inch, 1500 feet or less shall be tested for a minimum of 1½ hours. Each additional 500 feet shall be tested for an additional 30 minutes, total test time not required over 8 hours. (Example; a 5350 foot main would require a 4 hour test).

f. If a main is repaired by cutting out the damage portion of the pipe as a cylinder, the replacement pipe must be tested to the pressure required for a new line installed in the same location. The test may be made on the pipe before it is installed.

g. All pressure test records to be kept for the life of the segment.

DOCUMENTATION: Pipeline Test Report REFERENCE: 49 CFR 192.503, 192.517


5.25 PRESSURE TESTING TRANSMISSION LINES

1. If a transmission line is repaired by cutting out the damaged portion of the pipe as a cylinder, the replacement pipe must be tested to the pressure required for a new line installed in the same location. This test may be made on the pipe before it is installed.

No person may operate a new segment of pipeline, or return to service a segment of pipeline that has been relocated or replaced until:

a. It has been tested in accordance with subpart J and: i. For plastic pipelines in all locations, the test pressure is divided by a factor

of 1.5. ii. For steel pipelines, the test pressure is divided by a factor determined in

accordance with the following table:

Factor Segment

Class Location Installed Before (Nov. 12, 1970)

Installed After (Nov. 11, 1970)

Converted Under § 192.14

1 1.10 1.10 1.25

2 1.25 1.25 1.25

3 1.40 1.50 1.50

4 1.40 1.50 1.50

b. Each potentially hazardous leak has been located and promptly repaired. c. The test medium must be air, natural gas, inert gas, or liquid that is—

i. Compatible with the material of which the pipeline is constructed; ii. Relatively free from sedimentary materials; and iii. Except for natural gas, nonflammable.

d. Except as provided in 192.505(a), if air, natural gas or inert gas used as the test medium, for steel pipelines the following maximum hoop stress limitations apply:

e. Each joint used to tie in a test segment of pipeline is exempted from the specific test requirements of this subpart, but each non-welded joint must be leak tested at not less than its operating pressure.

f. Pressure testing must be conducted for 8 hours on transmission lines in all locations. For fabricated units and short section of pipe where a post installation test is impractical, a pre-installation test must be conducted for 4 hours.

g. All pressure test records to be kept for the life of the segment.

DOCUMENTATION: Pipeline Test Report REFERENCE: 49 CFR 192.503, 192.517

Maximum Hoop Stress Allowed As Percentage of SMYS

Class Location Natural Gas Air or Inert Gas

1 80 80

2 30 75

3 30 50

4 30 40


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DIVISION SIXCORROSION CONTROL

6.1 CORROSION CONTROL PROGRAM

The utility shall carry out a corrosion control program, (as per new 192.605 (B) (2)), under the direction of a person qualified in pipeline corrosion control, for the protection of metallic pipelines from external, internal, and atmospheric corrosion.

Each operator shall maintain a record of each test, survey, or inspection required by this subpart in sufficient detail to demonstrate the adequacy of corrosion control measures or that a corrosive condition does not exist. These records must be retained for at least 10 years after the pipeline has been taken out of service. REFERENCES: 49 CFR 192, Subpart I. 192.49, 192.491, 192.453. For general information, see the "Guidance Manual for Operators of Small Gas Utilities" current edition.

6.2 PROTECTIVE COATING

1. All metallic pipelines installed below ground as a new piping system or a replacement system shall be entirely coated and inspected prior to lowering into the ditch and backfilled, and any damage detrimental to effective corrosion control must be repaired. It is absolutely essential that the instructions supplied by the manufacturer of the coating material be followed precisely. Some general guidelines for installation are as follows: (for specific instructions, follow manufactures instructions)

a. Properly clean pipe surface to remove soil, oil, grease, and any moisture. b. Uses careful priming techniques to avoid moisture, refer to manufacturer’s

instructions. c. When applying the coating materials, be sure pipe surface is dry (see

manufacturer’s recommendations). Make sure soil or other foreign material does not get under coating during installation.

d. Only backfill with soil that is free of objects that may damage the coating. Coating damage can be caused by the careless backfilling operations when rocks and debris strike and break the coating. Over time a break in the coating will lead to corrosion of the pipe.

Each external protective coating must be protected from damage resulting from adverse ditch conditions or damage from supporting blocks. If coated pipe is installed by boring, driving, or other similar method, precautions must be taken to minimize damage to the coating during installation.

REFERENCES: 49 CFR 192.461, 192.483. A discussion of different types of coatings and handling practices is included in the “Guidance Manual for Operators of Small Gas Systems” current edition.


6.3 CATHODIC PROTECTION

All buried metallic pipeline shall be cathodically protected. The utility shall carry out a program that includes the installation, testing, and upgrading of cathodic protection throughout the system.

The program shall be based on procedures that include design, installation, operation, and maintenance of a cathodic protection system. Procedures will be carried out by or under the direction of a person qualified by experience and training in pipeline corrosion control methods.

1. To determine the need of cathodic protection:

a. Determine type(s) of pipe in your system: bare steel, coated steel, cast iron, plastic, galvanized steel, ductile iron, or other.

b. Date gas system was installed. On steel pipe installed after July 1 1971, the system must be cathodically protected in its entirety.

c. Who installed the pipe? By contacting the contractor and other operators who had pipe installed by the same contractor, operators may be able to obtain the valuable information needed as:

i. Type of pipe in ground. ii. If pipe is electrically isolated. iii. If gas pipe is in common trench with other utilities.

d. Pipe location, maps and drawings. Locate old construction drawings or current system maps. If no drawings are available use a metallic pipe locator.

Make sure that customer meters are electrically insulated. If system has no meters, check to see if gas pipe is electrically insulated from house or mobile home pipe.

2. Criteria for cathodic protection:

There are five criteria listed in Appendix D of Part 192, which qualify as cathodic protection. Operators can meet the requirements of any one of the five to be in compliance.

One of the most commonly used criteria is the -0.85 volt, as follows: a. With the protective current applied, a voltage of at least -0.85 volts measured between the pipeline and a saturated copper-copper sulfate half cell (this

measurement is called the pipe-to-soil potential reading). b. The pipe-to-soil voltage meter is a simple “go, no-go” type of monitoring of a

cathodic protection system. If the meter reaches at least -0.85 volts, the operator knows that the steel pipe is under cathodic protection. If not, remedial action must be taken promptly.

c. Be sure to take into consideration the voltage IR drop, which is the difference between the voltage at the top of the pipe and the voltage at the surface of the earth.

NOTE: When testing for cathodic protection on a metallic gas system, avoid taking pipe-to-soil readings over or near anodes.

DOCUMENTATION: Exposed Pipe/Bellhole Report, Pipeline Test Report, Anode Test-Station Report REFERENCE: 49 CFR 192.463 A discussion of principles and practices of cathodic protection included in the “Guidance Manual for Operators of Small Gas Systems” current edition.


6.4 CORROSION CONTROL REQUIREMENTS FOR PIPELINES INSTALLED AFTER JULY 31, 1971

All buried metallic pipe installed after July 31, 1971, must be properly coated and have a cathodic protection system designed to protect the pipe in its entirety.


1. For newly constructed metallic pipelines, each coated pipeline installed must have a cathodic protection system installed and placed in operation in its entirety within one year

after completion of construction of the pipeline. If it is demonstrated, by tests, investigation or experience, that a corrosive environment does not exist, the line may be

installed without the coating or cathodic protection. However, no later than 6 months after installation tests shall be made to prove that no corrosion control measures were necessary. If tests indicate that corrosion control is necessary, a cathodic protection program will be initiated.

NOTE: In general, all new pipelines will be coated and cathodically protected, as it is extremely difficult and costly to prove that a non-corrosive environment exists.

2. Cathodic protection requirements do not apply to electrically isolated, metal alloy fittings in plastic pipelines if:

a. If the alloy (such as stainless steel) of the fitting provides corrosion control; and b. If corrosion pitting of the fitting will not cause leakage.

REFERENCE: 49 CFR 192.455, 192.461

6.5 CORROSION CONTROL REQUIREMENTS FOR GAS DISTRIBUTION PIPELINES INSTALLED BEFORE AUGUST 1, 1971

Bare or coated distribution pipelines, regulating, and measuring stations shall be cathodically protected in areas of active corrosion.

1. Active corrosion will be determined by: (a) electrical survey; (b) where electrical survey is impractical, by the study of corrosion and leak history records; or (c) by leak detection surveys. Active corrosion means continuing corrosion, which unless controlled, could result in a condition that is detrimental to public safety.

2. Continuing corrosion will be considered active corrosion if it occurs on the distribution system within the city limits and within 100 yards of a building intended for human occupancy, regulator stations, and at highway and railroad crossings. Pipeline with active corrosion will be cathodically protected, repaired, or replaced.

3. The use of electrical surveys to find areas of active corrosion will be considered impractical in the following situations:

a. In areas of fluctuating stray D.C. currents, such as those caused by telluric currents and electrical railway systems;


b. Where the pipeline is more than two feet in from and generally parallel to the edge of a paved street or within wall to wall pavement areas;

c. Where pipelines are in a common trench with other metallic structures; or d. Where pipe is electronically discontinuous.

NOTE: Extreme hardship and expense may render an electrical survey impractical for a given pipeline for conditions other than listed above. In these cases, the impracticability of the electrical survey must be documented with test studies, or past experience with electrical systems for pipelines in a similar environment. In areas where electrical surveys cannot be run to determine corrosion, leakage surveys will be conducted on a more frequent basis. The electrical surveys conducted to find active corrosion must be run by a person qualified by experience and training in pipeline corrosion control methods. Some basic concepts and practical considerations about corrosion control are discussed in the "Guidance Manual for Operators of Small Gas Systems" current edition.

6.6 CORROSION CONTROL MONITORING

Cathodic protection levels will be tested at least once per calendar year at intervals not exceeding 15 months to determine adequate protection levels as required under 49 CFR 192, Subpart I.

Separately protected lines (not in excess of 100 feet) may be surveyed on a sampling basis. At least 10 percent of these protected structures, distributed over the entire system must be surveyed each calendar year, with a different 10 percent checked each subsequent year, so that the entire system is tested in each 10-year period.

Operators must take prompt corrective action to correct any deficiencies indicated by the monitoring. Operator must start remedial action within 90 days from the date of discovery, and completed prior to next survey. Extensive corrosion is defined as pitting causing 30% of wall loss. If remaining wall thickness is less than 70% then that section has to be repaired or replaced.

REFERENCE: 49 CFR 192.483, 192.485, 192.487, 192.489

1. External corrosion control: Electrical isolation.

a. Each buried or submerged pipeline must be electrically isolated from other underground metallic structures, unless the pipeline and the other structures are electrically interconnected and cathodically protected as a single unit.

b. One or more insulating devices must be installed where electrical isolation of a portion of a pipeline is necessary to facilitate the application of corrosion control.

c. Except for unprotected copper inserted in ferrous pipe, each pipeline must be electrically isolated from metallic casings that are a part of the underground system. However, if isolation is not achieved because it is impractical, other measures must be taken to minimize corrosion of the pipeline inside the casing.

d. Inspection and electrical tests must be made to assure that electrical isolation is adequate.


2. Testing Methods

a. Isolation joint testing using an insulator tester: Place prongs on either side of the insulation joint and test for conductivity. A volt meter will not work.

b. Isolation joint testing using external power supply: Take a pipe to soil reading on both sides of the Isolation Joint. Record this reading. If the difference is 100mv or more, we will consider the insulator to be good. If the readings are less than 100mv apart, induce DC current to one side of the insulator and take the readings again. If the readings spread apart, the insulator is good.

c. Insulator test using line locator: Switch the line locater to the conductive mode and connect the transmitter to the pipeline at a test point remote from the insulator. Locate pipe from the test point across the insulator, while monitoring signal strength. If no sudden drop in signal strength is detected, insulator is bad.

3. In addition to tests on pipeline facilities and structures, casings will include testing for shorts using one of the following methods:

a. Casing test using line locator -- Switch the line locater to the conductive mode and connect the transmitter to the pipeline at a test point remote from the casing. Locate pipe from the test point across the casing, while monitoring signal strength. If no sudden drop in signal strength is detected, the casing is isolated from gas main.

b. Casing test using external power supply -- Take potential reading of the casing and pipeline. Induce a negative D.C. current at a test point remote from the casing and then re-check the potential at the casing. If there is no appreciable difference in the potential readings at the casing, no short exists.

c. Criteria for casing test -- Take a casing to soil reading. If there is no test lead, the casing vent pipe may be used. Next take a pipe to soil reading at a nearby riser or test point (up to 1100 feet from the end of the casing). Record both readings.

If the difference between the two readings is 100 millivolts or more, the casing will be considered isolated from the carrier pipe. If the difference is less than 100 millivolts, the casing will be considered shorted to the carrier pipe.

To confirm that a casing is shorted, alter the potential of either the carrier pipe or the casing, and take another pipe to soil reading. If there is essentially no change in the casing or carrier pipe reading, this confirms the casing and pipe are shorted. If there is an appreciable change in one of the readings, the casing will not be considered shorted.

4. Remedial ActionIf the casing is determined to be shorted, the short will be cleared if practical. If the short is not cleared, the casing vents will be monitored with leak detection equipment at the same frequency as required by 192.721. A record will be made of each test and of the results recorded.

If a short is found it will be monitored in business districts, at intervals not exceeding 4-1/2 months, but at least four times each calendar year; and outside business districts, at intervals not exceeding 7-1/2 months, but at least twice each calendar year with leak detection equipment until proper repairs can be completed.


Operators are required to maintain cathodic protection (CP) on pipelines scheduled for replacement. After CP has been installed, CP shall be maintained until that line has been replaced or removed.

5. Test Stations

Transmission and distribution lines should have adequate test points for electrical measurements to determine the adequacy of cathodic protection.

6. Rectifier

a. Each pipeline that is under cathodic protection must be tested at least once each calendar year, but with intervals not exceeding 15 months, to determine whether the cathodic protection meets the requirements of § 192.463. However, if tests at those intervals are impractical for separately protected short sections of mains or transmission lines, not in excess of 100 feet (30 meters), or separately protected service lines, these pipelines may be surveyed on a sampling basis. At least 10 percent of these protected structures, distributed over the entire system must be surveyed each calendar year, with a different 10 percent checked each subsequent year, so that the entire system is tested in each 10-year period.

b. Each cathodic protection rectifier or other impressed current power source must be inspected six times each calendar year, but with intervals not exceeding 2-1/2 months, to insure that it is operating.

c. Each reverse current switch, each diode, whose failure would jeopardize structure protection must be electrically checked for proper performance six times each calendar year, but with intervals not exceeding 21/2 months. Each other interference bond must be checked at least once each calendar year, but with intervals not exceeding 15 months.

d. Each operator shall take prompt remedial action to correct any deficiencies indicated by the monitoring.

REFERENCE: 49 CFR 192.465, 192.467, 192.469

6.7 INSPECTING UNCOVERED PIPELINE

1. Whenever a portion of buried pipeline is uncovered and the pipe is bare or the coating has deteriorated, the exposed portion shall be examined for evidence of external corrosion. If external corrosion is found; remedial action must be taken to the extent required by 49

CFR 192.483 and the applicable paragraphs of sections 192.485, 192.487 and 192. 489.

a. If any pipe is removed from a pipeline, the internal surface shall be inspected for evidence of corrosion.

b. Anytime the operator exposes pipe and damage or corrosion is discovered, the operator is required to continue to expose pipe until the extent of the damage to pipe and/or coating is determined.

c. An Exposed Pipe/Bellhole Report will be filled out every time you have exposed underground piping with or without damage.

DOCUMENTATION: Exposed Pipe/Bellhole Report, 49 CFR 192.459, 192.475, 192.491, Pipeline Test Report, Report of Abandoned Facilities


6.8 ATMOSPHERIC CORROSION CONTROL AND INSPECTION

Above ground piping subject to corrosive conditions which cannot be controlled by cathodic protection shall be coated or jacketed to prevent atmospheric corrosion. All above ground piping shall be inspected at intervals at least once every three calendar years but not to exceed 39 months, with particular attention given to soil-to-air interface and pipe support locations. Re-evaluate pipeline exposed to the atmosphere and take remedial action (192.487) whenever necessary to maintain protection against atmospheric corrosion.

DOCUMENTATION: Atmospheric Corrosion Survey REFERENCES: 49 CFR 192.481, 192.483,192.487 Remedial measures.

6.9 INTERNAL CORROSION CONTROL

1. Internal Corrosion Control on New Transmission Lines After May 23, 2007:

a. After May 23, 2007, each new transmission line and each replacement of line pipe, valve, fitting, or other component in a transmission line must have features incorporated into its design and construction to reduce the risk of internal corrosion. At a minimum, unless it is impracticable or unnecessary to do so, each new transmission line or replacement of line pipe, valve, fitting, or other line component in a transmission line must:

i. Be configured to reduce the risk that liquids will collect in the line. ii. Minimize dead ends and low areas. iii. Minimize aerial crossings. iv. Minimize entry of water and corrosive gases.

2. Internal Corrosion Control on Transmission Lines Built Before May 23, 2007:

a. Repairs and modifications of a transmission line built before May 23, 2007, must consider, unless impractical or unnecessary the items listed above for a new transmission line.

3. Record Keeping:

a. Records must be maintained that demonstrate compliance with internal corrosion design requirements or to document that the provisions are impractical or unnecessary and kept for the life of the system.

DOCUMENTATION: Pipeline Test Report, Exposed Pipe/Bellhoe Report, Pipeline Purge Test Report REFERENCES: 192.476


DIVISION SEVEN WELDING AND JOINING

7.1 WELDING AND JOINING

1. Welding and joining of materials shall be performed in accordance with written standards consistent with applicable regulations.

a. Steel Pipeline -- All welding done on steel pipelines shall be performed by a welder qualified under the utility's qualified welding procedures and 49 CFR 192.221 through 192.245. Joining of materials other than by welding will be in accordance with 49 CFR 192.271 through 192.287.

b. Welding Procedures – Welding must be performed by a qualified welder or welding operator in accordance with welding procedures qualified under section 5, section 12, Appendix A or Appendix B of API Std 1104, or section IX of the ASME Boiler and Pressure Vessel Code (ASME BPVC) to produce welds meeting the requirements. The quality of the test welds used to qualify welding procedures must be determined by destructive testing in accordance with applicable welding standards.

c. Welder Qualification – Except as provided in paragraph (3) of this section, each welder or welding operator must be qualified in accordance with section 6, section 12, Appendix A or Appendix B of APE Std 1104, or section IX of the ASME Boiler and Pressure Vessel Code (ASME BPVC). However, a welder or welding operator qualified under and earlier edition than listed in 49 CFR Part 192.7 may weld but may not requalify under that earlier edition.

i. A welder may qualify to perform welding on pipe to be operated at a pressure that produces a hoop stress of less than 20% of SMYS by performing an acceptable test weld, for the process to be used, under the test set forth in section I of Appendix C in CFR Part 192 Subpart E. Each welder who is to make a welded service line connection to a main must first perform an acceptable test weld under section II of Appendix C of CFR Part 192 Subpart E as a requirement of the qualifying test.

REFERENCES: 192.225, 192.229. For an example of a qualified pipeline welding procedure, see the Model Welding Procedures of the Iowa Association of Municipal Utilities. Criteria for establishing a qualified welding standard are found in API Standard 1104 and 49 CFR 192, Appendix C. Also see the "Guidance Manual for Operators of Small Gas Systems" current edition.

d. Plastic Pipeline -- All joining of plastic pipe shall be performed in accordance with procedures recommended by the manufacturer. These procedures are on file at the utility's operations center. The procedures shall incorporate the recommendations contained in 49 CFR 192.273 (C), 192.285 and 192.287. The utility shall provide training to personnel sufficient to meet these requirements or shall engage a contractor trained in the procedure.

e. Whenever joining dissimilar PE materials, joining will be done by mechanical, electro or socket fusion procedures only.

REFERENCES: 192.281, 192.283. 192.287


DIVISION EIGHT ODORIZATION

8.1 ODORIZATION (General)

1. Gas shall be odorized so that, at a concentration in air of one-fifth the explosive limit, the gas is readily detectable by a person with a normal sense of smell. Odorant level shall be checked as necessary and at least quarterly. Also a record of the amount of odorant used shall be made as necessary and at least quarterly. Odorant sampling tests must be done with an instrument that can measure percent natural gas in air, following the manufacturer’s procedures for the instrument. The odorant sampling instrument must also be calibrated according to the manufacturer’s recommended procedures and a record of the instruments calibration shall be documented and kept on file. In Division 11 are the Odorant Usage Report and the Odorometer Test Report (Sniff Test) that may be used to document and record findings.

a. The lower explosive limit for natural gas is approximately 5 (five) percent natural gas in air by volume; therefore, odorant must be present at approximately 1% gas in air by volume. The odorant and its product of combustion shall not be toxic to humans, or harmful to components that make up your piping system. The odorant shall not be soluble in water to an extent greater than 2.5 parts to 100 parts by weight. To assure that all gas in distribution mains and service lines is odorized, periodic instrument checks will be made at system extremities.

b. A record of the type of odorant used in the system shall be maintained, along with the manufacturer's recommended rate of odorization.

c. Odorization equipment that introduces the odorant without wide variation in the level of odorant shall be used. The equipment will be maintained as recommended by the manufacturer.


8.2 TESTING OF ODORANT LEVEL

In addition to testing for odorant injection rate, the utility will perform quarterly instrument testing; including tests at the outer extremities of the pipeline system, to verify that the odor is distinctive at 1/5 the lower explosive limit. The utility will maintain records of injection rate and odor sampling for a minimum of five years. REFERENCES: 49 CFR 192.625

8.3 FOLLOW-UP ACTION FOR SNIFF TEST REPORT OVER 20% LEL

If an odorant sniff test is taken and the results show a reading over 20% LEL (1% gas in air) when odorant is readily detectable, two more tests should be taken at adjacent residences. If the sniff test readings are below 20% LEL than the odorant level will be considered adequate. If the readings are still over 20% LEL, the odorant tank shall be checked to make sure that the odorant in the tank is adequate. If the odorant in the tank is adequate, the odorant rate shall be increased at a small rate and sniff test taken at the same location where the first checks were made. Wait three days before retesting. Continue this procedure until sniff test readings are below 20% LEL.

DOCUMENTATION: Odorant Usage Report and Odorometer Test Report (Sniff Test) REFERENCES: 49 CFR 192.625. For federal information see the "Guidance Manual for Operators of Small Gas Utilities," current edition.


DIVISION NINE PEAK SHAVING

(This division applies only if the utility operates a peak shaving facility.)

9.1 PEAK SHAVING (General)

The utility's propane storage facilities shall be designed to ensure continuity of service during periods when system demands cannot be fully met by the pipeline supplier. The utility will operate its peak shaving equipment in accordance with applicable regulations.

REFERENCES: 49 CFR 192.11, 192.163, 192.165, 192.167, 192.169, 192.171, 192.173, 192.175, 192.177 and Iowa Code 19.76

9.2 INSTALLATION AND MAINTENANCE

The installation and maintenance of liquefied petroleum gas peak shaving facilities shall be in accordance with National Fire Protection Association's Standard 58 & 59 (ANSI/NFPA 58 & 59).

9.3 EMERGENCY PROCEDURES -- TANK LEAK

1. In the event of a leak at the peak shaving facilities, the following procedures should be followed:

a. Approach gas leak from upwind and keep out of cloud. b. Evacuate people in probable path of cloud immediately, ON FOOT. Do not allow

motors to operate in the area. c. Eliminate sources of ignition in the probable path of the cloud such as gasoline and

electric motors, pilot lights, electric lights and appliances (have service cut to affected area by utility), telephone, etc.

d. Do not permit anyone to enter the cloud, except in extreme emergency. e. Speed up evaporation of liquid by using water fog nozzle. f. Have fire department stand by in case of flash. g. After evaporation, check low places -- pockets, basements, etc. -- downwind for

vapors. h. Do not restore sources of ignition until complete evaporation has taken place and

the area thoroughly checked.

9.4 OPERATING INSTRUCTIONS

(Applicable operating procedures are attached.)


DIVISION TEN GAS OPERATING AND MAINTENANCE PLAN FORMS

Table of Contents

NOTE: Any of the following forms containing vital information regarding the integrity of the pipeline system must be retained for a minimum of 10 years to fulfill Integrity Management Program requirements.

Leak Investigation & Repair : Pg. 80 & 81(Report of Gas Leak): This is a required form for recording the investigation of suspected leaks on all indoor and outdoor gas system piping and components.

Electronic CGI Calibration Record: Pg. 82 This form is to be used as a record for the calibration of your CGI units. Without a record of calibration, the CGI findings cannot be accurately verified.

Dig-In Report: Pg. 83 & 84 This form is used to collect dig-in damages to utility services by anyone digging around gas lines. This data collection of events, causes, and root cause will be entered on the annual reports starting in 2012.

Excavation “Stand-by” Report: Pg. 85 This form is to be completed for those operators who have transmission lines where it is required to be present when excavations occur within 25 ft. of the pipeline.

Line Hit/Accident Investigation Follow-Up Report: Pg. 86 This report is to be completed after a line hit or accident has occurred with or without the release of gas to ensure that all procedures were followed and documented.

Transmission & Distribution Patrolling Report: Pg. 87(For Patrols of Areas Susceptible to Abnormal Physical Movement): This form is used for both scheduled and unscheduled patrols of the system. See section 4.2.

Atmospheric Corrosion Survey & Atmospheric Corrosion Location Form: Pg. 88 & 89 These forms are to be used to record the findings of an Atmospheric Corrosion Survey and to document the locations of any required remedial actions. See section 6.8.

Leak Survey Report: Pg. 90This report (or a report from a qualified contractor) is used for recording leak survey results. See section 5.3.

Valve Inspection and Maintenance Log: Pg. 91 & 92Page one of this two-page form is used to record the inspection and maintenance of a particular valve in the system. Page two (reprint in reverse side) is used to sketch the location of the valve. See section 4.4.

Manual Shut-Off (Curb Valve) Installation & Maintenance Form: Pg. 93 This form is to be used to record the installation and maintenance performed on any curb valves installed in the system. See section 5.22.3.


Regulator Station Inspection Report: Pg. 94This form is used to document and verify that a regulator station has been properly inspected and all required items have been checked. See section 4.5.

Relief Valve Inspection Report: Pg. 95This form is used to document and verify that a relief valve has been properly inspected and all required items have been checked. See section 4.6.

Farm Tap Regulator & Relief Inspection Form: Pg. 96 This form is to be used to record the required maintenance of farm tap regulators and relief valves. See section 4.6.2.

Gas Pipeline Pre-Installation Checklist: Pg. 97, 98, & 99 This form is an optional form to complete before installing service lines or mains. This form provides a “checklist” to complete to ensure that all relevant information has been considered and all procedures will be followed.

Pipeline Test Report: Pg. 100 These reports are to record information about welds, taps, fittings, pressure tests, trenching, etc., for each section of pipe placed in service or reinstated. See sections 5.3, 5.4, 5.15, 5.17, 5.22, 5.22.1, 5.22.2, 5.22.3, 5.25.

Exposed Pipe/Bellhole Report: Pg. 101 This form is to be completed every time a gas line is exposed. See section 5.3, 5.4, 5.15, 5.17, 5.22, 5.22.1, 5.22.2, 5.22.3, 5.25.

Pipeline Purge Test Report: Pg. 102 Use this report to record information on purging when installing new pipe or old pipeline abandonment, i.e. service lines, sections of main. See sections 5.4, 5.5, and 5.17.

Material Installation Record: Pg. 103 This form allows you to record all materials that were used during installations and repairs meeting DIMP requirements.

No-Flow Test Report: Pg. 104 Use this report to record no-flow (shut-in) test results from when installing a new meter or restoring service. See section 3.1.1

Report of Abandoned Facilities: Pg. 105 This report is required for all abandoned facilities, not including facilities that are temporarily disconnected. See sections 5.5, and 6.7.

Anode Test-Station Report: Pg. 106 & 107This is a two-page form can be used to record tests of anodes with or without a rectifier. See section 6.3 and 6.6.

Cathodic Protection Record (Pipe-to-Soil Readings): Pg. 108 An additional form, which can be used to record pipe-to-soil readings. See section 6.3 and 6.6.

Odorant Usage Report: Pg. 109This form is used to calculate and record the system odorization rate. It assumes use of diverted flow odorization and may need to be modified for injection systems. See sections 8.2, and 8.3.

Odorometer Test Report (Sniff Test): Pg. 110This form is used to record tests for the detectability of odorant at various points on the distribution system. See sections 8.1, 8.2, and 8.3.


Customer Owned Piping & EFV Notification Record: Pg. 111 This form provides a record of customers receiving notification of their responsibilities for maintaining customer owned piping and their options to request the installation of an EFV.

Determination of MAOP in Natural Gas Pipelines: Pg. 112 & 113This form is used to document maximum allowable operating pressure (MAOP) on steel and plastic piping. This form is also to document the MAOP after uprating. See section 5.2

Mechanical Fitting Failure Report: Pg. 114 This form is used to collect mechanical fitting failures that will be reported annually on the Mechanical Fitting Failure Report 7100.1-2 or may be submitted throughout the year.

Record of Lost and Unaccounted-For Gas: Pg. 115This is a worksheet to record differences between purchased gas and metered sales. Over time, it is an indicator of system leaks and metering errors.

Excavation and Trenching Guidance System: Pg. 116-120This five page form may be used when planning an excavation and trenching. Included are the inspection reports and safety checklists to help operators perform excavation and trenching safely.


LEAK INVESTIGATION & REPAIR Utility:_______________________________________________________________________

REPORT OF LEAK

Date Reported:_________________________Time:___________________ AM PM

Reported by:_______________________________Address:_____________________________________________

City/State/Zip:_____________________________________________Phone No.:___________________________

Person reporting is: Customer General Public Other:_____________________________________

Reason for suspected leakage:_____________________________________________________________________

Location of suspected leakage:____________________________________________________________________

DISPATCHED

Person receiving leak call:________________________________________________________________________

Date:_________________________Time:_______________________ AM PM

Person dispatched to:___________________________________Title:_____________________________________

LEAK INVESTIGATION

Time arrived at leak location:_________________________________ AM PM

Leak found: In House Outside ABOVE Ground Outside BELOW Ground NO LEAK

Leak Classification: 1 2 3 Classified with a CGI: Yes No

Gas % found:______________ CO % found:_________________ Completed bar-holes Yes No

If underground leak, map of leak migration pattern completed: Yes No (see reverse side for leak map)

REPAIR

Date repair started:_______________________Date finished:____________________________

Leak location: Meter Set House piping Service Line Main Other:____________________

Repairs made:____________________________________________________________________

______________________________________________________________________________

Conducted No Flow Test: Yes No Start Time:______________Stop Time:________________

Any movement of the ½ ft or 2 ft hand? Yes No

Signature:________________________________________________


MAP OF LEAKAGE AREA

(Bar-hole mapping is required for all underground leaks)

NOTE: Map information should include at a minimum, bar-hole locations with CGI readings to

determine the boundaries of the spread migration.


Utility

ELECTRONIC CGI CALIBRATION RECORD

SERIAL NUMBER:

NOTE: Calibration on each CGI is to be performed per the manufacturers recommended procedures. The following table is to be completed each time calibration is performed. The table is to be completed with a "GO", "NO GO" or "NA" response to each of the 5 calibration items. If a "GO" response is entered, calibration was successful. If a "NO GO" response is entered, calibration was not successful and should be addressed in the comments section. If an "NA" response is entered, that calibration item is "not applicable" to your machine.

CALIBRATION ITEMS

DATE OPERATOR LEL UEL CO H2S PROPANE COMMENTS


DIG-IN REPORT Part A – Who is Submitting This Information Who is providing the information? Electric Engineer/Design Equipment Manufacturer

Excavator Insurance Liquid Pipeline Locator Natural Gas One-Call Center Private Water Public Works Railroad Road Builders State Regulator Telecommunications Unknown/Other

Name of the person providing the information:

Part B - Date and Location of Event*Date of Event: (MM/DD/YYYY)*Country *State *County City Street address Nearest Intersection*Right of Way where event occurred Public: City Street State Highway County Road Interstate Highway Public-Other Private: Private Business Private Land Owner Private Easement

Pipeline Power /Transmission Line Dedicated Public Utility Easement Federal Land Railroad Data not collected Unknown/Other

Part C – Affected Facility Information*What type of facility operation was affected?

Cable Television Electric Natural Gas Liquid Pipeline Sewer (Sanitary Sewer) Steam Telecommunications Water Unknown/Other

*What type of facility was affected? Distribution Gathering Service/Drop Transmission Unknown/Other

Was the facility part of a joint trench? Unknown Yes No

Was the facility owner a member of One-Call Center? Unknown Yes No

Part D – Excavation Information*Type of Excavator

Contractor County Developer Farmer Municipality Occupant Railroad State Utility Data not collected Unknown/Other

*Type of Excavation Equipment Auger Backhoe/Trackhoe Boring Bulldozer Cable Plow Directional Drilling Explosives Farm Equipment Grader/Scraper Hand Tools Milling Equipment Probing Device Trencher Vacuum Equipment Data Not Collected Unknown/Other

*Type of Work Performed Agriculture Cable Television Curb/Sidewalk Bldg. Construction Bldg. Demolition Drainage Driveway Electric Engineering/Survey Fencing Grading Irrigation Landscaping Liquid Pipeline Milling Natural Gas Pole Public Transit Auth. Railroad Maint. Road Work Sewer (San/Storm) Site Development Steam Storm Drain/Culvert Street Light Telecommunication Traffic Signal Traffic Sign Water Waterway Improvement Data Not Collected Unknown/Other

Part E – Notification *Was the One-Call Center notified?

Yes (If Yes, Part F is required) No (If No, Skip Part F) If Yes, which One-Call Center? If Yes, please provide the ticket number

Part F - Locating and Marking *Type of Locator

Utility Owner Contract Locator Data Not Collected Unknown/Other *Were facility marks visible in the area of excavation?

Yes No Data Not Collected Unknown/Other *Were facilities marked correctly?

Yes No Data Not Collected Unknown/Other


Part G – Excavator DowntimeDid Excavator incur down time?

Yes No If yes, how much time?

Unknown Less than 1 hour 1 hour 2 hours 3 or more hours Exact Value ______

Estimated cost of down time? Unknown $0 $1 to 500 $501 to 1,000 $1,001 to 2,500 $2,501 to 5,000

$5,001 to 25,000 $25,001 to 50,000 $50,001 and over Exact Value ______

Part H – Description of Damage*Was there damage to a facility?

Yes No (i.e. near miss) *Did the damage cause an interruption in service?

Yes No Data Not Collected Unknown/Other If yes, duration of interruption

Unknown Less than 1 hour 1 to 2 hrs 2 to 4 hrs 4 to 8 hrs 8 to 12 hrs 12 to 24 hrs 1 to 2 days 2 to 3 days 3 or more days Data Not Collected Exact Value _______

Approximately how many customers were affected?

Unknown 0 1 2 to 10 11 to 50 51 or more Exact Value _______

Estimated cost of damage / repair/restoration Unknown $0 $1 to 500 $501 to 1,000 $1,001 to 2,500 $2,501 to 5,000

$5,001 to 25,000 $25,001 to 50,000 $50,001 and over Exact Value ______ Number of people injured

Unknown 0 1 2 to 9 10 to 19 20 to 49 50 to 99 100 or more Exact Value _______

Number of fatalities Unknown 0 1 2 to 9 10 to 19 20 to 49 50 to 99 100 or more Exact Value _______

Part I – Description of the Root Cause**Please choose one One-Call Notification Practices Not Sufficient Locating Practices Not Sufficient

No notification made to the One-Call Center │ Facility could not be found or located Notification to one-call center made, but not sufficient │ Facility marking or location not sufficient Wrong information provided to One Call Center │ Facility was not located or marked

│ │ Incorrect facility records/maps Excavation Practices Not Sufficient │ Miscellaneous Root Causes

Failure to maintain marks │ One-Call Center error Failure to support exposed facilities │ Abandoned facility Failure to use hand tools where required │ Deteriorated facility Failure to test-hole (pot-hole) │ Previous damage Improper backfilling practices │ Data Not Collected Failure to maintain clearance │ Other Other insufficient excavation practices │

Part J – Additional Comments


EXCAVATION “Standby” REPORT

For excavations occurring within 25 ft. of a Transmission Pipeline

Ticket Information:

Date & Time One-Call Ticket was processed:________________________________________________

Name of Company performing excavation:__________________________________________________

Type of excavation to be completed:_______________________________________________________

Name(s) of Excavation Company contact personnel provided to One-Call:_________________________

_____________________________________________________________________________________

Locate Information:

Date & Time locating was completed:______________________________________________________

Locate completed by:___________________________________________________________________

Approximate distance of pipeline to “white line” area:_________________________________________

Was contact made with Excavation Company to set up a meet time?______________________________

If so, who did you contact (name) and when was the meet scheduled?_____________________________

____________________________________________________________________________________

Was the meeting arrangement/excavation schedule followed?___________________________________

If not, why not. What circumstances changed?_______________________________________________

_____________________________________________________________________________________

Provide a brief description of the excavation and the events that occurred during the excavation:________

_____________________________________________________________________________________

_____________________________________________________________________________________

Did any of your facilities get damaged during the excavation?___________________________________

If facilities were damaged, was a Dig-in Report completed?_____________________________________

Description of damages:_________________________________________________________________

_____________________________________________________________________________________

_____________________________________________________________________________________

Was the Excavation Company reported to the Attorney General’s Office?__________________________


LINE HIT/ ACCIDENT INVESTIGATION:

FOLLOW-UP REPORT

Note: This report shall be completed after a line hit or accident has occurred with or without the

release of natural gas.

Utility: ______________________________________________________________________

Follow-up Report conducted by:___________________________________________________

Date:_____________________________

Date of Line Hit/Accident:_______________________________

Did the line hit/accident involve the release of gas?____________________________________

Were there any injuries or fatalities?________________________________________________

Was there any property damage?___________________________________________________

What was the cause of the line hit/accident?__________________________________________

__________________________________________________________________________________________________________________________________________________________________________________________________________________________________________

Were Emergency Procedures followed and properly documented?_________________________

______________________________________________________________________________

Were all leak investigations properly conducted and documented?_________________________ ______________________________________________________________________________

______________________________________________________________________________

Was Mutual Aid assistance needed?_________________________________________________

If so, was the work performed by the Mutual Aid assistance properly documented?___________

______________________________________________________________________________

What can be done to minimize the possibility of this type of line hit/accident from recurring?

__________________________________________________________________________________________________________________________________________________________________________________________________________________________________________

______________________________________________________________________________

Signature:___________________________________________________


Utility Name

TRANSMISSION & DISTRIBUTION PATROLLING REPORT Patrols of Areas Susceptible to Abnormal Physical Movement

PERIOD COVERED: ________________________ TO: _______________________________

AREA COVERED: ______________________________________________________________

______________________________________________________________________________

______________________________________________________________________________

______________________________________________________________________________ NOTE: The area can be described by reference to specific location(s) or by reference to main valves on either end of the section patrolled. Areas can also be described by reference to the system map(s).

_____ NO EVIDENCE OF PROBLEMS___________________________________________

_____ PIPLINE EXPOSURE, EROSION, OR SIMILAR PROBLEM: ___________________

_______________________________________________________________________

_____ LEAKAGE INDICATION: ________________________________________________

_______________________________________________________________________

_____ CONSTRUCTION ACTIVITIES: ___________________________________________

_______________________________________________________________________

_____ ANY NEW HCA’S IDENTIFIED OR CHANGE IN CLASS LOCATION:

_______________________________________________________________________

OTHER SIGNIFICANT FACTORS: _______________________________________________ _____________________________________________________________________________

RECOMMENDATION AND COMMENTS: ________________________________________

_____________________________________________________________________________ _____________________________________________________________________________

SIGNATURE:________________________________________________


Utility Name

ATMOSPHERIC CORROSION SURVEY

Note: This survey is to be completed on ALL above ground piping at least once every 3

calendar years not to exceed 39 months per the requirements of Parts 192.479, .481& .491.

Survey conducted by:___________________________________________________________________

Date &/or dates survey was conducted:_____________________________________________________

Area/Section/Location covered:___________________________________________________________

Transmission or Distribution:_____________________________________________________________

ITEMS TO BE INSPECTED ON ALL ABOVE GROUND PIPING:

Note: You may list any addresses or locations of problems found requiring remedial action on

the Atmospheric Corrosion Location Form. If no issues are found note it by answering the

following questions.

Any problems observed at the pipe to soil interface?____________________________________

______________________________________________________________________________

Was any disbonded coating observed on risers or associated piping?________________________ ______________________________________________________________________________

Does coating need to be removed and pipe rewrapped?__________________________________

Any atmospheric corrosion found?__________________________________________________

Was the atmospheric corrosion general (surface rust) or localized?_________________________

If localized, was any pitting found?__________________________________________________

Cleaning, painting, or replacement required?__________________________________________

Were pipe supports removed or adjusted to allow for the inspection of the pipe?______________

______________________________________________________________________________

Does the area under the pipe support require remedial action?_____________________________

If so, what remedial action is required?_______________________________________________

COMMENTS:__________________________________________________________________

______________________________________________________________________________

Signature:________________________________________________________


Utility Name

ATMOSPHERIC CORROSION LOCATION FORM

If atmospheric corrosion issues are found, please document below.

List of possible areas of concern: Piping ( ) Meter Set ( ) Fitting ( ) Regulator ( ) Support ( ) Vent ( )

Pipe Coating( )

Address Area of Corrosion (See List Above) Action Taken

By:_____________________________________________Date:_________________________


Address_____________________________________________________________________________

___________________________________________________________________________________

City / County___________________________________________________ State________________

Utility/Co.__________________________________________________________________________

DETECTED BY COLLECTING PROBABLE

SOURCE

SOIL VENTED C.G.I. TEST PRESSURE SURFACE PIPE & SIZE

Mobile Flame Pack In Building Main Rock Gas % Low Lawn Steel

Flame Pack Near Bldg. Service Cinders L.E.L. % Med. Soil Plastic

Visual / Vegetation In Man Hole Service Tap Clay P.P.M High Paved Cast Iron

Combustible Meter In Soil Valve Loam PPM-M Transmission Gravel Other

Electronic Gas Detector In Air Meter Set Sand Negative Other

RMLD Other Other Other

INSTRUMENT SERIAL # CALIBRATION DATE: CALIBRATION RESULTS:

REMARKS

____________________________________________________________________________________________________________________________________________________

____________________________________________________________________________________________________________________________________________________

SURVEYOR_________________________________________________________ GUIDE________________________________________________________________________

GAS COMPANY DATA

LEAK CAUSE COMPONENT & EXPLANATION PART OF SYSTEM PIPE & SIZE REPAIR DATA

Corrosion Pipe Transmission Steel Number of Leaks

Outside Force Valve Main Plastic Bare

Construction Defect Fitting Service Cast Iron Coated

Material Failure Drip Mater Set Ductile Iron Date Repaired:

Other Regulator Customer Pipe Copper Date Rechecked:

Tap Connection Other Other Positive Negative

Other

REMARKS

_________________________________________________________________________________________________________________________________

_________________________________________________________________________________________________________________________________

X = DENOTES ESTIMATED LEAK LOCATIONS

3 Yr.

5 Yr.

Annual

Row

______

GRADE OF CASE _______

GRADE 1________________

GRADE 2________________

GRADE 3 _______________

Page No.__________________

Field Case No._____________

Date_____________________

METER SET Meter No._________________

INSIDE OUTSIDE

LEAK SURVEY REPORT


Utility Name

VALVE INSPECTION & MAINTENANCE LOG

Valve No. __________________________

DATE FLEX LUBE AMOUNT BY

Page 1 of 2


Page 2 of 2


Utility Name

MANUAL SHUT-OFF (CURB VALVE) INSTALLATION & MAINTENANCE FORM

Installation performed by:________________________________________________________________

Date of Installation:________________________

Address of Installation:__________________________________________________________________

Location of Installation: Map the location of the valve in the grid lines below or attach a separate map.

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Type of Valve:_______________________ Size of Valve:__________________________

Print line off of valve:__________________________________________________________

NOTE: Maintenance is to be performed on this valve within every 5 years not to exceed 63 months from

the date of installation.

Maintenance Log

Date Maintenance Performed:

Accessible: Operated: Remedial Action Required:

Remedial Action Completion Date:

Performed By:


REGULATOR STATION INSPECTION REPORT

Utility: Date:

Location:

Function: Serial Number:

Make: Orifice Size:

Type: Size:

Loading: Pilot ___________ Max Range

Orifice and Seat Inspected: Yes No

M.A.O.P. of System to which it is Connected: __________________

Operating Pressure-- Inlet as Found:

Inlet as Left:

outlet as Found:

Outlet as left:

Lock up pressure: ____________________

Capacity at Inlet and Outlet Pressure:

Monitoring Regulator or Relief Setting: Was the Regulator Stroked (To Fully Open)?

General Conditions of station---

1. atmospheric corrosion: Yes no

2. support piping rigid: Yes no 3. Station guards: Yes4. area clean of weeds & grass: yes no

5. Locks: yes no

Corrections Made:

Remarks:

Signed


RELIEF VALVE INSPECTION REPORT

Utility: Date:

Location:

Make: Type:

Size: Orifice Size:

Type of loadings---

spring: pilot:

range: other:

Pressure Setting---

Inlet as Found: Inlet as Left:

Connection Pipe Size:

Vent Stack Size:

Capacity:

Condition Of ---

1. Relief valve: Exercised: Yes no

2. Recording gauge:

3. Support piping:

4. Station guard: 5. General area:6. locks: Yes no

Repairs Required:

Remarks:

signed


FARM TAP REGULATOR & RELIEF INSPECTION FORM

NOTE: This inspection is to be performed on all service lines not directly connected to a distribution system (i.e. farm taps) every 3 years not to exceed 39 months.

Utility : __________________________________Inspection performed by: ______________

Date of inspection:

Location/Address:

INSPECTION & MAINTENANCE ITEMS

Regulator #1 Regulator #2 (if applicable)

Type & Size: Type & Size:

In good mechanical condition? In good mechanical condition?

Set point as found? Set point as found?

Set point as left? Set point as left?

Was lockup obtained? Was lockup obtained?

At what pressure? At what pressure?

Corrective measures taken? Corrective measures taken?

Relief Valve

Type & Size:

Capacity:

In good mechanical condition?

Set point as found?

Set point as left?

Exercised to verify set point?

Fully seat after being exercised?

Corrective measures taken?

Are all regulator and relief vents pointed down and screened?

Is there any misalignment causing strain on piping or components?

Any problems found at the pipe to soil interface?

Comments and/or Concerns?

SIGNATURE:


Utility Name

GAS PIPELINE PRE-INSTALLATION CHECKLIST

Permits:

Are permits going to be needed from the State, County or Railroad?______________________________

General Information:

Installing a service line, distribution main, or transmission line?__________________________________

If installing transmission, does design allow for internal inspection devices?________________________

Installing polyethylene or steel pipe and fittings?_____________________________________________

MAOP of existing facilities to which the pipeline will be connected?______________________________

Pipeline Sizing:

Projected size of pipe?__________________________________________________________________

Projected length of pipeline installation?____________________________________________________

At what pressure will the installation operate?________________________________________________

What is the maximum capacity of the projected pipeline at operating pressure?______________________

What is the projected maximum customer load?______________________________________________

Does the projected pipeline have enough capacity for the load potential at the desired operating

pressure?_____________________________________________________________________________

Meter & Regulator Sizing:

How much pressure has the customer requested? (2 psi, 7” water column, etc..)_____________________

What type and size of regulator will be installed?_____________________________________________

What orifice size will be used in the regulator?_______________________________________________

Does the regulator have sufficient capacity for the load demand?_________________________________

What type and size (capacity) of meter will be installed?_______________________________________

Does the meter have sufficient capacity for the load demand?___________________________________

Page 1 of 3


EFV & Curb Valve Information:

Will an EFV or Curb Valve be installed?___________________________________________________

If an EFV is required, what size (capacity) will be installed?____________________________________

If a curb valve is required, what size (OD) will be installed?____________________________________

If the main is under pavement will the EFV/curb valve be installed as close to the main as possible or at

the curb line allowing easier access?______________________________________________________

Additional Information:

What size & type of tap tee will be used? (weld-on, bolt-on, fusion)______________________________

What type of riser will be used? (anodeless or steel)___________________________________________

How many joints will there be? (pipe to pipe, pipe to tap, pipe to riser, etc…)_______________________

Are joints going to be welded, fused, or are couplings going to be used?___________________________

If couplings are used, what type? (compression, stab, etc..)______________________________________

Is tracer wire going to be installed?________________________________________________________

Does the meter set need additional protection? (barricades)_____________________________________

Is the projected site for the installation of the meter set at least 3’ away from any potential ignition source

or any openings into the building?_________________________________________________________

Pressure Testing Requirements:

Installing a service line, distribution main, or transmission line?__________________________________

What size of pipe is going to be installed?___________________________________________________

What is the projected length of the pipeline? (add riser length if installing service line)________________

At what pressure will the pressure test be conducted? (90 psi minimum)___________________________

How long will the pressure test be conducted?________________________________________________

Does the pressure test meet MAOP & O&M requirements?_____________________________________

Page 2 of 3


Projected Pipeline Route (map of projected installation)

Additional Installation Comments:_________________________________________________________

_____________________________________________________________________________________

_____________________________________________________________________________________

_____________________________________________________________________________________

_____________________________________________________________________________________

Signature:____________________________________________________________________________

Page 3 of 3


Utility Name

PIPELINE TEST REPORT NOTE: This form is to be completed for each section of pipe that is placed in service or reinstated. Use the following space and/or reverse side for sketch of pipeline:

. . . . . . . . . . . .

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LOCATION: _______________________________________________________________________________

TYPE: ___________________________ SIZE ___________________ LENGTH: ____________________

TYPE WELD: _____________________ NO, WELDS: ____________ DATE WELDED: ______________

TYPE TAP: ____________________________ DATE INSTALLED: ______________________________

COATING TYPE: __________________________ DATE INSTALLED: ______________________________

SCHEDULE OF PIPE: _______________________

PRINT LINE: _______________________________

EFV INSTALLED: YES NO (If yes, Note EFV Placement on Map)

If yes, EFV Type ___________________________ Manuf.: ________________________________

PRESSURE TEST

Time Start: ______________ Pressure Start: ______________ Test Gas: _______________________________

Time Stop: ______________ Pressure Stop: ______________

Tot. Time: ______________ Line Loss: _________________

PURGED: YES NO

% GAS: ________________

COMMENTS: ______________________________________________________________________________

___________________________________________________________________________________________

BY: ____________________________ DATE: _________________________

NOTE: EXPOSED PIPE/BELLHOLE REPORT IS REQUIRED WITH THIS FORM.


Utility Name

EXPOSED PIPE/BELLHOLE REPORTNOTE: This form is to be completed for each time the gas line is exposed.

Use the following space and/or reverse side for sketch of pipeline:

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AIR SAMPLE OF BELLHOLE ________________ % GASLocation:____________________________________________________________________________

Type: _______________________________________ Size: _________________________________

Coating Type & Condition:______________________________________________________________

Pipe Condition (if applicable): ___________________________________________________________

If corrosion present is it General or Localized:_______________________________________________

Pipe Manufacturer: ____________________________________________________________________

Date Installed: _______________________________________________________________________

PITTING: YES NO If yes, Pitting Depth: ________________________________________

Corrective Measures (if required): ________________________________________________________

____________________________________________________________________________________

Was internal section of pipe exposed? YES NO

If yes, was internal corrosion present? YES NO

If yes, see O&M for remedial actions.

PIPE TO SOIL VOLTAGE READING

Grade Level: ___________ Pipe To Soil Interface: ____________ IR Drop Potential: _____________

Description of Maintenance Preformed: ____________________________________________________

_____________________________________________________________________________________

List of Materials Used: _________________________________________________________________

____________________________________________________________________________________

Corrective Measures (if required): ________________________________________________________

_____________________________________________________________________________________

Comments: ___________________________________________________________________________

___________________________________________________________________________________

BY: ______________________________________________ DATE: ___________________________


Utility Name

PIPELINE PURGE TEST REPORT

LOCATION: _________________________________________________________________________

_____________________________________________________________________________________

TYPE: ___________________________ SIZE ___________________ LENGTH: ______________

SIZE OF PURGE FITTING: _________________

EQUIPMENT USED: ___________________________ DATE CALIBRATED: __________________

INERT GAS USED FOR PRESSURE TEST: YES NO

PURGE TEST

Date: _____________________________

Purge Gas: ________________________

Time Start: ________________________

Time Stop: ________________________

% of Gas : ________________________

Was internal section of pipe exposed? YES NO

If yes, was internal corrosion present? YES NO

If yes, comments:____________________________________________________________________

_____________________________________________________________________________________

_____________________________________________________________________________________

COMMENTS: _________________________________________________________________________

_____________________________________________________________________________________

_____________________________________________________________________________________

_____________________________________________________________________________________

BY: ______________________________________________ DATE: _________________________


Utility Name

MATERIAL INSTALLATION RECORD

**All materials to be documented and recorded as a requirement of DIMP**

Note: The “print line” or manufacturing data that is stamped on or included in the packaging of

the pipe and/or components used during installation must be documented. If more than one roll,

segment of line pipe or couplings is used during installation, documentation must be made of all

different rolls, segments or components used.

Date of Installation:____________________________________________________________

Job Number or Address of Installation:____________________________________________

______________________________________________________________________________

Pipe Information:

______________________________________________________________________________

______________________________________________________________________________

______________________________________________________________________________

______________________________________________________________________________

______________________________________________________________________________

Tap Tee Information:

______________________________________________________________________________

______________________________________________________________________________

______________________________________________________________________________

EFV or Curb Valve Information:

______________________________________________________________________________

______________________________________________________________________________

______________________________________________________________________________

Coupling Information:

______________________________________________________________________________

______________________________________________________________________________

______________________________________________________________________________

______________________________________________________________________________

Riser Information:

______________________________________________________________________________

______________________________________________________________________________

Any Additional Information Not Included Above:

______________________________________________________________________________

______________________________________________________________________________


Utility Name

NO-FLOW TEST REPORT

Location Address______________________________________________________________

Meter Make: ______________________ Size: ___________________________

Serial Number: ___________________________

TEST:

Time Start: _______________________________ Stop: ___________________________

Reading Start: _____________________________ Stop: ___________________________

Regulator Pressure Setting as Found and as Left: __________________

Lock Up: _________________________________

Comments:

BY: ______________________________________________ DATE: ___________________________


Utility Name

REPORT OF ABANDONED FACILITIES

NOTE: This form is to be completed for all abandoned facilities.Use the following space and/or reverse side for sketch of pipeline:

. . . . . . . . . . . .

. . . . . . . . . . . .

. . . . . . . . . . . .

. . . . . . . . . . . .

. . . . . . . . . . . .

. . . . . . . . . . . .

LOCATION: _________________________________________________________________________

_____________________________________________________________________________________

DATE OF ABANDONMENT: ___________________________________________________________

FACILITY: Main Service Other: ________________________________________________

_____________________________________________________________________________________________

SIZE: __________________________ MATERIAL: _____________________________________

METHOD OF DISCONNECTION: _______________________________________________________

INTERNAL CORROSION PRESENT: YES NO If yes, Comments: _____________

______________________________________________________________________________

______________________________________________________________________________

PITTING: YES NO If yes, Pitting Depth: _________________________________

BLED & PURGED? YES NO

CLOSURE TYPE: _____________________________________________________________________

COMMENTS: ________________________________________________________________________

_____________________________________________________________________________________

_____________________________________________________________________________________

BY: ____________________________________________ DATE: _________________________


Date _____________________ Address _______________________________________________________________ Station No. ______________

Installed on: Anode Rectifier Insulator Other ___________________________________________ Map No. _______

Location: __________ Ft. ___________ of _____________________________________________________________________________________

__________ Ft. ___________ of ______________________________________________________________________________________

. . . . . . . . . . . . .

. . . . . . . . . . . . .

. . . . . . . . . . . . .

. . . . . . . . . . . . .

. . . . . . . . . . . . .

. . . . . . . . . . . . .

. . . . . . . . . . . . .

. . . . . . . . . . . . .

Date Ins. Ck. Anode Test

p/s-mv Rectifier

Test Point

p/s-mv

Date Ins. Ck. Anode Test

p/s-mv Rectifier

Test Point

p/s-mv

off ma/on off ma/on

Utility Name

ANODE TEST-STATION REPORT

Page 1 of 2


Address ________________________________________________________________ Station No. ___________________

Date Ins. Ck.

Anode Test

p/s-mv

Rectifier

Test Point

p/s-mv

Date

Anode Test

p/s-mv

Rectifier

Test Point

p/s-mv

off ma/on off ma/on

Page 2 of 2


CATHODIC PROTECTION RECORD PIPE-TO-SOIL READINGS

Note: Readings shall be taken at least once every calendar year not to exceed 15 months. Avoid taking readings on top of or near anodes where possible. All readings shall be -0.85 V or greater. If not, corrective action must begin within 90 days and be remedied by the next survey cycle.

CP readings taken by:__________________________________________________

DATE TEST LOCATION P/S READING CORRECTIVE ACTION

NEEDED & CORRECTED P/S READING

DATE

Utility Name


ODORANT USAGE REPORT

DATE: ______________________________________

ODORANT TYPE:

_____ B-Captan _____ Other: ________________________

ODORANT USE:

1) _______ lbs. added to fill tank

DELIVERED GAS:

2) Meter Reading (this report) ____ ____ ____ , ____ ____ ____ MCF

3) Meter Reading (last report) ____ ____ ____ , ____ ____ ____ MCF

4) Delivered Gas (2-3) ____ , ____ ____ ____ MCF

5) Delivered Gas (MCF/1000) = ____ , ____ MMCF

ODORIZATION RATE:

(Item 1 divided by item 5) = _______ lbs./MMCF

By: ________________________________________

MCF = 1,000 cubic feet MMCF = 1,000,000 cubic feet

Utility Name


ODOROMETER TEST REPORT (Sniff Test)

LOCATION: __________________________________________________________________________________

DATE: _________________________ TIME: _____________________________________

ODOR LEVEL: _____ NIL _____ BARELY DETECTABLE _____ READILY DETECTABLE _____ STRONG

LIST OTHER ODORS PRESENT: ________________________________________________________

REMARK: (ODOROMETER READING)__________________________________________________

_____________________________________________________________________________________

_____________________________________________________________________________________

OBSERVED BY: ____________________________

LOCATION: __________________________________________________________________

DATE: ________________________ TIME: ____________________________________

ODOR LEVEL: _____ NIL _____ BARELY DETECTABLE _____ READILY DETECTABLE _____ STRONG

LIST OTHER ODORS PRESENT: _________________________________________________

REMARKD: (ODOROMETER READING) _________________________________________ ____________________________________________________________________________________________________________________________________________________________

OBSERVED BY: ____________________________

Utility Name


CUSTOMER OWNED PIPING & EFV NOTIFICATION RECORD

The following individuals received a copy of the "Customer Owned Piping" & “EFV” notification the same date they signed up for service and received the New Customer Packet

Customer Name (Print) Customer Signature Date

Utility Name


DETERMINATION OF MAOP IN NATURAL GAS PIPELINES

Identity of Pipeline/Distribution Area

A. Maximum Allowable Operating Pressure: Steel or Plastic Pipelines (Part 192.619): and High-Pressure Distribution Systems (Part 192.621).

Part 192.619(a)(1) Design Pressure: Lowest design pressure Part 192.621(a)(1) for any of the following system elements

Pipe (including service lines)

Valves

Flanges

Fittings

Mechanical Couplings

Leak Clamps

Instruments Odorizers

Overpressure Protection Devices

Upstream Regulator(s)-Outlet Pressure Rating

Downstream Regulators-Inlet Pressure Rating

Other (list)

Part 192.619(a)(2) Pressure Test Plastic Pipe: Test Pressure divided by 1.5 Steel Pipe operated at or over 100 psi, Test Pressure divided by Class Location Factor

Part 192.619(a)(3) Historic Operations Highest operating pressure between 7/l/65 and 7/l/70 unless the pressure test in (a)(2) was after 7/l/65 or an uprating in accordance with Subpart K has been conducted.

Part 192.619(a)(4) Furnace butt welded steel pipe: 60% of mill test pressure

Part 192.619(a)(5) All other steel pipe: 85% of mill or post installation pressure test, whichever is higher

Page 1 of 2


B. Part 192.621: High Pressure Distribution Systems Only.

Part 192.621(a)(2) 60 psig unless all services have overpressure protection

Part 192.621(a)(3) 25 psig for any cast iron pipe with unreinforced joints

Part 192.621(a)(4) Pressure limit on joints.

C. Part 192.619(a)(6) and Part 192.621(a)(5): Additional Consideration for Transmission or High Pressure Distribution Lines.

Highest operating pressure considered safe based on operating history

D. Part 192.623: Low Pressure Distribution Systems.

Highest delivery pressure which can be safely applied to customer piping and properly adjusted gas appliances.

E. Part 192.619(c): Alternate consideration for transmission lines. Highest operating pressure between 7/l/65 and 7/l/70 (7/l/71 and 7/l/76 for offshore gathering lines.)

F. Determination of MAOP. Either item E., where applicable, or the lowest pressure on any of the above lines is the MAOP.

MAOP: Date(s) of Uprating (if applicable) _________________ Describe the uprating process: _________________________________________________ ___________________________________________________________________________ ___________________________________________________________________________ ___________________________________________________________________________ ___________________________________________________________________________ ___________________________________________________________________________ ___________________________________________________________________________ ___________________________________________________________________________ Continue on back if needed.

By: Date:

This form used to establish maximum allowable operating pressure (MAOP) for steel or plastic pipelines. MAOP shall be documented and kept for the life of the system.

Page 2 of 2


Utility Name

MECHANICAL FITTING FAILURE REPORT

Date __________________ Time _____________________ By ____________________________

ADDRESS OR GENERAL LOCATION -- Sketch Location of Leak

. . . . . . . . . ____________________________________

. . . . . . . . . ____________________________________

. . . . . . . . . ____________________________________

. . . . . . . . .

INVESTIGATION Leak Classification 1 2 3 (NOTE: Only Class 1 hazardous leaks are required to be reported to PHMSA)

Nominal Pipe Size _____” Material Type ____________________ Fitting Manufacturer ________________

Lot Number __________ Date of Manufacture ___________________ Date of Installation _______________

Any Other Markings on Failed Fitting __________________________________________________________

Nature of Failure (including pipeline environment): _______________________________________________ _________________________________________________________________________________________ _________________________________________________________________________________________

Other Observations: ________________________________________________________________________ _________________________________________________________________________________________ _________________________________________________________________________________________

Repairs made: ____________________________________________________________________________ _________________________________________________________________________________________ _________________________________________________________________________________________ _________________________________________________________________________________________

This form is used to collect mechanical fitting failures that are hazardous and will be reported annually on the Mechanical Fitting Failure Report F 7100.1-2 or may be submitted throughout the year.

NOTE: This form will be filled out and attached to Service Call Report, Leak Investigation Report, and Exposed Pipe/Bellhole Report for all mechanical fitting failures.


Utility Name

RECORD OF LOST & UNACCOUNTED-FOR GAS FOR CALENDAR YEAR ___________

Month

MONTHLY 12 MOS. ENDING CURRENT MO. % RATIOS OF

LOST & UNACCOUNTED

MCF Gas Purchased

MCF Gas Sales

MCF Lost & Unacctd.

MCF Gas Purchased

MCF Gas Sales

MCF Lost & Unacctd.

Monthly 12 Months End. Curr. Mo.

Jan.

Feb.

Mar.

Apr.

May

June

July

Aug.

Sept.

Oct.

Nov.

Dec.

Year

Gas O&M Plan – Revision03.18 116

EXCAVATION AND TRENCHING GUIDANCE SYSTEM JOB PLANNING

Public Utility Name:

Project/Location Of Job Site:

Competent Person(s) filling out this checklist:

Item To Be Checked (√)

if required

Date when

completed

Determine the location of the underground utilities. (One Call System) Locate overhead transmission lines and arrange precautions to avoid contact by equipment, etc. As applicable, give prior notification to homeowner(s) and businesses affected by the work. Have adequate and correct signing and barricading around excavation. Workers shall use reflective vests if necessary. Place vehicle, equipment, spoil piles, etc. correctly to allow for safe passage of traffic and progress of construction. Notify traffic control (police, fire departments, etc.) and use appropriate safety gear. Consult a registered professional engineer, if necessary. Use trained supervisors and workers. Designate a competent person for the job. Identify all buildings, utility poles, trees, and any other object or destabilizing forces along the right of way. Determine the soil type. Complete the Excavation And Trenching Initial Safety Checklist. Determine appropriate means for safeguarding the excavation and have the necessary equipment on hand. Ladders, steps or ramps that meet OSHA requirements are available for trench excavations, with no more than 25 feet of lateral travel for employees egress. Ladders should extend three feet above the surface and be secured. Available room exists to place spoil pile at least two feet back from the edge of the excavation. Confined space atmospheric hazards are considered and acceptable. Oxygen levels must be at least 19.5 % and not more than 23.5 %. Combustible gases cannot be more than 10 % of the lower explosive limit. Suspect atmospheres must be tested as required and appropriate rescue equipment must be on site. Lifelines and harnesses are required for bellbottom piers and like excavations. Bridges and walkways over trenches and excavations have standard guardrails or other fall protection. A means to divert water from the excavation exists, if necessary. A Competent Person makes daily inspections or more frequently as conditions require. The “Daily Inspection Report” is completed and forwarded to supervisor. Shoring and shielding are removed in a manner that ensures the safety of workers.

Page 1 of 5


EXCAVATION AND TRENCHING GUIDANCE SYSTEM INITIAL SAFETY CHECKLIST

Public Utility Name:


Competent Person(s) filling out this checklist:

Day of Excavation:

Item To Be Checked YES NO

Have applicable utility companies been notified of proposed work?

Are all tools, equipment, emergency equipment (fire extinguisher, first aid kit, rescue equipment, if needed) and shoring materials readily available prior to going to the job site?

Have applicable utility companies or owners been contacted within established or customary local response times, advised of the proposed work, and asked to establish the location of the utility installations prior to the start of actual excavations?

While the excavation is open, are all underground and surface utility installations protected, supported, or removed as necessary to safeguard workers?

Is the closest edge (to the trench) of the spoil pile at least two (2) feet from the edge of the excavation?

Does the Competent Person inspect the excavation daily or more frequently when there is a change in weather or environment could affect the soil?

Are barricades, stop logs, if needed, properly placed?

Are excavations five (5) feet or deeper correctly sloped or shored, or is a trench box (shield) used?

Is a ladder or other means of exit (egress) provided in trenches or excavations four (4) feet or deeper?

When ladders are used do they extend three (3) feet above the surface and are they secured?

Is there evidence of a potential cave-in such as dry or cracking soil?

Are shoring and shielding systems inspected daily by the Competent Person?

Page 2 of 5


EXCAVATION AND TRENCHING GUIDANCE SYSTEM SOIL TESTING RESULTS

Public Utility Name: Competent Person And Date:

Visual Examination Of Soil

Disturbed Soil (yes/no): Fissured Soil (yes/no):

Layered Soil (yes/no): Granular/Flowing Soil (yes/no):

Water Seepage (yes/no): Subject To Vibration (yes/no):

Results Of Manual Soil Tests

Test Sample 1 Sample 2 Sample 3 Sample 4 Sample 5

Dry Strength

Plasticity: Mold a moist or wet sample into a ball. If the material can be rolled into threads 1/8 inch in diameter without crumbling, it is cohesive

Compressive Strength: Circle Applicable Test1. Thumb penetration test, Type A if

thumb penetrates with great effort, Type B if thumb penetrates several inches

2. Shear vane test results or 3. Penetrometer test results

Average

Maximum Allowable Slopes (H:V) For Excavations Less Than 20 Feet Deep (Edited from Section: IV, of Chapter 2 to the OSHA Technical Manual (OTM), Directive TED 1.15, September 22, 1995)

Soil Type Soil Description Maximum Allowable Slope

Stable Rock

Stable rock is natural solid mineral matter that can be excavated with vertical sides and remain intact while exposed. It is usually identified by a rock name such as granite or sandstone. Determining whether a deposit is of this type may be difficult unless it is known whether cracks exist and whether or not the cracks run into or away from the excavation.

Vertical (90 Deg.)

Type A

Type A soils are cohesive soils with an unconfined compressive strength of 1.5 tons per square foot (tsf) (144 kPa) or greater. Examples of Type A cohesive soils are often: clay, silty clay, sandy clay, clay loam and, in some cases, silty clay loam and sandy clay loam. (No soil is Type A if it is fissured, is subject to vibration of any type, has previously been disturbed, is part of a sloped, layered system where the layers dip into the excavation on a slope of 4 horizontal to 1 vertical (4H:1V) or greater or has seeping water.

3/4:1 (53 Deg.)

Type B

Type B soils are cohesive soils with an unconfined compressive strength greater than 0.5 tsf (48 kPa) but less than 1.5 tsf (144 kPa). Examples of other Type B soils are: angular gravel; silt; silt loam; previously disturbed soils unless otherwise classified as Type C; soils that meet the unconfined compressive strength or cementation requirements of Type A soils but are fissured or subject to vibration; dry unstable rock; layered systems sloping into the trench at a slope less than 4H:1V (only if the material would be classified as a Type B soil).

1:1 (45 Deg.)

Type C

Type C soils are cohesive soils with an unconfined compressive strength of 0.5 tsf (48 kPa) or less. Other Type C soils include granular soils such as gravel, sand and loamy sand, submerged soil, soil from which water is freely seeping and submerged rock that is not stable. Also included in this classification is material in a sloped, layered system where the layers dip into the excavation or have a slope of four horizontal to one vertical (4H:1V) or greater.

1 1/2:1 (34 Deg.)

Type A Short Term Applies to short term (24 hours or less) excavations in class A soils that are no greater than 12 feet deep. 1/2:1 (63 Deg.)

Specified Protective System

Soil Type (A, B or C):

Depth Of Evacuation:

Protective System:

Tabulated Data Used To Specify Support System:

Page 3 of 5


EXCAVATION AND TRENCHING GUIDANCE SYSTEM DAILY INSPECTION REPORT

Public Utility Name: Competent Person:


Item To Be Checked (√)if OK

(√)if OK

(√)if OK

(√)if OK

(√)if OK

Date Of Inspection

Signs Of Side Wall Failure (√) If AbsentTension cracks on surface Subsidence/slumpage of surface Deformation of sidewalls Spalling of sidewalls Seepage of fine soils Cohesiveness of sidewall soil Water accumulations Deformation of shoring Cracking/popping sounds Protective SystemSloping: Appropriate angle Shoring/shielding: condition Shoring/shielding: 18” above surface Overhead Power Lines: Safe Distance Hazardous Atmosphere: Potential For Undermined Structures/Utilities: Supported

Equipment/Backfill >2’ From EdgeMeans Of Egress Provided Every 25’Ladders 3’ above ground surface/tied down Ramps/stairs in good condition Crossovers: good condition/handrails Dewatering Equipment: Proper Operation

Adequacy/Condition Of BarricadesGeneral Safety ItemsHand tools: condition Slings, chains and wire ropes: condition Electrical equipment/cords: condition Electrical equipment connected to GFCIs Chemical containers labeled MSDSs available for hazardous chemicals Flammable/combustible liquids in safety cans Mobile equipment: condition Emergency EquipmentFirst aid kit: available/condition Fire extinguisher: available/condition Body harness/life line: available/condition

Page 4 of 5


EXCAVATION AND TRENCHING GUIDANCE SYSTEM DAILY INSPECTION REPORT (Continued)

Record Results Of Air Testing (When Dictated By Job Site Location/Conditions)

Date And

Time

Device Used % Oxygen Min 19.5% Max 23.5%

% LEL Max 10% of LEL

H2S ppm Max 10 ppm

CO ppm Max 35 ppm

Identify Protective Measures To Be Used And Emergency Equipment To Be Available On-Site If The Presence Of A Hazardous Atmosphere Is Confirmed

Comments:

Competent Person’s Signature:

Page 5 of 5


PAGE INTENTIONALLY LEFT BLANK


DIVISION ELEVEN DRUG TESTING PROGRAM

(Operator to insert their Drug and Alcohol Program here.)

2018 om final draft 2

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