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AGA DT&E Committee – Open Forum 42 – August 2013 1

AGA Distribution and Transmission Engineering Committee Open Forum 42

2013

Note: The survey responses are based on an informal survey and are for general information only. They are not intended to

bind any company or state a company's official position. The information represents an unaudited compilation of information

and could contain coding or processing errors. Anyone using this document should rely on his or her own independent

judgment or, as appropriate, seek the advice of a competent professional. References to work practices, products or vendors

do not imply an opinion or endorsement by AGA or a responding company. This publication is confidential and proprietary

to AGA. AGA Full and Limited Members are granted a limited license to reproduce this publication for internal business

purposes but not for regulatory or civil matters. This document is not intended to provide legal advice or opinions. As

always, you should consult your legal counsel for advice based on the law and your company’s specific facts and

circumstances.

Copyright & Distribution: Copyright © 2013 American Gas Association. All rights reserved. This work may not be

reproduced or transmitted in any form or by any means, electronic or mechanical, including photocopying, recording, or by

information storage and retrieval system without permission in writing from the American Gas Association.

Compiled by: John Wyckoff, New Jersey Natural Gas -- [email protected]

QUESTIONS (as submitted by:)

Avista Utilities – Jeff Webb

1. What form of pressure test documentation are you accepting or requiring, i.e. circle chart from a mechanical

pressure recorder, digital download and printout from an electronic pressure recorder, paper form with blanks

filled in by the individual performing the test, or other method?

A: Distribution: Main Test Data Sheet (for mains) and service card (for services) Transmission: Pressure (circle) chart

B: Gas Main – Chart from mech. recorder along with O&M form; Gas Service – O&M form

C: Historical is mixed; current is recorder chart plus paper form.

D: Paper form is filled out documenting the pressure test.

E: For distribution work the pressure test information is documented by the individual performing the test on the project completion report (paper form). For transmission work we require a witness test form, pressure chart (paper or digital) and/or a PV plot.

F: If the test is two hours or more, a mechanical chart record is required with all required test details completed by the inspector using a stamp on the back of the chart. For tests under two hours, a gauge is used and the results are recorded on a paper record with all required test details.

G: Our work method requires each operator to make a record of each test performed, either hard copy or electronic version. Pressure recording charts are required if used for the test. For transmission lines a special form is used which requires more detailed information. Records are then scanned into the electronic document system as well as maintained in paper files.

H: We typically use charts from mechanical pressure recorders. Occasionally we will utilize a printout from a digital recorder. If the test is over 4 hours long we will also fill out a table form showing the pressures at set time intervals.

I: Transmission - We require a pressure test record (i.e. paper form with blanks filled in


by the individual performing the test) and chart recording of pressure. Temperature recordings are almost always provided, but not required. The pressure test record includes all the criteria required by CFR 49 §192.517 and Michigan Revised Rule 460.20314. Distribution – High Pressure - We require a pressure test record that differs from transmission record, but also includes all the criteria required by CFR 49 §192.517 and Michigan Revised Rule 460.20314. However, pressure test chart(s) are only required based on the duration of test. Medium and Standard Pressure – We require both an electronic entry of the test pressure and duration and for this information to be recorded on the “as-built” drawing.

J: Test details are captured in engineering approved construction drawings for any pressure testing that is done under 100 psi. Pressure recording charts, hard-copy or electronic downloads from electronic testing devices for pressure tests are required for pressure testing of greater than 100 psi.

K: Circle Chart from a mechanical pressure recorder for all mains

L: The type of documentation required to constitute a completed pressure test depends upon the type of test conducted. For leak tests conducted on pipelines operating at any pressure, we require a circle chart signed by the personnel that conducted and approved the test in addition to a form to be filled out detailing exactly what was tested. For strength tests, a pressure testing schematic is required along with a circle chart and typically the field personnel are also required to submit temperature and dead-weight pressure reads taken at several points during the testing process. The schematic shows the specific pipe tested. For services and IP main, there is a section of the as-built drawing set that must be filled in with information regarding the details of the initial testing; this is to be accompanied with circle charts in the same capacity as with HP tests.

M: Mechanical pressure recorder circular chart

N: Circle chart from a mechanical pressure recorder & paper form with blanks filled in by the individual performing the test.

O: Mechanical pressure recording charts, printout from electronic recorders, and paper forms completed by the individual performing the tests are all acceptable documents.

P: MAOP >60, then circle charts. < 60, then signature on a “form” with applicable information on it. I’d like to consider using electronic downloads from a digital pressure gauge.

Q: A pressure recording chart is required over 60psig or for a required test of longer than one hour. A gage is adequate for 60 psig and less if less than one hour test is required.

R: We use circle charts from a mechanical pressure recorder.

S: Calibrated pressure recorders are required on all Hydrostatic tests, either a circle chart or digital printout with appropriate intervals and pressure ranges. When testing any segment over 90% SMYS or establishing MAOP on existing segments, an electronic pressure recorder or dead weight tester is required.

T: For systems operating at 120 psig or less, a paper form filled in by the individual performing the test is used. The information on this form is also entered into our work management system. For systems operating above 120 psig, a paper chart or printout from an electronic pressure recorder is also required.


U: Circle chart and electronic form with blanks filled out.

V: Transmission: We require a digital pressure recording as well as a paper log documenting test conditions and ½-hourly test data. Distribution: Log on as-built form indicating test pressure, medium, duration & length of main.

2. From meter sets to bridge installs, how do you protect your steel carrier pipe at pipe supports? Plastic liners, FRP shields, or do you allow metal on metal contact?

A: Distribution and Transmission: No metal to metal contact allowed; engineering design for each installation. (At meter sets where a riser bracket is installed the metal to metal contact is NOT contact with the carrier pipe.)

B: FRP Shields, Centering Cradles; No metal on metal contact

C: We avoid metal to metal and “combustible” supports; we use various plastic products.

D: For meter sets, use insulating fittings between service termination and meter set, and between meter set and customer piping. For bridge installs, use insulating supports and insulating spacers.

E: FRP shields

F: We use dielectric spacers, FRP shields and plastic liners. Normally no metal to metal contact.

G: No metal on metal contact is permitted. FRP’s and plastic liners are used at pipe supports.

H: We use Nu-bolt pipe U-bolts on top of i-beam supports. No metal to metal contact.

I: We typically prevent metal on metal contact by using an insulating material that serves as mechanical protection in addition to cathodic insulation. We use FRP shields, non-metallic rollers, epoxy chocks, etc.

J: FRP shields are required for bridge crossings. All other pipe supports allow for metal on metal contact.

K: Our existing procedure do not allow metal on metal contact. There are exceptions when a wear plate is welded 360 at the six-o’clock position and the segment of pipe is isolated from cathodically protected underground piping. All steel carrier pipes inside steel casings are isolated with non-metallic spacers on 10 foot center. Any metal on metal supports are remediated upon discovery

L: We utilize FRP (Fiberglass Reinforced Plastic) shields that are placed between the pipe and the support; the shields are adhered to the piping with a specific (standards approved) epoxy.

M: FRP Roll On Shield, FRP Flatties, and non-conductive (polyurethane) rollers.

N: We use non-conductive insulated fasteners. (i.e. unions, service cocks, roller chairs, stanchion saddle,…)

O: Typically an insulating material is installed at the supports.


P: Meter sets and Reg Stns: typically a plastic sleeve between pipe and supports, no epoxy or adhesive. Bridges:

Q: For bridge and other exposed main we do not allow metal to metal contact; frp, rubber, etc. Meter sets are less of a concern as long as they are not dissimilar metals and coated as a part of the meter set.

R: In the past we used FRP shields to protect steel pipe at pipe supports. We now use clock spring pipe supports. We do not allow metal-on-metal contact.

S: Steel carrier pipe is separated from steel pipe supports. We use the following insulating material: sheet, plastic, Delrin No. 1' x 4' x 1/16”, black or insulating tubing, 1/16” thick, grade CE, cotton fabric impregnated with phenolic resin. No metal on metal contact.

T: Steel pipe is isolated from pipe supports when practical. FRP shields or non-conductive rollers are preferred.

U: FRP Shields, Rock Stop, Link Seals

V: We recently went to FRP shields adhered to the pipe. Main sits on epoxy roll guide or chair.

Alabama Gas – Randy Wilson

3. How are companies evaluating blasting near pipelines? Are blasting specialists used to investigate the impact to nearby pipe systems?

A: Distribution and transmission: If our company is made aware (before or after the fact) then a leak survey is performed. If enough details are known before the blasting is performed an engineering study is performed, using “Pipeline Toolbox” (vendor is Technical Toolbox). Should the software not be able to determine SMYS level on pipe (due to inadequate information), a blasting specialist contractor will be requested to perform the study.

B: Utilizing Pipeline Toolbox w/ Pipe Blast program

C: We’ve had success in coordinating with the companies doing the blasting to set up their sensing equipment at the nearest spot on our pipeline that we expose for them. This allows us to monitor and record the blasting affect, which to date has been negligible.

D: Have general criteria for planning and protecting gas facilities, and personal safety, this is covered in our general design/construction manual. Also use Technical Toolbox PipeBlast Evaluation software. Do not typically use blasting specialists.

E: We require third party instrumented monitoring for any blasting activity near our facilities.

F: Blasting work at [our company] falls under our leak survey policy. When the blasting occurs near our facilities, it should be directed away from the pipeline. The contractor must also demonstrate that the blasting does not result in a measured particle velocity of 2 in. /sec. at the pipeline location. A company person also stands by during the blasting and performs a follow up leak survey.

G: Our standard called for a maximum PPV of 2 in/sec at the gas main but we are in the


process of changing that to 5 in/sec based on AGA study, a blasting consultant, and input from other LDCs. No blasting within 10 feet of the gas main. Seismograph required to be placed over the gas main when blasting within 50’ of a typical distribution main; 200’ for a critical main. We usually get good cooperation from blasters but we will hire our own blasting expert if necessary. For typical blasting jobs our Damage Prevention group takes the lead in the field.

H: We use Pipeline Toolbox to evaluate the effects of ground acceleration due to blasting. The analysis is performed by our in-house engineering department.

I: We strive to keep blasting away from our facilities. When there is blasting within 100′

survey as part of the post-activity inspection. See Standard 6-5 for recording results.

J: When others are blasting near pipelines, a recognized independent blasting consultant is required at the applicants’ expense to evaluate and validate the risks for blasting. The Independent Blasting Consultant is to be a Registered Professional Engineer and a holder of a Certificate of Authorization (C of A), specializing in blasting. A copy of the consultant’s report is to be forwarded to the Engineering Department for review.

K: Hire a consultant to investigate the impact of the blasting and our facilities

L: There has been blasting near our pipelines at several locations, but municipal ordinances prohibit blasting practices that would negatively impact our pipelines in any significant capacity. Provided there was a variance granted for more invasive practices, we would most likely hire consultants to investigate the need for remedial action.

M: Follow Pennsylvania standards. No specialists used.

N: No formal process. Leak surveys pre & post blasting. Use an analysis program to assist in determining impact.

O: A commercially available software package such as Technical Toolbox Pipeblast is used by Engineering to evaluate the impact that blasting will have on gas facilities.

P: Blasting activities within 200 ft of any gas facility require evaluation by Engineering. A Company representative should be on site during the blasting operation. No blasting operation is allowed that will adversely affect Company facilities. Following a blast performed within 200 ft of any gas pipeline, or a blast that has the potential to damage a gas facility, a post inspection leak survey shall be completed to verify the integrity of the pipeline system. For blasting operations in which the predicted Peak Particle Velocity (PPV) of the blast will exceed 2 in/sec at the pipe an engineering evaluation of the blasting operation is required (see chart below). PPV is a measure of the ground vibration caused by blasting.


Q: We will object to blasting plans that are clearly risky based on calculations. We assert that we are not blasting experts and the blaster is fully responsible and liable for any and all safety with regard to blasting.

R: Leak surveys are conducted before and after all blasting sequences to verify the integrity of pipelines within a distance determined to be adequate to ensure safety.

S: [Our company] is in the process of updating standards in an effort to evaluate blasting near pipelines. Currently [our company] follows AGA guidelines, and a facility engineer assigned to the area conducts an investigation and analysis if blasting is scheduled to occur near [our company] facilities.

T: The excavator that is conducting the blasting is required to provide ground vibration monitoring to ensure that peak particle velocities near company facilities do not exceed 2 in/sec. Pre- and post-blasting leak surveys are conducted, and the excavator is responsible for any damages caused by their blasting operations.

U: Our procedures calls for conducting leak-survey of the area located in the immediate vicinity of the blast site. We survey this area before and after the blasting. We don’t usually hire “blasting specialists” to evaluate the impact to nearby pipe systems, but we sometime use the expertise of our Professional Engineers in Planning section in order to look into the effects of blasting on nearby pipeline structures.

V: We are not in an area that performs blasting.

Baltimore Gas & Electric – Joe Opert

4. Have you experienced incomplete or cold fusion failures using electro-fusion tees and confirmed that all procedures were followed, all equipment functioned properly and all materials appeared defect free? If so,

was a likely root cause determined?

A: Distribution: All failures have been determined to be construction defect. (The failure count is low).

B: Yes. Probable cause was loose connection / improper connection of fitting to processor


C: Have not experienced this.

D: Have experienced some fusion failures but have struggled with the cause. (Sometimes hard to verify that procedure was followed and equipment functioned properly.)

E: No

F: No. We utilize mechanical tees for the majority of installations.

G: No. However, majority of failures are attributed to inadequate surface preparation.

H: No

I: No answer provided

J: There has not been any reported incomplete or cold fusion failures using electrofusion tees where all procedures were followed, all equipment function properly and all the material appeared to be defect free.

K: Yes we have experienced a few unexplainable incomplete/ cold fusions; we experienced 21 on 1” CTS couplings where one side would fuse and the other side no fusion occurred. These fittings were sent back to the manufacturer who also couldn’t determine a root cause, after fusing over a hundred additional fittings without duplicating the problem they removed the entire lot number from our inventory and we didn’t have any additional problems since. We have also occasionally experienced a few similar problems on electrofusion tee’s completely fusing to the polyethylene main but most of these were found to be caused by out of round or egg shaped pipe. We have discovered all these problem fittings during the air test and haven’t discovered any after the facility was placed into service. The majority of our electrofusion problems are found to be installer related.

L: No, we have not experienced any electro-fusion tee failures where it was determined that all procedures and standards were confirmed to have been followed correctly.

M: No

N: No

O: Not aware of this problem.

P: No

Q: No

R: We have recently experienced these types of failures with a few 8x2 electrofusion high volume tapping tees. The failures were discovered during a pressure test before the taps were in-service. The manufacturer assisted with a root-cause study, but could not find a definitive answer for the failures.

S: We have had failures. It’s a combination of Material defects, human error, or equipment malfunction.

T: No

U: No


V: No, all such failures experienced have been due to incorrect procedure.

5. Have you ever experienced a dual regulator failure at pressure regulating station employing a worker/monitor

configuration? If so, what was the cause for the failure and what did you do to prevent recurrence?

A: Yes. Debris has been determined to be the cause. To prevent recurrence, strainers have been installed.

B: Yes. Construction debris. Filter separators were installed

C: Have not experienced failure of monitor and control, but our practice is to make sure that we have no “closed systems” in that we have one or more relief valve devices somewhere on the system.

D: Yes, the typical cause is debris. For high pressure and above systems, install filters upstream of the worker/monitor regulators.

E: Y, Installed relief valves on systems fed exclusively by worker/monitor regulators

F: Yes, mostly caused by debris in pipeline. Added filters to regulator stations that did not have one and reviewed filter capacities for stations that had filters.

G: We have on an LP station. It was caused by local flooding and both pilot vents were submerged causing the regulators to overpressurize the downstream system. We installed taller vents to prevent re-occurrence.

H: Yes. We have had two incidents both which were caused by debris – one in the pilot, the other in the regulator itself. We now require filters on all pilots and strainers on regulator stations.

I: Yes we have had failure of both the primary worker and monitor regulator at a station. Usually the cause is welding wire, slag, sand or other small solid particles in the gas which cut up the boots in both regulators. This usually happens after pipe construction upstream of the city gate station and/or flows increase due to much colder weather early in the winter heating season. We have been trying to avoid this problem by putting in cone strainers where there has been new construction at the station or just upstream on the pipeline. We are also putting in more filter-separators on the inlet of city gates where there has been a history of liquids and solids in the gas. We also consider where there could be future occurrence of solids and liquids stirred up in the gas stream due to pipeline pigging.

J: There has been a dual regulator failure in the past; the root cause is due to water content following hydrostatic testing, debris caused by pigging and hydrates formation.

K: None that we recall

L: No. Provided one had happened, our means of preventing the recurrence would be to install electronic monitoring the interstage and outlet pressures that would immediately alert our controllers of a failure at one of the regulation stages; allowing us to intervene before the failure of both stages.

M: We do not use worker/monitor configuration for regulator stations.

N: Yes, trash in the regulators prevented a complete shutoff. Scheduled maintenance program for regulators and reliefs.


O: Failures have occurred due to no demand situations where the pilots have leaked and caused overpressure situations. In certain instances, we are starting to install 1” RVs downstream of monitor regulators.

P: No

Q: N/A. We do not utilize worker/monitor installations. We do utilize wide open monitors and have seen failures of both the operating and the monitor regulators. The recent cause of the dual failure was the freezing of the pilots on both the operator and monitor due to poor gas quality (heavy hydrocarbons). To prevent a recurrence, heat was applied to the pilot supply gas for both the operator and monitor regulators.

R: We have not experienced a control/monitor failure at a regulating station. We identify the control failures with SCADA, charts, etc.

S: We are not aware of these types of failures with a monitor.

T: Yes. The monitor pilot bleed line for a pressure-loaded regulator was connected to the downstream pressure system. When the working regulator failed, the elevated pressure in the downstream system caused the monitor to open. A relief valve and pilot regulator were added to the bleed line to prevent recurrence.

U: No

V: We had one case of double failure, caused by excessive debris in the line from a pigging operation coupled with a full filter.

6. Have you ever repaired a larger diameter gas line with a defect, damage or leak by welding on a smaller diameter cap instead of using a repair band or full encirclement sleeve? Did you consider the repair to be

permanent or temporary?

A: Our standards do not allow this type of installation, either temporary or permanent.

B: Yes. Permanent only if yield strength was less than 42,000

C: “Weld patches” were used historically, but current practice is for full sleeve or cut-out.

D: Yes, preference is a full encirclement sleeve, but have used weld caps, and consider these permanent.

E: No, however we recognize that there have been legacy repairs using this method

F: Caps are only used with nipples/pups to canopy over fittings such as service tees.

G: Yes. For leaking damages or defects, we have used pressure control fittings PC’s or hot tap fittings. We also use weldolet fittings with caps for non-leaking defects or damages. The key factor is that the weldolet dimensions exceed the dimensions of the damage. The repair is considered permanent.

H: Yes, On IHP it was a permanent repair, on HP it was a temporary repair

I: No

J: No, a smaller diameter cap is not used to repair a defect, damage or leak on a larger


diameter line; typically a repair band (clock spring etc.) or a full encirclement sleeve (pumpkin etc.) is used. Smaller diameter caps are used when services are cut off of the main.

K: No

L: There have been multiple occasions where we’ve utilized fittings to encase damage in permanently resolving smaller leaks on larger diameter pipelines. This consists of welding a fitting (generally a Save-A-Valve slightly larger than the area of concern) around the damaged area. Caps are not typically used as there is no way to test the welds made after the fact to ensure that it will indeed hold to the same pressure as the pipe it is connected to in the event of an MAOP violation. The fittings are typically tested to the same pressure as was the pipeline originally or when it was up-rated (if applicable). Repair bands are sometimes used, but are considered a temporary repair on our high pressure system (>60 psig).

M: Never tried that method. Have welded barrels and metal pins as permanent repairs.

N: No

O: We have installed saddles or weldolets over defects. We consider these to be permanent repairs.

P: No

Q: A permanent repair may be made in this way.

R: No, only industry-approved fittings or replacement are used for repairs.

S: Yes, we have performed this type of repair. Historically these were considered permanent repairs on both gas transmission and distribution.

T: We have made permanent repairs by fabricating a “dome” or utilizing a purchased fitting, to entomb a problem (or a leaking fitting) on a steel main. Any welding completed to “seal” a leak is not considered permanent; such a seal weld needs to be entombed with a separate fitting welded to a qualified procedure.

U: No

V: Yes, but only in distribution pipe, and considered permanent. Never on transmission.

7. When designing and installing new rectifier systems, how do you estimate the initial and ultimate amperage

requirements to adequately protect the pipeline segment?

A: Pipeline surface area X Est. coating coverage (varies by coating type and age) X 1mA, make this the midpoint of the rectifier specification. Maximum amperage would be determined by estimated coating loss at 50% of pipeline design life. Install enough anodes for maximum rectifier amperage for 20 year design life.

B: Current requirement test on the structure and historical trends

C: Historical readings, footage of steel being protected, etc.

D: Amperage requirement depends upon soil resistivity, pipe size and length to protect, and pipe coating. Calculated amperage is increased to provide safety margin and


account for coating deterioration.

E: Design calculation based upon amount of pipe to protect. Post-install evaluation of potentials to verify.

F: We have a CP design standard and we calculate current requirement for new pipe before it is installed. This number is 2 mA/Sq Ft. Once the pipe is installed we do a field current requirement test to confirm the amount of current needed. We also do current requirement testing on existing steel if we are upgrading the system. All new rectifier systems regardless of current required are no smaller than 8 Amps DC

G: A current requirement test is performed by measuring and recording the ON/OFF CIS pipe-to-earth potentials with the application of a DC test current to the facility. We obtain a minimum -0.90v at the lowest point(s).

H: When practical we use a temporary rectifier/anode or other method to estimate current requirement.

I: In Gas Distribution, we often use GIS to gather pipe lengths and diameters to use in calculating an estimated bare surface area that would need to receive the cathodic protection. Then we calculate the initial CP current needed and size it larger to allow added flexibility and future degradation. In Gas Transmission &Storage, we tend to use past experience and other rectifier sizes used on our system to select a rectifier larger than is expected, so we can supplement other rectifiers as their ground beds deplete or the coating deteriorates. Both groups test adequately after installation to determine the ultimate current requirements the rectifier will supply in order to bring our reads to necessary levels.

J: When designing new rectifier systems for existing pipelines, field testing is performed using a target of -850mVCSE polarized potential to determine current requirements. For new pipelines estimates of ground bed resistance using soil resistivity measurements and estimates of coating quality are made and current requirements are estimated accordingly. After rectifier installation, an interrupted survey of the pipeline is performed with all test points required to have a minimum “off” potential of -850mVCSE

. Rectifier current output is adjusted as required to meet this criterion.

K: Impressed Current Cathodic Protection System (Rectifier) Design: A corrosion technician performs a current requirement test from several locations to determine current demands and current attenuation based on the pipeline soil and environment condition of the total pipeline or segment therein. Once potential ground bed locations are identified, soil resistivity measurements are collected and the ground bed resistance calculations are performed based on soil resistivity. The total resistance is calculated based on soil resistivity data and ground bed configuration. The total resistance is used to determine the rectifier voltage so that the appropriate current can be discharged. The ground bed layout which specifies the type and quantity of impressed current anodes are chosen based on desired ground bed life span. The final rectifier size is determined based on pipeline specification and anticipated future expansion based on the class location of the pipeline. This is a summary of the process we go though to make sure we are properly designing an impressed current cathodic protection system

L: On an existing pipeline segments, we evaluate the coating type and condition (new pipeline, only the coating type) and, based on this evaluation, perform a calculation to estimate the current density. The rectifier and anode bed are then sized accordingly. A standard design for rectifiers covers the majority of installations.

M: No answer provided


N: Initial amperage is determined through analysis of the system (i.e. soils, pipe material, etc…). Ultimate amperage is obtained by directly testing the adequacy of the initial amperage along the pipeline. Adjustments are made where required.

O: Formulas consider soil resistivity, coating conditions, pipe length and pipe diameter.

P: 1 to 2 milliamps/sq meter of bare pipe. Amount of bare pipe based on age of coating, 2 percent per decade.

Q: For new pipe, rectifier requirements are calculated using coating efficiency, pipe size, diameter, length, and soil resistivity. For adding a rectifier to an existing piping system, a portable rectifier is set-up and actual readings taken throughout the system to determine amperage requirements.

R: We use soil -resistivity tests and current requirement calculations.

S: Initial current requirements are based on either historical requirements for the route or by calculating the current requirement based on coating type and assumed bare pipe surface area. The final design is typically supplemented with temporary ground bed tests to identify attenuation and possible soil resistivity issues.

T: Estimated amperage by performing a current requirement test from a temporary ground bed. Post construction of ground bed, a coupling survey conducted, control point(s) established, defined amperage. Rectifiers sized for approximately 50% additional capacity.

U: Soil resistivity tests when designing. After installation use a power source to throw current to the entire system and record on/off potentials. Using the lowest delta and the output current from the power source, calculate to determine the amount of current required to achieve a 0.30 delta.

V: There are many variables taken into consideration (age of pipe, soil resistivity, anode size, wire length, number of services, dry or wet environment, etc.). Newer main with proper coating is relatively easy to protect initially, but as coating stabilizes with time it will require more current, older main is more difficult as the coating applied and deterioration is a factor. We refer specifically to Peabody’s ‘Control of Pipeline Corrosion’ manual.

8. How do you count the number of leaks repaired for the annual DOT report? For example on steel pipe with

multiple pinhole leaks in a single excavation, would you count the number of through wall penetrations

separately, the number of leak bands installed or the entire job as one leak repair?

A: Leaks in a single excavation are counted as a single leak.

B: Count is calculated based on the total number of Leak Repair work orders

C: The annual DOT report reflects the number of “classified” leaks that were “created” and documented as repaired in our work management system. In the scenario you describe, there would have been one classified leak created and one leak repaired. Individual holes aren’t counted. If residual gas is coming into the excavation from another location, an additional leak is “created” for that repair.

D: For the annual DOT report, the number of leak repairs represents the number of physical repairs made to stop a leak, that is, total number of bands/sleeves, encapsulations, abandonments, and replacements.


E: Per leak report which includes all repairs within an excavation

F: Company typically counts the number of leaks repaired for the annual DOT report based on the number of leak repair WRs (work request / job) completed. For example, if a leak survey is conducted resulting in one leak found, a WR would be created to repair the leak. During the WR excavation, if more than one leak is discovered within the extents of the excavation, in most cases it would still be counted as one leak.

G: We count each repair requiring a separate excavation as a leak. The example in the question would be counted as one leak if all the pinholes or all the band clamps were in the same excavation. The only exception would be for multiple facilities in an excavation. For example, if we made a leak repair to both the main and the service in a single excavation, that would be 2 leaks.

H: Leaks are captured in a data base and are characterized by location (address, city, county, state), system (i.e. main or service) and by component (meter, fitting, riser, valve, regulator, tap, coupling). The number of leaks reported at a single site or excavation would be a function of main or service and component. If there were multiple leaks on a single component in a single excavation, this would be characterized as a single leak.

I: Most of the time we would count “number of leak bands installed.”

J: Leaks are counted based on the excavation site (i.e. multiple pinholes on the asset in one excavation site are considered as one leak).

K: For DOT reporting, we count each leak repair excavation as one reportable leak repaired. (Note: If a service line leak and main line leak are repaired in the same excavation, then one reportable leak repaired is reported for the service line and one reportable leak repaired is reported for the main.)

L: Generally, each leak event is counted as a single leak, regardless of the number of through-wall penetrations present.

M: Penetrations

N: Entire job as one leak repair.

O: All penetrations that can be repaired in a single excavation are considered to be a single leak repair.

P: Entire job as one leak repair.

Q: One excavation may be counted as a single leak. Typically the first pinhole to break through is caught in a leak survey before additional pinholes begin to leak.

R: The entire job, regardless of pinholes or clamps, is counted as one reported leak. This one leak is initiated, documented and tracked through one leak form.

S: Multiple pinhole leaks are not counted separately. The entire job is considered as one leak repair.

T: We count the number of repairs made, except for CI main breaks, for which we assume the entire job is a single leak repair.


U: We count the entire job as one leak repair.

V: We consider the entire job as one leak repair.

DTE – Timothy Miller

9. Do you use valves in plastic distribution systems or rely on pinch off tools to isolate systems? If you utilize

valves in plastic distribution systems what criteria do you use to determine where to put valves?

A: Yes, plastic values are used in distribution systems. Location is determined by local engineering design, as needed to isolate the system. Design based on many, many variables.

B: Yes, both. No set criteria. Customer count / location / other factors weight judgment

C: Very few plastic valves have been installed historically on two-inch and four-inch plastic systems, but are considered for six-inch and up.

D: Valves are used throughout the system including plastic distribution. Guidelines for valve location are: 1) installed at intervals not exceeding 5-miles for feeder mains (main that is high pressure or above, ≥6 in size, and provides a principal source of supply for an area served by smaller distribution piping), and 2) installed on lateral connections in newly constructed residential developments serving ten or more residential units.

E: We utilize valves in our plastic system. Emergency valves are installed so that valve zones include no more than 500-600 customers in a shut-down. Additional valves are generally installed at 4” and larger tees and at branch connections off of 4” and larger mains. We also utilize squeeze tools to isolate systems for construction or for emergency shut-down where circumstances permit.

F: We use a combination of both. Valves are used if they are nearby; we have guidelines that that there should be enough valves in a distribution system to isolate groups of approximately 2500 customers or less.

G: Yes. The criteria below apply to distribution systems, not just plastic distribution systems. For elevated pressure systems (MAOP greater than 0.5 psig), valves should be placed: i. At any change in pipe diameter of new main (valve placement should be on the larger diameter pipe). ii. When a new main is installed to supply gas to one or more distribution points. iii. To secure major river, highway, bridge and railroad crossings. iv. To isolate areas susceptible to major flooding. v. To isolate major geographical risk areas. vi. As required for isolation area or sectionalizing districts and spaced to reduce shutdown of a section of main in an emergency. vii. When new main crosses a designated isolation area or sectionalizing district. Emergency sectionalizing procedures shall be updated to reflect such installation(s). Additional factors that are considered: i. Is the main a single source of supply? ii. Does the area have a backfeed? iii. Is there a regulator or gate station involved? iv. Are there any sensitive customers on the line (e.g., hospital, school)?


v. Is the main feeding a dead end street? vi. Growth potential. vii. Location recommended for a system interconnect. For low pressure systems (MAOP = 0.5 psig), valves are not required on a LP distribution system except for the following: i. When new main crosses a designated isolation area or sectionalizing district. ii. When a main larger than 12-inch diameter crosses a major river, highway, or railroad crossing (unless valves are required for all mains by the specific railroad or local jurisdiction). iii. When specified by Engineering.

H: Use valves at all isolation boundary areas. Boundaries determined by customer count

I: We use pinch off points.

J: Both are used in the system, but there is a strong reliance on pinch off tools to isolate systems. Valves are placed in areas according to our design philosophy (i.e. load shed zones).

K: We utilize valves to manage total “system” size but typically use pinch off tools to isolate our system during a leak repair

L: We use valves on our plastic distribution system, but depending on the circumstances

we might use valves and/or pinch off tools to isolate a system. The criteria for determining valve locations and frequency are based on numerous existing and

potential future conditions. Some of those conditions include, but are not limited to,

the following: number of potential customers impacted, population density, emergency sectionalization, possibility of land movement, bridge crossings, water crossings, future

development, heavily paved areas, number of main branches, etc. Discretion is always required when installing valves on a new distribution main, but

general minimum guidelines require IP (or LP) block valves to be placed so that there

are a maximum of eight main branches between them or a maximum distance of one mile, whichever is shorter. The distance between block valves can be lengthened out

to a distance of five miles if located in sparsely populated areas. Branch valves (IP or LP) are also required, at a minimum, whenever branching a smaller sized main from a

larger main where the larger main is at least 4-inch IPS. It is important to reiterate that

these are minimum guidelines and does not preclude the possibility that more valves may be needed based on conditions indicated in the 1st paragraph of this response.

M: Valves. Placed to limit potential outage to no more than 500 customers.

N: Pinch off tools and plastic valves. We install valves at desired isolation points on the system.

O: Both are used. In some cases valve placement is dictated by state regulations. When this is not the case, Engineering, operations, and Compliance work together to define valve isolation sections.

P: We do use PE valves. Spacing and location are determined by the local Operations Managers to maintain their Emergency Operating Plan. Shut in zone size varies from one district to another. We do squeeze pipe, but we don’t count on that for defining the size of our Emergency Zones.

Q: Different criteria have been applied over years. We are returning to systems and adding valves to the largest areas. Steel systems are prioritized over PE for this effort, but PE systems are included. System layout should minimize customer outages and


have a reasonable number of valves to be closed in an emergency. A lot of factors come into play; steel vs. PE, customer density, critical customers (hospitals, etc.), geography and natural system layout, and back feeds or system reliability.

R: Poly valves and plastic stopper equipment are the preferred method of isolation. Squeeze-off occurs only when the preferred options are not feasible. The spacing criteria are a judgment made with consideration to reducing the time to shut down a section of main in an emergency.

S: We use plastic valves but more commonly use squeeze off tools to isolate systems. Valves are installed as needed to establish emergency shut-down zones.

T: We install valves in the course of new construction in plastic distribution systems. When designated as emergency valves, they are spaced no more than approximately 1 mile apart. Otherwise, they are spaced to be able to isolate approximately 500 customers.

U: We use valves. The criteria are similar to that of steel systems (ability to separate district regulator stations, amount of customers, length of pipe, critical main, etc.). However, we sometimes have fewer valves in predominantly plastic areas, knowing that we have the option of squeezing off. Also note that our system is predominantly low pressure (inches WC), where valves would rarely be used.

V: We utilize both methods. Criteria is based largely on population density in an affected area, the size of the main and whether it is a primary feed, or the impact on overall emergency sectionalization plans.

ENSTAR – John Lau

10. Does any of your transmission system lack information now required by pipeline reauthorization related to: a) insufficient hydrotest records; and b) insufficient material traceability? If so, how are you addressing them?

A: a) Yes. Risk model ranks these higher; preventive and mitigative measures such as pressure test or pipe replacement are employed. b) Yes. If the pipe segment is ranked higher, then metallurgical testing is performed to determine pipe characteristics.

B: a) Yes – Future hydrotesting planned b) Yes – We are pressure testing and material testing for this small portion of our system to verify integrity.

C: a) Yes. Conducting hydrotests as part of integrity work. b) Yes. Performing the approved assessment methods to address all threats.

D: a) No. b) No.

E: a) Y, Pressure Testing or Reduction of MAOP b) Y, Material field verification, substituting lowest acceptable value (if still meeting MAOP), Replacement of pipe or Reduction of MAOP

F: Yes, a limited number of pipe segments have been identified as having incomplete records. However, company has not made a final determination as to how it will remedy those segments.

G: We are currently evaluating this with a records review and have already identified


pipelines with insufficient hydrotest and/or material traceability. We have engaged a consultant to establish procedures and engineering methods for potential gaps in records and re-establishing MAOP.

H: a) yes b) yes Research and then retest or replace if needed

I: a) Yes, A plan is being developed to ascertain the most prudent method of reconciliation, i.e. retest, replace or other (yet to be identified). b) Yes, same as above.

J: a) Yes, currently the company is conducting MAOP assessments on lines that are >20%SMYS. Corrective actions and recommendations are provided by engineering and verified by operations. Example includes reducing pressure. b) Yes, see above. Example includes taking samples and testing.

K: a) Yes b) Yes Still evaluating – may replace small sections and hydrotest others.

L: a) {company removed} has approximately 12 miles of transmission pipeline that are in class 1 and class 2 locations which are considered HCA, or class 3 and 4 locations. Hydrostatic or pneumatic test records were found for {company removed} transmission pipeline segments, except a 7 feet long tie-in piping which the current segment MAOP is governed by the highest operating pressure during the 5 years preceding 7/1/1970. b) Records on material used for {company removed} transmission pipelines were found for all PSE transmission pipelines. Through review of various sources including As-built records, company historical purchase specification records, national codes review (i.e. ASA, and ASTM material codes), etc, {company removed} was able to determine the material used for our transmission pipelines.


N: a) Yes, we are analyzing the condition and making appropriate adjustments. b) Yes

O: a) Yes b) Currently there is no single process defined to address incomplete records.

P: a) Yes b) Yes Not sure yet, de-rating to less than 20% SMYS is an option, however may not be a long term solution if IVP extends to Distribution as well. Pipe replacement is the other feasible option. We do not plan to retest.

Q: a) Yes b) Yes Most insufficient records exist on “grandfathered” pipe. Monitoring PHMSA’s draft IVP for proposed steps. Testing coupons and cylinders removed during normal operations for material properties where insufficient records exist.

R: a) Yes. b) Yes. Addressing these issues will be done after receiving guidance from PHMSA.

S: a) Yes, we currently have insufficient pressure test records for some pipelines. We


have long term plans to pressure test all of our gas transmission pipelines. We are proceeding with this plan which was initiated in 2011 focused first on pipelines in Class 3, 4 and HCA areas as highest priorities. b) Yes, we have insufficient material traceability to specifications on some pipelines. We have used historical engineering procurement practices and our historical standards that allow us to make the most conservative engineering assumptions about the material specifications based on known information about the pipeline in these cases. However, in some cases this means that we must utilize the minimums (such as 24,000 SMYS) in the federal code.

T: a) Yes – Evaluating for hydrotest or replacement. b) n/a

U: a) No b) No

V: We have all the information (hydrotest, material documents (codes), construction data/as-built with hydro data) to validate the MAOP of our pipelines.

11. Is hydrotesting on any of your transmission systems prohibitive due to need for continuous service? If so,

what options, other than hydrotest to establish MAOP, have been discussed?

A: Yes has been prohibitive. If a hydro-test or nitrogen test is needed to establish MAOP on a one-way feed a by-pass or bottle trucks would be utilized. (Should the grandfather clause be eliminated we would have immense difficulty in complying).

B: We have been successful at removing from service and testing the identified lines.

C: It has been difficult but not completely prohibitive thus far.

D: Yes, however, testing was completed prior to the piping going into service and an MAOP was established.

E: To this point we have been able to shut-down pipelines for hydro-testing by providing temporary service or minimizing the shutdown duration. Where hydrotest is not feasible we would look at replacement or lowering the MAOP by the appropriate safety factor if possible.

F: It is possible for some parts of our system to be prohibitive due to service demands. In those cases, replacement is considered as the primary option.

G: Yes. In-line inspection via robotic pipeline crawlers (i.e. Explorer). In some cases, we will consider main replacement or retirement.

H: If hydrotesting is prohibitive, we use nitrogen when allowed by code. The MAOP for some pre-1970’s pipelines in our system was determined by analyzing the prior pressures and operating history of the line.


J: Yes, hydrotesting may be prohibitive due to continuous service. Options to establish MAOP are engineering assessed which includes but not limited to: reducing pressure, replacement of line and bypassing and retesting.

K: Yes. Replacement and expanding network/connectivity have been discussed


L: Yes, continuous service requirements would prohibit hydro testing to certify MAOP. We would most likely perform relocations on sections of piping without established testing records in order to prove MAOP.

M: We can take the outage.

N: Yes, evaluation plan continues.

O: Yes – no other approved options currently exist in our procedures.

P: Yes. None discussed.

Q: Replacement has been discussed.

R: Yes, hydrotesting is prohibitive to service. Alternatives have yet to be formally discussed.

S: CNG, LNG, temporary bypasses, cross compression (from distribution pressure to transmission pressure) and back-ties, as applicable, are utilized to provide continuous service while hydrostatic testing. When that is not feasible, pipe replacement and in line inspection are discussed. To date, ILI has not been utilized to establish MAOP.

T: No

U: No

V: No, we have no pipelines that have not had a post-construction hydrotest to establish its MAOP. We have used portable LNG or our own LNG facilities to feed and/or backup and area being in-line inspected.

12. Does your company ever hydrotest up to 100% SMYS on transmission pipelines? If not, what limitations are made?

A: Not currently. We pressure test to at least 1.5 times MAOP and most frequently use nitrogen.

B: We typically do not exceed 90% SMYS on pressure tests, however, have recently added approval to 100% SMYS.

C: No.

D: Transmission pipelines are pressure tested at 1.5 times the MAOP for 8-hours regardless of the % SMYS.

E: Yes, for new pipelines. Typically we test new pipelines at a minimum of 90% SMYS.

F: Yes, it is possible for us to test up to 100% of the SMYS, but only because our test range in those cases is established to be between 90% and 100% of SMYS. In no cases should a test ever come close to exceeding 100% of SMYS, as the test is mostly attempting to be above 90%.

G: No. Pipelines are typically tested at a minimum of 1.5 times MAOP. Pipelines typically operate at < 30% SMYS; New Pipelines are either designed to operate at < 20% SMYS or are built to be fully piggable.


H: We typically hydrotest up to about 90% of SMYS. We do not hydrotest to 100%.

I: No. 90% SMYS maximum.

J: Yes, 100% SMYS 4 hr hydro strength test is required for NPS 12 or higher.

K: No. Current standard limits test pressure to 80% SMYS

L: No. The highest that we might test to would be approximately 70-80% SMYS. However, we do not have a limitation in our standards that would preclude a test to 100% other than the requirement that the UTC be notified for any testing performed over 20% SMYS.

M: No – test to the needed MAOP.

N: No, hydrotest to 1.5 times MAOP

O: Yes. We try to test at less than 95% SMYS.

P: No

Q: We test to maximum of approximately 95% SMYS.

R: No. We test up to 90% SMYS.

S: Yes, for pipelines constructed with seamless or DSAW/SAWL pipe. Pipelines with ERW seams are limited to 95% SMYS. Detailed protocols for establishing max test pressures on existing pipelines are in place that considers age, seam type, probable Mill test pressure, operating history, construction methods and specifications of pipeline appurtenances/features.

T: No – Not to exceed 90% SMYS

U: No 1.5x MAOP

V: No, however we do spike test to 90% SMYS for 30 minutes, with a maximum at 95%, at the beginning of a required 24-hour test.

MidAmerican Energy – Michelle Payne

13. For companies that assessed casings using PHMSA’s casing guidance for ECDA, how are you handling the year 1 requirements for testing the structural integrity of the casing? Is anyone doing a 5 psig pressure

test? Have other methods – such as a water level test – been utilized?

A: In the past we have performed a 5 psig pressure test.

B: We are removing casings if any integrity issues are found

C: N/A

D: Have not performed structural integrity testing of casings.

E: Casings were either removed or pressure tested. We do not use ECDA on cased segments.


F: [Our company] does not utilize ECDA for assessing casings.

G: We perform 5 psig pressure test on the annular space and end seals as part of ECDA on casings.

H: We conduct all direct examinations within 12 months. We do conduct a 5 psi pressure test to test the integrity of the casing and end seals. Other test methods for testing the casing and end seal integrity are not used.


J: We do not assess casings using ECDA

K: Procedure is still being developed. We are looking at a combination visual inspection down vent tubes where casings have been grease filled and the 5 psig air pressure test.

L: We typically remove the casing to perform the guided wave ultrasonic test.


N: No answer provided

O: CP Survey is done every 6 months.

P: n/a

Q: N/A

R: We do not use ECDA. We require a 5 psig pressure test for all casing installations. We have not utilized any other methods of testing.

S: Currently [OUR COMPANY] treats the gelled/filled casings the same as the others – isolation testing is performed at the new casing or existing casing test stations every 12 months not to exceed 15 months; PHMSA’s guideline of quarterly testing for the first year may be incorporated in next revision of the Corrosion Standard. 5 psi pressure test is performed before filling/gelling, to ensure the integrity of the casing and the end seals. Water level test is not utilized at this moment.

T: No answer provided

U: N/A

V: We are currently able to assess our all our casings by ILI.

National Grid – Eric Aprigliano

14. Engineering Design – Load Analysis & Diversity Factors - When performing hydraulic analysis (SynerGEE or similar) of a single customers new load, do you use ‘total connected load’ or ‘diversified load’?

a. If you answered ‘Diversified Load’, do you diversify all equipment types - space heating, water heating, cooking, etc?

b. If you answered ‘Yes’ to all equipment, what diversity factor do you use for each category? (I.e. Space heating is 65%, water heating is 26%, etc.)

c. For the factors given in b, what is the source documenting the diversity factors?


d. If you answered ‘No’ for all equipment, what category do you apply a diversity factor to? Why? What

is the source document the diversity factors?

Answer: Primary question (‘total connected load’ or ‘diversified load’): For facility sizing, the “total connected” load is typically used for commercial and large industrial loads. For single residential customers, a “diversified load” is used based on the average calculated winter peak hour load for that load type. a) NO. b) NO. c) NO. d) Residential. The calculated average is based on peak monthly usage extrapolated to a design hourly volume using the load calculation program.

B: Primary question (‘total connected load’ or ‘diversified load’): Total connected load a) - d) N/A

C: Primary question (‘total connected load’ or ‘diversified load’): Use total connected for C&I customers and our standard (average) load for residential (~65 CFH) as calculated and tested in the past to have validated results for our area. a) - d) N/A

D: Primary question (‘total connected load’ or ‘diversified load’): For single customer load consisting of all gas appliances or all house heating, use total connected load. Can use a diversity factor of 0.90 if customer load consists of gas appliances and house heating. Diversity factor is based on an investigative study performed in 1960’s. a) - d) N/A

E: Primary question (‘total connected load’ or ‘diversified load’): Total Connected Load a) - d) N/A

F: Primary question (‘total connected load’ or ‘diversified load’): Diversified Load a) No b) N/A c) N/A d) Domestic load like water heating, cooking, and Discretionary load like gas logs, gas grills. Company Standard, Company Manuals

G: Primary question (‘total connected load’ or ‘diversified load’): a) We only diversify space heating (67%), water heating (26%), cooking (5%) b) Space heating (67%), water heating (26%), cooking (5%) c) Internal Corporate Procedure d) See response to a) above.

H: Primary question (‘total connected load’ or ‘diversified load’): Total connected load a) - d) N/A

I: Primary question (‘total connected load’ or ‘diversified load’): Diversified load a) All equipment b) We use an overall diversity factor of 90% c) Load information is collected from customer and sent to System Planning d) n/a

J: Primary question (‘total connected load’ or ‘diversified load’): Diversified load a) Yes between space heating load and base load (water heater, BBQ, etc) b) Space heating (100%) and base load (65%) c) Company best practices d) n/a


K: Primary question (‘total connected load’ or ‘diversified load’): Both. Total connected for service line but diversified for M&R set. a) Yes b) 0.70 c) Electronic measurement sampling. d) Diversified

L: Primary question (‘total connected load’ or ‘diversified load’): total connected load for new loads. Diversified load is used on existing customer’s additional load. a) all non-space and non-water heating equipment b) 75% c) n/a d) n/a

M: Primary question (‘total connected load’ or ‘diversified load’): Total connected load. a) - d) N/A

N: Primary question (‘total connected load’ or ‘diversified load’): Both a) Yes b) 0.7 for total load c) No specific source of origin d) n/a

O: Primary question (‘total connected load’ or ‘diversified load’): Diversified load a) Yes b) We apply a factor to the total connected load rather than the individual components. c) The factor is based on SME knowledge and actual consumption information for similar customers in that area. d) n/a

P: Primary question (‘total connected load’ or ‘diversified load’): total connected load unless it’s clear that a piece of equipment is for “back-up” a) - d) N/A

Q: Primary question (‘total connected load’ or ‘diversified load’): We will use fully connected load, and approve the load addition if that meets our system capacity criteria. If not, we will certainly consider practical diversity to see if our system may be adequate or to design improvements. Obvious examples are; a backup boiler, a furnace and outdoor pool heater. a) We would apply appropriate factors depending on the type of load. b) We do not have fixed factors to apply. It is a judgment where we may consider more factors than just type of equipment. c) NA d) NA

R: Primary question (‘total connected load’ or ‘diversified load’): Total connected load. a) - d) N/A

S: Primary question (‘total connected load’ or ‘diversified load’): For residential single family homes we use a gas demand per home based on historical actual gas use which includes diversified use. We do not determine usage based on individual equipment ratings. For other customers such as hotels, restaurants, office buildings we evaluate both the loading from similar customers and the load derived by applying diversity factors for multiple pieces of equipment within the single premise. We use the diversity factors in the AGA’s Distribution Gas Engineering and Operating Practices. See Volume III page


28. a) - d) N/A

T: Primary question (‘total connected load’ or ‘diversified load’): Total connected load. a) - d) N/A

U: Primary question (‘total connected load’ or ‘diversified load’): Total connected load. a) - d) N/A

V: Primary question (‘total connected load’ or ‘diversified load’): Total connected load. Single customers are modeled based on the equipment and loading details provided by Marketing, and reduced for any back-up load such as stand-by boilers if commercial, or non-heating season load such as pool heaters if residential. a) - d) N/A

15. When performing hydraulic analysis (SynerGEE or similar) of a multiple customers new load in the same general area on your system, do you use ‘total connected load’ or ‘diversified load’?

a. If you answered ‘Diversified Load’, do you diversify all equipment types - space heating, water

heating, cooking, etc?

b. If you answered ‘Yes’ to all equipment, what diversity factor do you use for each category? (I.e. Space heating is 65%, water heating is 26%, etc.)

c. For the factors given in b, what is the source and/or industry standard documenting the diversity factors?

d. If you answered ‘No’ for all equipment, what category do you apply a diversity factor to? Why? What

is the source document the diversity factors? e. For the diversity factors provided in b, do you apply a coincidence factor to each category after

diversification? f. If you answered ‘Yes’ to e, what coincidence factor do you use for each category?

g. For the factors given in f, what is the source and/or an industry standard documenting the coincidence factors?

h. How many customers in a grouping initiate the use of coincidence factors (i.e. greater than 5)?

A: Primary question (‘total connected load’ or ‘diversified load’): For facility sizing, the “total connected” load is typically used for multiple commercial and large industrial loads. Residential customer load is based on a calculated average peak hour load for that load type (diversified load). a) NO. b) NO. c) NO. d) Residential. The calculated average is based on peak monthly usage extrapolated to a design hourly volume using the load calculation program. e) NO. f) NO. g) NO. h) NO.

B: Primary question (‘total connected load’ or ‘diversified load’): Total Connected load a) - h) N/A

C: Primary question (‘total connected load’ or ‘diversified load’): Use total connected for C&I customers, and our standard (average) load for residential (~65 CFH) as calculated and tested in the past to have validated results for our area. a) - h) N/A

D: Primary question (‘total connected load’ or ‘diversified load’): Total connected load vs.


diversified load depends on the number of units. Look at either number of apartment units or number of heating units and non-heating units. If look at number of apartment units, no diversity factor is used for 1 to 4 units, factor of 0.75 used for 5 to 9 units, and factor of 0.50 for 10 or more units. If look at number of units for heating and non-heating, for heating: no diversity factor is used for 1 to 3 units, factor of 0.95 used for 4 to 5 units, factor of 0.90 used for 6 to 7 units, and factor of 0.85 used for 8 or more units. For non-heating, diversity factors created for number of units for cooking, water heater, and dryer. Diversity factor for each is relatively close and the factors decrease from 0.75 with 2 units down to 0.25 with 10 units. Diversity factors are based on an investigative study performed in 1960’s. a) - h) N/A

E: Primary question (‘total connected load’ or ‘diversified load’): Diversified Load a) Y b) Use average hourly peak day load with a safety factor c) - h) N/A

F: Neither, Unit loads have been developed by region for residential loads, based on regression of historic usage. a) - h) N/A

G: Primary question (‘total connected load’ or ‘diversified load’): a) We only diversify space heating (67%), water heating (26%), cooking (5% for one or more single family units). Cooking is also diversified separately for multifamily facilities depending on the number of units. b) See response to a) above. c) Internal Corporate Procedure and Coincidence Tables d) See response to a) above. e) For New York, coincidence factors are only used for cooking in multifamily facilities and depend on the number of units. For New England, coincidence factors are used for each category of equipment for multiple customers greater than 5 units. Then, the diversification factors from a) above are applied. f) For New York, cooking only depending on the number of units. For New England, all equipment categories; the coincidence factor depends on the number of units. g) Internal Corporate Procedure h) Five (5) Customers or greater

H: Primary question (‘total connected load’ or ‘diversified load’): Total connected load a) - h) N/A

I: Primary question (‘total connected load’ or ‘diversified load’): Diversified load a) All equipment b) Overall diversity factor of 90% c) Load information is collected from customer and sent to System Planning d) e) We use a coincidence factor also f) 85% g) It’s based on verification study analysis for each model based on actual pressure and flow data h) a single customer

J: Primary question (‘total connected load’ or ‘diversified load’): Diversified load a) Yes between space heating load and base load (water heater, BBQ, etc) b) Space heating (100%) and base load (65%) c) Company best practices d) n/a e) No, coincidence factors are not applied (if there is historical data for like buildings


that data is used) f) - h) N/A

K: Primary question (‘total connected load’ or ‘diversified load’): Diversified a) yes b) 0.5 to 0.7 c) Calibration with actual pressure readings. d) n/a e) No, overall number of customers. f) n/a g) n/a h) 5

L: Primary question (‘total connected load’ or ‘diversified load’): Total connected load for all new loads. However, load is diversified per Planning discretion on an apartment building, for example, to check system pressures. a) - h) N/A

M: Primary question (‘total connected load’ or ‘diversified load’): Total connected load. a) - h) N/A

N: Primary question (‘total connected load’ or ‘diversified load’): Both a) Yes b) 0.7 for total load c) No specific source of origin d) n/a e) No f) - h) N/A

O: Primary question (‘total connected load’ or ‘diversified load’): Diversified load a) Yes b) We apply a factor to the total connected load rather than the individual components. c) The factor is based on SME knowledge and actual consumption information for similar customers in that area. d) n/a e) Yes f) It varies due to the difference in our operating environments g) The factors are based on SME knowledge and actual consumption information for similar customers in the various operating areas. h) The coincidence factor is taken into consideration whenever multiple customers are connected to a network.

P: Primary question (‘total connected load’ or ‘diversified load’): Diversified Load a) Yes, we use a generic 90cfh/home for residential loads en mass. b) - h) n/a

Q: Primary question (‘total connected load’ or ‘diversified load’): diversified load, each existing large customer is evaluated for a design load and diversified load once a year. These loads are used to aid in determining new customer loads. a) No, single dyers or boilers do not get a diversified. b) NA c) NA d) Redundant equipment like backup boilers e) - g) n/a h) No set number

R: Primary question (‘total connected load’ or ‘diversified load’): Total connected load.


a) - h) n/a

S: Primary question (‘total connected load’ or ‘diversified load’): We follow AGA’s Distribution Gas Engineering and Operating Practices. See Volume III page 28. a) Yes b) – c) See response to primary question above. d) N/A e) - h) See response to primary question above.

T: Primary question (‘total connected load’ or ‘diversified load’): Diversified Load (residential customers only); Total connected load (commercial and industrial customers) a) No b) – c) n/a d) Heaters, AWH, ranges, and emergency generators are diversified. Other appliances are not included in the load estimate due to low input ratings or intermittent use. Diversity and coincidence factors are published in the company’s design manual and are dependent on the type of appliance and number of customers being added. e) – g) n/a h) 2 or more

U: Primary question (‘total connected load’ or ‘diversified load’): a) Yes, when designing main we diverse the load. When designing services we do not diverse the load on row houses, but we do diverse the load on commercial properties. b) - h) [no answer provided]

V: Primary question (‘total connected load’ or ‘diversified load’): Diversified Load a) Yes b) We take a percentage of total connected load, and scaled based on the number of customers and types of equipment proposed. c) We use a chart developed many years ago, source unknown. d) n/a e) We consider the coincidence factor the same as the diversification factor f) As in b, this varies based on combination of equipment used and units proposed g) n/a h) Greater than 5 units – however, once a customer has been active for >1 year, their actual usage is used in the hydraulic modeling using a commercially available module. This extracts and analyzes usage data using regression analysis based on base load and temperature factors.

16. Emergency Response Gas Outages - Does your organization have a gas outage management system? (Y/N)

a. If you answered ‘Yes’, is the application provided by an external vendor or was the application

developed internally?

b. If you answered “provided by external vendor”, who is the vendor/developer? c. If your organization does have a gas outage management system, what support does it provide?

i. Are you able to geographically see where the outages have occurred on a GIS (i.e. ESRI) or web based (e.g. Google, Bing, etc) mapping application?

ii. Are you able to generate a customer outage list from the application? If not, how do you

generate a customer outage list? iii. Does the data in the customer outage management system link to your GIS (i.e. ESRI)? How

often is the data refreshed? iv. Does the data in the customer outage management system link to your Customer Account

System? How often is the data refreshed?


v. Does the customer outage management system allow real time updates (i.e. turnoff & relight,

etc) from a wireless enabled laptop, mobile handheld device (i.e. Smartphone) or other field data capture device?

vi. Does your Customer Account System allow for pressure coding customer accounts (i.e. identifying system MAOP)?

vii. Do you have a web based application for customers to view gas outages?

A: Primary question (Y/N): YES a) Developed by internal IT resources. b) NA c) i) Yes.

ii) Yes. iii) Yes. iv) Yes. v) Yes. vi) No. vii) No.

B: Primary question (Y/N): No.

C: Primary question (Y/N): No

D: Primary question (Y/N): Yes a) Internally b) N/A c) i) No

ii) Yes iii) Yes, can obtain data from the GIS (Atlas) via the gas outage management

system (GOMS), or independently in GOMS using individual streets/premise addresses.

iv) Yes, weekly. v) No vi) No

vii) No

E: Primary question (Y/N): Y a) Internally developed b) N/A c) i) N

ii) Y iii) N iv) Y, System utilizes CIS data to generate lists/orders v) N vi) Y

vii) N

F: Primary question (Y/N): No.

G: Primary question (Y/N): No.

H: Primary question (Y/N): Yes a) Internal b) NA c) i) Not currently, but is under development in-house.

ii) The list is generated manually. The on-site tech calls in to dispatch with a list of meter numbers, which is tied to the customer.

iii) Not currently.


iv) Yes, instantaneous. v) Yes vi) Yes

vii) No

I: Primary question (Y/N): N a) b) System Planning uses SynerGEE Gas software from GL Noble Denton and ESRI

ArcMap for the hydraulic models and to assist with customer outages c) i) No

ii) We can generate a customer outage list from SynerGEE iii) - v) n/a vi) No vii) {company removed} is currently working on this type of application

J: Primary question (Y/N): Yes, it is a combination of SynerGEE modeling and GIS mapping a) Application is provided by an external vendor b) SynerGEE for modeling and GIS for Mapping c) i) Yes, ESRI is used for near real time updates from Work Management Center.

ii) Yes, ESRI would be able to provide a list of customers. iii) Yes, the data on customer outages is linked to ESRI and is refreshed every 24

hrs. iv) Yes, it is linked to our Customer Account System and is refreshed every 24 hrs. v) No, that option is not available. vi) No, option is not available.

vii) No, not available to customers.

K: Primary question (Y/N): Y a) Both we originally developed it internally we currently use the reports from our GIS gas isolation program, This data is then linked to a database that generates our field forms that crews use to shut off customers and relight them. b) EGIS (GE Smallworld) c) We currently use it in managing the restoration of service on shut off and relight

i) yes ii) yes iii) yes iv) yes v) No vi) No

vii) No

L: Primary question (Y/N): Y a) It is part of our GIS system b) N/A c) This is still in development, as our GIS was implemented just this year, so there is limited use and experience.

i) Y ii) Y iii) Y as it is a subset of the program iv) Y, nightly (same as 17a) v) N vi) N

vii) N

M: Primary question (Y/N): No


N: Primary question (Y/N): Y a) internally b) n/a c) i) Yes, ESRI

ii) Yes iii) Yes, weekly iv) Yes, weekly v) Yes, laptops in service trucks vi) Yes

vii) We have the capability, but are not using it at this time.

O: Primary question (Y/N): Yes. It is contained in our GIS, but it is currently not in use. a) External vendor b) General Electric c) i) Yes

ii) The system is capable of performing this function, but the data has not been entered into, or linked to the system. The list is currently generated by the meter reading routes.

iii) The outage management system is part of the GIS. iv) The system is capable of performing this function, but the data has not been

entered into, or linked to the system. v) No. vi) n/a

vii) n/a

P: Primary question (Y/N): Yes a) internally developed b) n/a c) i) Yes

ii) Yes iii) Yes, nightly iv) Yes, nightly v) No vi) Not sure

vii) No

Q: Primary question (Y/N): No

R: Primary question (Y/N): No.

S: Primary question (Y/N): No.

T: Primary question (Y/N): No

U: Primary question (Y/N): No

V: Primary question (Y/N): No (but planning to in the near future using GIS)

17. Does your organization plot all gas services on a GIS? (Y/N)

a. How often is your GIS updated with information from the Customer Account System? b. If you answered ‘Yes’, are you able to generate a customer outage list from the GIS using a trace

feature or by generating a polygon around an area to extract the information?

c. What is the accuracy of this information?

A: Primary question (Y/N): YES.


a) Nightly batch. b) Customer outage data is obtained in the internal application, which obtains data from GIS. The outage data is NOT directly from GIS. c) Only as accurate as the user who defined the outage polygon in the internal application.

B: Primary question (Y/N): Yes a) Daily b) Yes c) Accurate

C: Primary question (Y/N): Yes a) Postings are constant/ongoing. b) Not yet. c) N/A

D: Primary question (Y/N): No, not all gas services are plotted on a GIS, only for certain services (length >300-ft, non-standard configuration, >2” size, if main is extended to install a service, high-occupancy customers). a) - c) n/a

E: Primary question (Y/N): N a) - c) n/a

F: Primary question (Y/N): Yes, Southwest Gas posts gas services to the GIS a) During the posting of the service, a riser is also posted. Associated with each rise is a premise number(s) (account number(s)). We are able to assign more than one premise number to each riser to handle meter manifolds. b) Current GIS does not adequately handle traces well. We do not generate affected customer lists from the GIS at this point in time c) We currently have approximately 95-96% of the accounts posted to the GIS. We are currently migrating to a new GIS. With the new GIS, we plan to implement affected customer identification from within the GIS.

G: Primary question (Y/N): No. We do in some areas. For areas not where services are not plotted in GIS, service records are scanned into a Scanned Records database for users to access. a) For most of our GIS systems, the information from the Customer Account System is updated weekly. Most GIS systems are a one way feed from Customer Account System, but for some GIS feeds are two way. b) We can generate some customer outage information where the Customer Account System is linked and/or plotted in GIS. If the information is linked, the polygon method is used for selection. If the information is plotted, a trace can be done. This information is not live customer information. c) Reliability varies by region.

H: Primary question (Y/N): Y a) The GIS system has been interfaced to the customer Account System which gives us a live link. The data is therefore constantly updated. b) Yes, we are able to generate a customer outage list from the GIS using both a trace or polygon c) Since we have a live link to the customer data, the outage list should be very accurate and timely.

I: Primary question (Y/N): N a) N b) Y (we use service “nodes”)


c) varies, customer count is 92% or better, location could be improved

J: Primary question (Y/N): Gas services are put into GIS but are not plotted to indicate geospatially how the service is installed (see part “a)” for further clarification). a) New address points are passed from our Customer Account System into GIS once per week. They are then manually placed into the correct parcel of land. Once placed in the correct parcel an algorithm is run to draw a “Virtual Service Line” from the Address point (centroid) to the gas main that our asset management system has it connected to. The algorithm just draws the line perpendicular to the main, it is not an actual representation of how it was installed in the field. b) We do not do this today, but there is the potential to do this in the future. c) As mentioned above, the virtual service lines are just an algorithm which draws a line from the address point perpendicular to the main, it is not an actual representation of how it was installed in the field. However the paper field records with sketches are linked to the address points and accessible from the GIS. The asset information is also interfaced with the GIS and service information can be accessed from the GIS as well.

K: Primary question (Y/N): Y a) Daily b) Yes, we use an outage trace application that generates a list of customers with their contact information. c) The accuracy of this information is relatively high. We estimate that there are 5% of customers that do not have their account matched between the GIS system and the customer accounts system. Accuracy can also be affected by human errors in the work process.

L: Primary question (Y/N): Yes, all installed services are detailed in our GIS system. a) Nightly refresh b) Trace can be used to generate a predicted outage path and extract attached customers and objects. c) N/A – See answer above.

M: Primary question (Y/N): No a) - c) n/a

N: Primary question (Y/N): Y a) weekly b) Yes c) 95%

O: Primary question (Y/N): No a) There is no interface between the customer account system and the GIS b) - c) n/a

P: Primary question (Y/N): Yes a) Nightly b) Trace or Polygon c) not 100%

Q: Primary question (Y/N): Yes a) Once a week b) Yes – trace, user defined polygon, or predefined isolation areas c) The information in billing data, so mostly accurate

R: Primary question (Y/N): No. a) - c) n/a


S: Primary question (Y/N): Y a) We are currently developing a distribution GIS and have not deployed it. We are planning on plotting all services in GIS when available b) Yes, we will have the capability to do a trace to capture basic customer info to create a list. c) TBD

T: Primary question (Y/N): All meter points are plotted in GIS. a) Monthly b) Yes c) [no answer provided]

U: Primary question (Y/N): No a) - c) n/a

V: Primary question (Y/N): Yes, we attempt to plot through an automated process after extracting data from our customer accounts, matching account address with parcel address. We do not generally map actual service pipe & meter locations, only account identifiers. a) Weekly extraction and update b) We have not yet done so. c) We have approx 85% of our accounts mapped. Those missing are primarily due to mismatches between account and parcel addresses.

18. Does your company use/require a second level of overpressure protection above the primary regulator for

distribution regulator stations? (Y/N) a. If ‘Yes’, which of these is utilized (answer using numbers 1, 2, and/or 3):

1) Slam shut valve 2) 2nd Monitor Regulator

3) Relief Valve

b. What is the criteria for requiring a second layer of overpressure protection? (answer using numbers 1, 2, 3 and/or 4+text)

1) Pressure

2) Number of customers served 3) Population density surrounding the site

4) Other (specify) ______________________

c. Does your company require/perform formal process safety assessments of station designs? (Y/N)

d. If ‘Yes’ to c, what drives this process to be performed? (answer using numbers 1, 2, 3 and/or 4+text)

1) Pressure at station inlet

2) Number of customers served 3) Population density surrounding the site

4) Other (specify) ______________________

e. If your company performs formal process safety assessments of station designs, what numerical value for the probability of failure on demand (Pfd) is used for:

i. Control regulator failing Open

ii. Control regulator failing Closed iii. Monitor regulator failing Open

iv. Monitor regulator failing Closed v. Relief valve failing Closed

vi. Slam shut valve failing Open

A: Primary question (Y/N): YES.


a) 3 (token relief) b) 4 – Based on engineering design (not required by standards) c) NO. d) – e) n/a

B: Primary question (Y/N): No a) b) c) No d) – e) n/a

C: Primary question (Y/N): Yes. a) 3 b) 4, all factors are considered c) Engineering review required d) 4, any district regulator station d) – e) n/a

D: Primary question (Y/N): Yes a) 2 b) 1 c) No d) – e) n/a

E: Primary question (Y/N): Y for monitor stations a) 3 b) 2 c) N d) – e) n/a

F: Yes a) Primary method is 2 with 3 as an option b)4-Always used c)No d) – e) n/a

G: Primary question (Y/N): Yes a) 2 or 3 b) 1 c) Y d) 1 e) i) 2 x 10 -2

ii) 2 x 10 -2 iii) 4.1 x 10 -3 iv) 1.4 x 10 -3 v) 5 x 10 -3

vi) 5 x 10 -3

H: Primary question (Y/N): Y a) 2 b) 4 all stations c) N d) – e) n/a

I: Primary question (Y/N): Y a) 2,3


b) 1,2 c) N d) – e) n/a

J: Primary question (Y/N): Yes a) The company typically uses an operator regulator for pressure control and a monitor regulator for overpressure protection. There is no second monitor regulator. Sometimes there are full capacity reliefs and slam shuts valves are used instead of monitor regulators. These would be chosen based on the application. b) N/A c) No, not currently. The Process Hazard Analysis practice is being established for existing and new components of the pipeline system. d) – e) n/a

K: Primary question (Y/N): No. However, sometimes a token relief is added downstream of a operator-monitor set in remote systems

a) n/a b) n/a c) No d) – e) n/a

L: Primary question (Y/N): Yes a) 1, 2, and 3 b) 1, 2, 3, and 4 (Special features surrounding the site) c) Yes d) We have developed a safety checklist that is considered during the initial design and stays with the facility documentation to be updated and/or consulted provided there are significant changes made to the facility. The factors mentioned above would all be considered when filling this checklist out as well as during the design process. The checklist is required of all jobs, from the larger HP pipeline facilities down to a farm tap. e) We do not use this sort of criteria for performing safety assessments of our station designs.

i) - vi) n/a

M: Primary question (Y/N): Yes a) 3 b) 4 – This is the only means of overpressure protection required by code on our system. c) No d) – e) n/a

N: Primary question (Y/N): No a) – e) n/a

O: Primary question (Y/N): No a) – b) n/a c) No d) – e) n/a

P: Primary question (Y/N): No a) – b) n/a c) not sure what this means, each station is formally designed, peer reviewed, and then approved by a manager (PE). This process is the same whether it’s an industrial meterset, farm tap, or city gate station. d) – e) n/a


Q: Primary question (Y/N): Yes a) 3 b) 4 - (A single feed system serving 100 or more customers) c) No d) – e) n/a

R: Primary question (Y/N): Yes.

a) 2 & 3 b) 1 & 4- overall evaluation for relief capability throughout looped system. c) No. d) – e) n/a

S: Primary question (Y/N): Yes. a) 1 and 3 b) 4 - All low pressure (inches water column) distribution regulator stations. c) N d) – e) n/a

T: Primary question (Y/N): No a) – b) n/a c) No d) – e) n/a

U: Primary question (Y/N): Y (old standard, no longer required) a) 2 b) 1 (inlet MAOP of 150 PSIG) c) N d) - e) n/a

V: Primary question (Y/N): Yes a) 2 – working monitor b) 4 – this is our standard design c) No d) – e) n/a

19. New York State regulators have asked National Grid to state our policy for relocating meters/services from

inside to outside the customer's premise. National Grid would like to be sure that our approach is consistent

with the best utility industry practices. Would you please let us know:

a. Do you have a significant number if inside meter sets (i.e. 10%, 20%, 50%, etc.)? b. Does your company have a formal meter/service relocation policy?

c. Do you relocate meters from the inside to outside in conjunction with other mandated program work?

d. Could you give us an idea of how many services are relocated annually so that we can set reasonable expectations with the Commission?

e. Is there any cost to the consumer or is all work performed at the utility's expense?

A: a) 5% b) NO. c) YES. d) Not tracked today. Will be a DIMP performance measure beginning in 2014. e) Depends on situation. (Example: Is it part of a mandated program (DIMP) or is it at the customer’s request due to a room addition?)

B: a) 10% b) Yes


c) Yes d) Varies depending on geographic area of replacement work e) Utility’s Expense

C: a) We still have a small number of inside sets, <10%. b) Standard construction procedures call for outside installation. c) Yes. d) Too small to track formally. e) Utility, if done for utility’s purpose.

D: a) At least 50% are inside meter sets. b) Intent is to relocate inside meters to the outside where possible. Company Standards state to relocate an inside meter to the outside for certain situations when renewing a service. Nothing formal. c) No. d) N/A e) Cost performed at utility’s expense (provided the relocation is not the result of a build-over condition).

E: a) 30% b) Y, we relocate all meters outside with rare exception. c) We relocate meters during service renewal or where access is a concern. d) Estimated 5,000 meters per year e) All work performed at utility expense

F: a)NO <1% b)Yes c)N/A d)Unknown e)Customer pays cost

G: a) Of [our company’s] 2.543 million services, nearly 54% of them are inside services (meter sets). Because {company removed} services such a diverse territory, the ratio

of inside services to outside services varies by region. The greatest concentration of inside services is in (city removed), (city removed) and (city removed). b) While we don’t currently have a written policy on service relocations, we are in the process of writing one. However, current practice is that where practical, inside services are relocated to the outside. c) Yes. Whenever a service is being renewed (except by insertion) for bare steel replacement, leak prone pipe, flood zones, etc. d) This number not currently available. e) There is no cost to the customer if [our company] initiates the service relocation. If the service is relocated at the customer’s request, there is a minimum charge for the service cutback.

H: a) 2% b) No c) If feasible d) 5 on average e) If consumer requests relocation there is a charge, otherwise it is at utility’s expense.

I: a) [no answer provided] b) Yes, we have relocated meters serving residential customers that are served by mains delivering distribution pressures that range from 7 – 60 psig. We are also relocating meters that are supplied by mains delivering up to 14” WC as the gas mains are replaced with mains serving c) If a meter described in (b) is discovered.


d) [no answer provided] e) [no answer provided]

J: a) 5-15% of our meters sets are located inside. b) The company does not have a formal meter/service relocation policy. c) When doing the cast iron replacement program, the practice was to relocate meters sets outside. The cast iron program was completed in 2012. d) Not available. e) All the work performed is at the company’s expense.

K: a) Approximately 40% b) No c) No d) n/a e) n/a

L: a) 5 - 10% (rough estimate) b) No c) No. Meters can be moved outside when corrosion or leaks are an issue, but we do not look to move them outside when other work is being done. d) Varies per year but about 50 (rough estimate) e) Utility expense

M: a) 18% b) Our standard is to relocate outdoor, with limited exceptions c) Yes d) Estimated 3,300 per year, but that is without a formal program to relocate meters. e) If done in conjunction with other work (i.e., service renewal) no charge to customer. If done for customer driven work (i.e., remodeling), there is a charge.

N: a) 1% b) No c) Yes, cast iron replacement (unmandated program) d) e) Utility’s Expense

O: a) No b) No c) Yes d) Few e) The customer may pay if the customer line is found to be leaking. We check it prior to disconnecting the meter.

P: a) +/- 2% b) No. c) No d) [no answer provided] e) Utility expense

Q: a) 11% inside meters, 8% services with inside meters b) Yes, we have a capital program to target moving meters out and replacing services c) Yes, any opportunity to move meters out d) Meters moved: 4,499 (2009), 9,541 (2010), 12,929 (2011), 7,947 (2012), 7,600 (2013 plan) e) Utility's expense

R: a) 13% of our meters are inside sets.


b) No. c) No. d) No, this is not tracked. e) Currently, meters relocations are done as a consumer’s preference and are done at the expense of the consumer.

S: a) <10% of the inventory. Most are in (city removed). b) Yes. We have a policy to relocate outside of the building. If conditions do not permit, we have meters installed in cabinets. c) Yes. This is a requirement in our standards. d) Approximately 750 inside meters annually. e) No, unless this is customer generated work.

T: a) Approximately 2/3 of our meters are inside. b) Yes. c) Only if the new meter set cannot be accommodated within the existing space inside. d) Varies by year. e) If the relocation work is done at the customer’s request, they are responsible for the cost. Otherwise, it is done at the company’s expense.

U: a) Approximately 90% are installed inside. b) No. c) No. d) No. e) [no answer provided]

V: a) Approx 10% b) Yes, whenever service or meter work is required at an address with an inside meter, it is moved outside. c) Yes d) Approx 100 per year e) Utility expense, unless related work is requested by the customer (i.e. service build-over)

Pacific Gas & Electric - Karen Roth

20. How does OSHA Process Safety Management standard 29 CFR 1910.119 impact your company?

A: The impact is negligible in the delivery and supply side. On the supply side we do adhere to many of the tenets of PSM at the LNG plants. We complete the Hazard Analysis process before changing process material or operations procedures. Delivery references 49 CFR part 192 and 29 CFR 1910.1000 Hazard communication.

B: It does not. We do not have any of the hazardous chemicals, toxics, or reactives in sufficient quantity to fall under 1910.119

C: To be determined.

D: N/A

E: No answer provided

F: It does not impact our company. A letter issued by OSHA to its Regional Administrators, dated November 4, 1992, states that OSHA does not have jurisdiction in regard to the enforcement of the PSM standard on natural gas distribution and


transmission facilities.

G: [Our company’s] assets are not covered under OSHA’s Process Safety Management based on the materials and volumes we store as well as the exemptions provided by OSHA for LNG facilities.

H: High cost for compliance and amount of time


J: The OSHA PSM standard does not apply directly but the company is in the process of building a program; several PSM standards, including OSHA, are being used.

K: The impact that this regulation has had on our company has been that the company has developed programs/written plans throughout the organization that will allow us to identify and understand hazards posed by the process or processes involving hazardous chemicals. The company has developed and implemented safe work practices to provide controls of hazards during work processes for both company and contractor employees.

L: We have one facility that would be affected by the requirements in this PSM standard due to the use of large quantities of anhydrous ammonia. However, PSE does not formally operate the plant and is therefore not responsible for the implementation and oversight of a safety program associated with this PSM standard.



O: We don’t work with the toxic and reactive highly hazardous chemicals listed in Appendix A of 1910.119 at or above the threshold quantities.

P: No answer provided

Q: No answer provided

R: We do not have operations that fall under this OSHA standard.

S: Analysis in progress.


U: No answer provided

V: We do not believe it applies to our company at this time.

21. How many staff are assigned to Process Safety at your company?

A: There are no employees assigned to PSM at our company.

B: Zero

C: To be determined.

D: N/A


E: No answer provided

F: None as it applies to OSHA’s Process Safety Management standard.

G: One dedicated employee with others across the business performing process safety related tasks

H: Variable, it is not one employees assignment


J: 7-10 FTE

K: Duties are shared with various employees in our Health and Safety organization as well as in the operating groups.

L: None

M: 0


O: Our company has does not have anyone assigned specifically to “Process Safety”; however, we do have 19 employees assigned to all aspects of safety.


Q: No answer provided

R: N/A. See response to #20.

S: 1 – new Director of Process safety just hired and building out gap analysis prior to increasing staff.


U: No answer provided

V: None

22. Do you have a manual governing gas transmission pipeline and station design? If yes provide a general overview of contents included and level of detail covered (detailed procedures vs. high level requirements/specifications).

A: NO. Our standards manual contains [high level] 192 requirements.

B: Yes; Detailed; It covers the design requirements and recommendations including best practice from route considerations to completion as a company asset.

C: No

D: No

E: We have a standard design manual containing high level requirements/specifications.


F: Our Operations Manual covers some aspects of Transmission Design, but does not cover everything. Some items can be detailed, such as Transmission test requirements or the use of 3-Diameter elbows to ease ILI operations. However, other operations, such as steel horizontal directional drilling, are not covered.

G: We have detailed internal construction standards and procedures for both transmission and station design. The design standards provide a fairly high level of details and cover topics such as design requirements for transmission mains, regulator stations, in-line inspection tools, casings, and pipeline uprates. A good external reference for station design is AGA Gas Measurement Manual Design of Meter and Regulator Stations Part No. Nine prepared by the Transmission Measurement Committee.

H: We have standard practices for design of steel piping systems and regulator stations. We do not have a specific manual detailing pipeline design and construction. The standard practices include examples of problems as well as interpretation of code sections.

I: Engineering Design Manual is under development. When completed it will have detailed procedures for pipeline and M&R Station design

J: Stations are designed for <30% SMYS. There is a Regulation and Measurement Manual.

K: We have the following standards and procedures: - Design Considerations for Transmission Lines - Piping Materials, Components, Other Considerations, Records; - Design Information - Responsibilities, Pipe Specs, MOP, MAOP, Class Locations, Design Variances, Design Formulas - Manufacturing Specifications for Pipe & Pipeline Components - including Welding, Tapping & Internal Inspection Devices, etc. - Establishing MAOP

L: Yes. We publish two standards manuals that govern our gas pipeline transmission system. One manual governs “Operating Standards” and the other manual governs “Field Procedures.” Major topics covered in the “Operating Standards” include General Reference (e.g. definitions, description, etc.), Reports & Programs, Tools/Instruments/Materials, Design & Construction, Operations & Maintenance, Corrosion Control, Leakage Reduction, and Tapping & Joining Materials. This has essentially the same content as our distribution system operating standards, but has been modified in the appropriate places to accommodate transmission system requirements. Similar to the “Operating Standards” manual, the “Field Procedures” manual has close to the same content as the distribution system manual, except it too has been modified for the transmission system. Major topics covered include Emergency Response & Safety, Environmental, CP & Corrosion Control (Maint & Insp), Joining Pipe (Flanged and Threaded), Leak Detection & Repair, System Control, and specific procedures for unique transmission facilities. Welding procedures are covered in a separate manual. Since the majority of content for both of these manuals comes from our distribution system manuals, it’s appropriate to say that these procedures and requirements can be very detailed or high level. The level of detail varies based on the topic as well as our own experiences as an operator.

M: No

N: We have construction standards set in our operating manual. However, we avoid


installing any new main classified as transmission.

O: No

P: No

Q: Yes, relatively general section on materials, construction techniques, and testing requirements. Each transmission/high pressure project requires a tailored “High Pressure Design Specification” document created by the project engineer to detail material specifications, pressure test, valve & blow-down, piggability design, and construction specifications.

R: We have a Design & Construction Manual that gives high-level and general design guidelines in the areas of pipeline design, pressure regulation, welding, etc.

S: Yes – Follow up for more information.

T: Yes. Our design manual provides high level requirements and specifications for the design of transmission pipelines and metering & regulating stations.

U: No

V: Our standards manual covers both items from a generally high level. Transmission includes specs on pipe, pipe storage, valves, component specs, coatings, coating repair, pressure testing, MAOP, installation and trench requirements. Station specs include site location, valve locations, overpressure protection requirements, venting.

23. If not, then how is transmission design performed at your company including how you ensure consistent

design?

A: Gas engineering is responsible for all gas transmission design process. Peer review is performed on designs. Larger project designs are outsourced; company personnel reviews outsourced design.

B: N/A

C: We do not put in any new pipe >20% SMYS

D: The design of a new transmission line or station on our system is rare. Several aspects of transmission line design are covered in our general design/construction manual, including required cover, clearances, testing, and some materials. Transmission lines and stations are usually designed with coordination between our design department, a contractor resource, and engineering & standards. There are certain requirements that all of our transmission lines and stations must meet, but many aspects of the design are unique and must be individually evaluated from one job to the next.

E: We utilize standard designs, a bill of materials library and an approved vendor list. Also Engineering works closely with our Measurement and Regulation group to standardize equipment. All designs are subject to high-level review for consistency.

F: The items that are determined to be significant to overall Company Operations are included in our Operations Manual to promote standard designs, but many of the non-covered topics are managed as “on-the-job” training in our operating divisions. Major projects that meet certain requirements are sent to a central staff engineering group at


the Corporate office that will review the design for consistency and sound practices.

G: N/A

H: All projects are subject to an internal review process and approval of an oversight committee. This committee reviews the projects for code compliance as well as compliance with company standard practices.

I: Drawing review including design checklist and review by two approvers

J: N/A

K: n/a

L: n/a

M: We have a limited transmission system. Designs are contracted out. No formal need to have a “consistent” design.

N: Do not install new main classified as transmission.

O: Currently each operating area has its own set of design parameters. The company is in the process of creating an Engineering Design Manual.

P: We have a small group & we do “peer reviews” of designs before the Mgr signs off on the drawing.

Q: Consistency is managed through the review process.

R: N/A. See response to #22.

S: N/A

T: N/A

U: Only one transmission line

V: n/a

Philadelphia Gas Works – Thomas Pendergast

24. Does your company use 12” or larger plastic? Up to what pressures?

A: No

B: No

C: No

D: Only use plastic up to 8”, and highest pressure is the high pressure system which has a maximum operating pressure of 99 psig.

E: 12” up to 60 psig.

F: No


G: We use 12” PE up to 100 PSIG.

H: No

I: No, 8 inch is the largest diameter we have installed.

J: No, the largest approved plastic pipe is 8” PE plastic that operates at 64 psi. There is currently a 12” that is being piloted but has not yet been approved.

K: We use up to 12” plastic in our 60 psi systems

L: The largest diameter plastic pipe utilized by [our company] is 8” and it is employed up to the boundary of IP and HP, or 60 psig.

M: No

N: No

O: Yes. 60 psig.

P: No

Q: The largest PE pipe currently installed is 8” at 60 psig

R: 12-inch is the largest diameter PE pipe used at our company. Maximum operating pressure is 125 psig.

S: We do not use 12” or larger plastic pipe. We use up to 8” plastic pipe at up to 60 psig.

T: We use 12” plastic in systems that operate up to 60 psig.

U: No

V: We have 12” HDPE SDR 9.33 in our system at 100# MAOP. We have not installed it in over 15 years, and prefer steel for these diameters.

25. Does your company allow welding against control fittings, stopper fittings and valves during tie-ins? If so, at what pressures and do they take any other precautions?

A: Per our standards welding or hot tapping closer than 18” to a flange or threaded connection is not allowed. Welding closer than 3” to a welded seam (including long seam) is to be avoided.

B: Yes. We follow manufacturer’s directions for pressure and distances

C: Yes. Safety precautions included in welding procedures.

D: Non-welded joints are used for tie-ins.

E: Yes, on pipe near control fittings, at pressures consistent with stopping equipment rating. Additional precautions include air movers to prevent an explosive atmosphere where valves/equipment do not provide a bubble tight shut-off.

F: Yes, provided the welding is within the Manufacturer’s specifications for distance,


temperature and pressure limitations and within the CFR requirements. As for precautions, cooling fittings with cold wet rags (away from weld zone) is common.

G: Welding, cutting or grinding shall not be performed on a line containing air that is connected to a source of gas or other combustible/flammable material, unless appropriate isolation between the gas and welding is provided. I.e. Two closed valves; One valve and Two stoppers using a “double block and bleed” approach. Ref. “Pipe Welding Safety” (CNST05003)

H: On IHP system, 60 psig, weld a minimum of 3 pipe diameters away from the fitting and cool the control fitting with wet rags. On HP system, up to 500 psig against TDW plugging equipment, against valves depends on the upstream line pressure.

I: Yes, if 100% air in line or if a condition can be created where 100% gas exists. Can’t create condition where pressure builds. Must maintain minimum distances between the rubber stopper and weld point.

J: The company does allow for welding of control fittings, stopper fittings during tie-ins. Tapping and stopping equipment rating must be checked before operation. It may be necessary to lower the operating pressure of the line before any tapping or stopping procedure is performed. All pieces of equipment must be checked. The lowest rating in the equipment is the limiting factor.

K: Yes. We try to complete the work at line pressure. If the line pressure exceeds the limitations of our stopple equipment we will request a pressure cut. With any task involving the separation of main, the pressure is constantly monitored. Also when welding downstream the internal piping is monitored to prevent a dangerous air gas mixture.

L: We allow it, but it is not a common practice given the practicality of using field measurements to make exact cuts. We much prefer to use pups flanking any fitting to allow for changes to be made on the fly in field conditions if need be. Were this practice employed, we have established acceptable leakage rates under which welding can be performed. If there was a concern beyond this, our Gas System Engineering department would be consulted before allowing further work.

M: Try to avoid, but not always possible (establish a double block and bleed). Always make sure area around welder is less than 20% LEL and continuously monitor area with combustible gas indicator.

N: Yes, may lower pressure temporarily during welding. Additional precautions taken when welding on thin wall pipe.

O: Yes. The system operating requirements dictate the line pressure on the energized side of the flow control fittings. Commonly used safety precautions include the use of air movers, and nitrogen purging.

P: We don’t specifically disallow it, but we would normally have a fitting or pup of pipe welded between a tie in weld and the “control fitting”.

Q: No – We require a section of pipe between the tie in weld and the fitting

R: Yes, we allow this practice for all operating pressures. We use LH rods 7018 or 8018. If the pipeline contained gas and has been purged to atmospheric pressure, we will jet the main with air compressors to draw the residual gas away from the weld area.


S: Yes. Minimum distances between clearance points and welds are employed for all pipeline pressures. Other precautions such as external cooling can also be employed if needed.

T: All tie-ins are done with a double block and bleed setup. Welding can be done against the secondary stop-off. The double block and bleed requirement can be waived if the primary stop-off is a newly-installed valve (e.g. hot-tap valve) that provides a secure seal.

U: No. The pipe must be separated physically from the active pipe.

V: We do, so long as the heat generated can be monitored and minimized at a safe level so as not to affect the rubber components or seals. If close to the fitting, cooling of the affected area with wet rags or similar methods is required. A separation of 8”-20” is required from fitting to weld for sizes 2” to 12” pipe (at 2” intervals).

26. How does your company control stresses on pipelines on bridges?

A: We use either expansion joints or looping.

B: Designed with commercially purchased expansion joints or utilize design characteristics which absorb expansion / contraction

C: N/A

D: Provisions are made for expansion and contraction due to temperature changes in steel carrier pipe. Provide details for supports, expansion joints or loops, anchors, alignment guides, abutment connection.

E: Older installations utilize expansion joints. Newer installations are not anchored to the bridge structure.

F: Each end of the pipe is designed to be as non-fixed as possible (i.e. place carrier pipe inside of casing in dirt before it enters the bridge, with no part of the carrier pipe fixed by concrete). Some bridge crossings are entirely cased. Pipe supports are liberally used where possible to prevent bending stresses as much as possible, and to spread the pipe load.

G: We analyze the stresses but in reality we typically find that the stresses do not exceed what we would consider acceptable. As a rule of thumb we install an expansion joint for spans 200’ of greater. The concern is often the stress that will be put on the pipe supports as/if the pipe elongates and wants to bow slightly. The expansion joint prevents that.

H: We analyze and design our piping systems to resist all anticipated loads. This includes thermal, seismic and other types of external stresses. The bridges have been designed to resist the lateral and gravity forces without imparting these loads onto the pipe.


J: The company does not have a formal procedure to control stresses on pipelines on bridges. Engineering must approve the bridge crossing design. Expansion joints are used if required. In addition, bridge crossings are visually inspected annually and a detailed inspection is completed every 5 years.


K: We calculate the span for hangers and utilize expansion joints

L: Expansion loops are employed to minimize stresses in pipelines on bridges.

M: Expansion joints or pipe loops.

N: Expansion fittings and heavy wall pipe

O: The anticipated total combined stress placed on a pipeline is taken into consideration during the design process. Support placement and material specifications are selected to keep the calculated combined stress at an acceptable level.

P: Expansion loops or expansion joints.

Q: Expansion joints and insolated rollers

R: Stresses due to thermal expansion are calculated and addressed appropriately with the use of bends, loops, offsets or expansion joints. Stresses due to pipe weight and excessive vibration are also addressed with proper supports, hangers and/or anchors

S: We has above ground gas pipeline configurations that cross highway bridges or span over canyons, ravines, and stream channels. The pipelines that cross highway bridges are typically suspended from the underside of the bridge, or in some cases installed within a box section of the bridge. When the bridge structure is modified or when a new pipeline is constructed, it is necessary to perform a structural evaluation of the pipeline to insure that it is able to withstand gravity, pressure, thermal expansion and earthquake (and wind loads if the pipe is directly exposed to winds). We have a gas standard which establishes general guidelines for the design and installation of steel natural gas lines on steel and concrete bridge structures.

T: One or more expansion joints are required for spans over 80’. For spans under 80’, seal-only compression couplings are installed on either side of the span, with restraints installed to allow some expansion & contraction.

U: Expansion joints, loops

V: Expansion joints are used for spans 80’ or greater, with the number determined by the length.

27. Does your company have an accelerated main replacement program? If so, are you attempting to eliminate

low pressure systems (in w.c.) by area in the process and how does this affect your risk model?

A: DIMP program includes accelerated replacement of main. Low pressure systems are replaced on a risk basis, not based on pressure of pipeline. (For example: our cast iron replacement program is eliminating some low pressure systems; however, the replacement is not based solely on the pressure, rather it’s based on the cast iron.)

B: Yes. Yes. Eliminates risk for customer outage due to low pressure issues and reduces difficult to locate issues.

C: Yes. Our MRP includes cast iron, bare steel, and non-protected steel. To the extent that LP systems are made up of program pipe, we target them for replacement.

D: Accelerated main replacement program mainly targets cast iron and bare steel mains, replacing low pressure systems is secondary and does impact the priority of the main


replacements.

E: We have a leak prone main replacement program that includes the elimination of low pressure systems where possible. Larger low-pressure replacement projects may not score as high as smaller replacement projects but our SME selection of projects takes this fact into account. Since we have employed a systematic replacement approach for several years, in our low-pressure system, our medium pressure system is generally within reach on most replacement projects. Where it isn’t we will use a phased approach to advance the medium pressure into the area.

F: [Our company] has accelerated main replacement programs. We do not have any low pressure systems.

G: Yes – we have a proactive replacement program for unprotected steel and cast iron gas mains. When high pressure is available in the area of a low pressure main replacement project, we will try to replace the low pressure main with high pressure main. However, risk is always the primary driver behind our program – thus low pressure main that is determined to be in need of replacement will be replaced with new low pressure main if high pressure is not available in the area or is too costly to connect to the new main.

H: Yes but we do not have any low pressure systems

I: Yes we have an accelerated main replacement program and it is positively affecting our risk model.

J: No, the accelerated cast iron main replacement program was completed in 2012. There is currently an evaluation of the vintage plastic main in our <64 psi system; it is too early to make any conclusions regarding an accelerated replacement program.

K: [Our company] is currently in the 13th year of a 15-year AMRP program. Whenever possible, we are eliminating our standard pressure systems, inches-w.c., and our 5-pound systems. Not all the standard pressure systems will be eliminated. If pounds of pressure can be introduced with minimum amount of conversion work or if the system is a single feed system, then the pressure will be increased. Otherwise, some standard pressure systems will remain part of our distribution system.

L: Yes, we have 3 replacement programs to eliminate DuPont Aldyl-HD PE piping, bare steel and older steel wrap. Any LP piping that is found is typically replaced with IP but is not required. Operating pressure is not a factor for the risk model.

M: Yes. Low Pressure Systems are not specifically targeted. Going after Cast Iron, Bare Steel, Wrought Iron and Ductile Iron main, and bare steel services. We have some initial specific targets that management wants out first, but will be moving to targeting the areas from the risk model results.

N: No, yes. Risk is generally decreased due to new pipe being installed.

O: Yes. The risk model or state mandates identify the replacement order of the pipeline segments.

P: We are accelerating our early vintage PE pipe.

Q: Yes we have an accelerated main replacement program based on materials. We have one small elevated low pressure system which is not be targeted by the program.

R: Yes, we have an accelerated main replacement program. Our program does not


intentionally attempt to eliminate low pressure systems; however, if the opportunity presents itself, we will evaluate the chance to uprate a low pressure system.

S: We are currently replacing Cast Iron, along with pre-1940’s steel main, along with a Pre-1983 Aldyl-A main replacement program. Where we remove cast iron, steel and Aldyl-A, and it’s in a LP system, there is an effort made to uprate that system to high pressure. Our current risk model is not taking LP into consideration.

T: No

U: Yes. No.

V: Yes, we have a program, targeting unprotected steel and cast iron main. While not specifically targeting it, this will eliminate our remaining low-pressure systems.

Puget Sound Energy – Steve Schueneman

28. For meter sets that have a delivery pressure of 1 psig or more, when retrofitting the meterset to add a pipe nipple between the service regulator and the meter outlet, how do operators test the added pipe nipple?

When replacing a component of an existing meter set, it could be difficult to strength test each individual

non-rated component (e.g. short nipple, zero nipple, etc). Do operators either: a) pre-test these components; b) retest the entire meter set assembly (such as by spooling the regulator); or c) not test these components?

If your answer is a), what are some of the methods/procedures that operators use to test these short non-

rated component when retrofitting them onto an existing meter set?

A: Primary question (a, b, or c): Soap test the final connections. If a): n/a

B: Primary question (a, b, or c): C. If a): n/a

C: Primary question (a, b, or c): We use manufacturer’s tested components for meter loops and then leak-test at operating pressure upon installation. If a): n/a

D: Primary question (a, b, or c): b (Any segment that is taken out of service for repair needs to be pressure tested as for new construction.) If a): n/a

E: Primary question (a, b, or c): a If a): We utilize prefabricated meter conversion kits that are certified by the manufacturer.

F: Primary question (a, b, or c): C If a): n/a

G: Primary question (a, b, or c): a If a): C – We soap test all joints to ensure that they are not leaking

H: Primary question (a, b, or c): a If a): It is soap tested and checked with an electronic sensor for leaks when it is added in the field. It is not tested with air and a gauge.


I: Primary question (a, b, or c): a. If a): Pretest components. Prefabricated components are pressure tested at the factory. Locally made components must be pressure tested at 90 psig for 10 minutes

J: Primary question (a, b, or c): a. New stations are pretested before installation in accordance with the pressure test requirements listed in the manuals. If a): Retrofitted pieces are soap-tested once installed. Standard parts are already specified in the manuals.

K: When field performers work with the meter bracket, they will check the installation with a combustible gas leak detector (we use the Sensit Gold) and then they will apply a soap solution to all of the pipe joints on the meter bracket itself. The new brackets are all pre-assembled.

L: No answer provided


N: Soap test for leaks, all materials used are rated.

O: These fittings are subjected to a leak test rather than a strength test. If a): n/a

P: Primary question (a, b, or c): soap test at operating pressure If a): n/a

Q: Primary question (a, b, or c): C If a): n/a

R: Primary question (a, b, or c): b If a): n/a

S: c) not test these components


U: Primary question (a, b, or c): Under the meter set, on a spool, is an outlet to allow us to put up a gauge and use the delivery pressure to perform a test along with a Sensit.

V: Primary question (a, b, or c): C, we soap test at turn on. If a): n/a

29. Part 1 - Do operators use API 1104 Appendix B to qualify maintenance welding procedures? Some variables are considered as essential variables in API 1104 Section 5.4 that are not considered essential in Appendix B

for maintenance welding (for example, pipe grade and thickness); and some variables are considered as

essential variables in Appendix B that are not considered essential variables in section 5.4 (for example, operating conditions – cooling rate of flowing gas).

Part 2 - Per CFR 192.225 “Welding Procedures”, welding procedures must be qualified under section 5 of API 1104. Neither the CFR nor API 1104 Section 5 makes any reference to Appendix B. If API 1104 Appendix B is

used to qualify maintenance welding procedures, do you consider grade and thickness as essential variables

in addition to those “API 1104 Appendix B only” essential variables (e.g. operating condition)?

A: Part 1 – YES. Part 2 – Our company does consider grade and thickness as essential variables in additional to those “API 1104 Appendix B”


B: Part 1 – Yes Part 2 – API 1104 Appendix B variables only

C: Part 1 – N/A Part 2 – N/A

D: Part 1 – Do not use API 1104 Appendix B, use API 1104 Section 5 and/or ASME Section IX. Part 2 – N/A

E: Part 1 – Yes Part 2 – We consider grade as an essential variable but not wall thickness.

F: Part 1 – Some Operators do, our Company does not, as it is not required by the CFR (However, refer to NAPSR, as it is required by law in some state(s). Part 2 – For in-service fillet welds, specified minimum yield strength is not an essential variable. For in-service welds other than fillet welds, the strength of the completed weld should meet or exceed the specified minimum strength of the pipe and fitting material. An increase in the carbon equivalent above that of the material used for procedure qualification constitutes an essential variable, except as provided below. A procedure may be used for higher carbon equivalent materials than the material used for procedure qualification provided that the thermal conditions are less severe than the procedure qualification conditions and no increase in the risk of hydrogen cracking results. As for Thickness: For in-service fillet welds, wall thickness is not an essential variable. However, wall thickness of the materials being welded should be considered when considering the thermal severity of the pipeline operating conditions. For weld deposition repairs, the qualified welding procedure should not be used on a remaining pipe wall thickness less than what was used during qualification.

G: Part 1 - Although, API 1104 – Appendix B is a recommended practice, {company removed} is using Appendix B to qualify welding for in-service welding on transmission main. In-service welding procedure, severity of cooling is an essential variable and therefore, procedure and welder qualification is performed using a pipe with water cooling inside using low hydrogen cellulosic electrode. Part 2 - Pipe grade & thickness are not essential variables per API 1104 – Appendix B.

H: Part 1 – Yes Part 2 – Grade, yes. Thickness, no.

I: Part 1 – Yes. Procedures were qualified as of June 2013. See Michigan Gas Safety Standard 22nd Edition, 192.225 added rule R 460.20304. Part 2 – Material Grades and Wall Thicknesses are identified in the welding procedures. Ranges are not consistent with API 1104 section 5.4 or 6.2.2 (e), however, ranges listed in WPS are essential to the applicability of the In-Service welding procedures.

J: Part 1 – Yes, Appendix B is used to qualify maintenance welding procedures for our US affiliates. For the Canadian affiliates, maintenance welding procedures, CSA Z662-11 and ASME Boiler and Pressure Vessel Section 9, is used to qualify. Part 2 – There are limits to welding procedures based on essential variables which include grade and thickness.

K: Part 1 – Yes we do use Appendix B to qualify maintenance welding procedures. Part 2 – Yes we consider grade and thickness as essential variables in addition to those in Appendix B.





O: Part 1 – Yes Part 2 – Yes

P: Part 1 – We have not historically followed Appendix B for qualifying in service welding. We are going to start following some of the recommendations in Appendix B (like performing more specimen tests) as we develop more welding procedures. We have not used the water flow test assembly in the past but we may try it to simulate extreme flow conditions. Part 2 – Yes

Q: Part 1 – No Part 2 – NA

R: Part 1 – No. Part 2 – N/A

S: Part 1 – Yes, we use API 1104 Appendix B to qualify maintenance welding procedures. Part 2 – No, we do not consider grade and thickness as essential variables for API 1104 Appendix B weld procedure specifications, however we have conducted weld performance qualification tests and have PQR’s to confirm this consideration.

T: Part 1 – Yes. Our low-hydrogen in-service welding procedure is qualified under Appendix B. This procedure is specifically for welding on high-flow pipelines. Part 2 – We utilize a multiple qualification on 12” diameter 0.250” wall pipe (full open branch and butt) which qualifies our welders for all diameters, all thicknesses and all positions. We have a procedure for doing all welding on X42 and lower grade pipe and a separate procedure for all welding on X46 through X60 pipe. These are separate from the low hydrogen in-service procedure.

U: Part 1 – Not yet but we are currently developing a procedure according to appendix B. Part 2 – Not decided yet.

V: Part 1 – No Part 2 – We consider grade and wall thickness to be essential variables, by grouping (<X46, X46-X60, X65, X70 / <0.188”, 0.188”-0.750”, >0.750”).

30. Has your company determined there are particular gas facilities (as represented by standard designs e.g. for

particular metering facilities, which categorically do NOT have Class 1 Division 1 areas (as defined by the National Electric Code)? If so, what are those facilities? How was that determination reached? If OK to

contact, please provide name and contact info.

A: NO.

B: No

C: N/A

D: All gas facilities have Class I, Division 1 areas.

E: Yes, in accordance with AGA Publication XF0277, Classification of Gas Utility Areas for


Electrical Installations.

F: We also recognize Class 1 Division 2 areas as defined by NEC along with a company standard of “non category MSA” which requires the MSA be fed by 60 psig or less mainline pressure, well ventilated area, meter pressure of 5 psig or less and 2” or less on the regulator outlet piping.

G: AGA document (Catalog XL1001) is utilized along with API RP 500 to determine electrical classifications of areas. Using these guidelines, most areas are classified as Class 1, Div2. Div 1 areas are uncommon.

H: We consider regulator and metering stations inside of buildings Class 1 Div II because gas should not be present in the building under normal operating conditions.

I: No

J: Most stations have Class 1 Division 1 components

K: No, every station has at least a C1D2 area


M: No


O: Yes. Facilities without devices that vent gas do not have Class 1 Division 1 areas.

P: If we install electronics/telemetry at a station, then we abide by the Class 1 Div 1/2 rules. We have trouble controlling the customer’s actions within those zones.

Q: No

R: All of our stations are classified as Class 1, Division 2 locations. These stations include district regulators, all meter sets, compression stations, etc. I am not aware of any Class 1, Division 1 locations within our systems where flammable gases exist under normal conditions. You may contact (contact info. removed) for further discussion.

S: We only designate NEC classification areas around equipment located on Company property. We do not classify customer meter sets as hazardous areas because we feel that we cannot classify an area that is not on Company property. However, we do require the use of explosion proof lighting and ventilation equipment in new gas meter rooms. (contact info. removed)

T: No

U: No

V: As long as the gas is normally contained in a closed system, and it can only escape under rupture or failure conditions, we treat it as Class 1 Div 2. (5 feet from the outside dimension of above ground gas piping and devices; 5 feet around the outside dimensions of an underground vault containing gas piping; inside traffic control boxes with live gas instrumentation.)


31. Does your company have any low pressure distribution system (nominal 7 inches WC)? If so, under what

conditions do you favor liquid seal relief valves? Under what conditions do you favor relief valves? If you have and favor relief valves, why? What brand(s) do you use? If you favor liquid seals, why?

A: YES. We do not install relief valves on low pressure systems.

B: Yes. We do not.

C: Yes. We no longer install low pressure systems. Our LP relief valves are mostly Anderson Greenwood models.

D: Yes, we have a low pressure distribution system, but do not use relief valves, only district regulators.

E: We have a significant amount of low pressure system mileage (although it is slowly being phased out through our pipeline replacement program). We have older liquid seal relief valves in our system, however, any new regulator stations utilize spring or dead weight operated relief valves in the low pressure system.

F: N/A - We do not have any low pressure systems.

G: Yes. Liquid seal relief valves are still used. These are favored in older systems. We do not favor them, we prefer mechanical reliefs.

H: No

I: No liquid seal relief valves on SP System.

J: Yes, the company has low pressure distribution system. Liquid seals relief valves are not used but have monitor regulators. Overpressure protection relief valve: internal relief on monitor regulator, external relief of monitor regulator.

K: Do not have liquid seal relief valves

L: We have two small LP systems, each of which is protected by a liquid seal for overpressure events. The seals are preferred over the relief valves for the pressure ranges and overall costs associated with their operation and installation.

M: Yes. All Low Pressure outlet regulators stations have a relief valve and an oil seal for overpressure protection. Dual design used as a backstop in the event of a relief valve failure, since customers off LP systems are directly fed and have no protection in this event.

N: Yes, relief valves

O: Yes. We do not use liquid seal relief valves.

P: No

Q: No

R: Yes, we do have low pressure distribution systems. We do not use liquid seal relief valves. We favor dead weight relief valves.

S: Yes. We have low pressure distribution systems.


We do not use liquid seal relief valves. We have at least one low pressure relief valve installed in each hydraulically independent low pressure distribution system. The relief valves are in addition to the over pressure protection required by §192.195. Low pressure system relief valves are used for increased security for over pressure events and are in addition to the monitor with integral slam shut device installed at each low pressure district regulator station. We primarily use Fisher 66RR low pressure relief valves.

T: Yes. Our preference is to use liquid seal relief pots, due to a long record of reliable and safe operation in our system, and low likelihood of failure.

U: Yes. Never. We have eliminated relief valves at all district regulator stations and standardized with a worker/monitor configuration.

V: We do, and prefer a working-monitor regulator set-up instead of liquid seals or relief valves for new installations, though new installs are rare. However, a very large majority of our older stations have liquid seal reliefs.

32. Does any company use any device to remotely adjust regulator settings? If yes, please explain any

observations based on use that would indicate their successful or unsuccessful implementation?

A: NO, our company does not use remotely adjustable regulator settings. (We have some valves that are remotely operated.)

B: Yes. Field verifiable pressure readings after pressure change command given

C: We currently only have SCADA monitoring, not pressure control at this time.

D: Remotely adjust regulator settings on gate station feeder regulators and medium pressure backfeeds. Use real-time pressure/flow feedback.

E: We have successfully used remote pressure and flow controllers for many years at major stations. Remote controllers allow for better management of upstream capacity and sources as well as downstream pressure control during peak loads.

F: We do not have any regulators that are adjusted remotely, only control valves that are operated by a PLC/DPC through SCADA.

G: We implement pressure set-point control using two methods on our system. We change the pressure set-point on a regulator station by loading pressure on the control pilot vent chamber or with a direct coupled motor to the controlling pilot set point screw. In both cases commands from a remote terminal unit initiate the set-point change based on a program or operator command. The two methods are widely used and have provided a successful implementation.

H: No (however we are installing our first, but they are not functioning yet)

I: We have used Jordan Kixcels to remotely adjust regulator settings in the past. We have had problems with communication lag between the Control Center and the devices which has caused problems in being able to accurately adjust the regulator settings remotely. We currently have disabled the remote adjustment capability and adjust the regulators manually. We continue to use the Kixcels on our SP distribution system without any problems.


J: Yes, devices to remotely adjust regulators are found in gate stations and are controlled by operators in the control room. No problems have been encountered.

K: Yes, we monitor set point feedback, and output pressure to valve. Very successful operation. We can determine how close the controller is calibrated by using the various signals and know when the controller needs to be adjusted.

L: We have two automated systems installed to remotely change regulator settings. They are effective, but take a fair amount of time to make the changes relayed to them. As a result, the command of these devices is given to our gas controllers, who can monitor the changes in pressure triggered by the commands more effectively to ensure proper operation.

M: We do not.

N: Yes, we have remote monitoring at these locations, so we can watch our remote actions take effect. We have procedures in place to address any problems with remote regulators.

O: No

P: No

Q: Yes. We have utilized a number of methodologies for remotely controlling pressure or flow. For new installations, a current to pressure device (I/P) is used to apply pressure to the pilot spring case to control the outlet flow or pressure of a station.

R: We use SCADA that is monitored and operated by qualified personnel to control our remote station regulators. Successful implementation has been verified by field inspections and field pressure recordings.

S: We have remote set point adjustment on a limited number of key large controller operated regulator stations with electronic controls. The electronic controller set point in these cases can be adjusted remotely but a hard clamp is programmed into the controller to prevent remote adjustments that would exceed high or low limits governed by code or reliability. It is important that the set point adjustments are programmed in the station RTU to slowly ramp to the new set point adjustment so that excessive high velocities are not experienced.

T: Yes

U: Yes. We have some pilot-operated district stations that are adjusted from Gas Control. There is an RTU at each location which controls a linear actuator attached to the pilot. The system works fairly well and allows our Gas Controllers to manipulate the system as needed to maintain minimum pressures downstream.

V: No, we do not.

33. What is your company's frequency of inspection of indirect fired heaters for: a) checking the chemistry of

heat transfer fluid, and b) removing the coil for a direct (visual) assessment? c) What criteria do you use in maintaining proper chemistry of the heat transfer fluid?

A: a) N/A b) N/A c) N/A


B: a) Yearly b) None c) Send sample to lab yearly

C: a) N/A b) N/A c) N/A

D: a) Samples taken annually and sent to a lab for determination of corrosion inhibitor levels, lab provides corrosion inhibitors to add if necessary. b) Coil will be removed for inspection on a 10-year cycle (based on manufacturer recommendation). c) Lab determines proper chemistry to maintain based on corrosion inhibitor levels present.

E: a) Annual b) Never c) Send fluid samples to outside lab for analysis. (Goal – 50% Mix: Glycol to Deionized Water).

F: [Our company] does not use this equipment.

G: a) annual b) coils are not removed for inspection c) we follow manufacturers recommendations for pH, conductivity, and additive (inhibitors)

H: a) typically once a year b) no set frequency. We do it upon need and concern after glycol chemistry test c) use the recommendation from the glycol analysis

I: a) On an annual basis not to exceed a 15 month period b) We try to do a complete overhaul of the heater including removing the gas coil on a 10 year rotating basis. c) Ethylene Glycol %, PH, Metals present, Inhibitor concentration, Corrosion agents i.e. sulfates and Chlorides conc., Scale agents conc. i.e. magnesium and calcium, Contaminants conc, i.e. silica, lead, arsenic, nitrates, etc.

J: a) The glycol mixture chemistry is checked annually. b) Coils are not removed and visually inspected because everything is welded shut. Boilers are checked twice a year. c) Glycol mixture specifications.

K: a) We check them once a year before placing them in service during the fall b) we never remove the coil and do a direct visual assessment c) We send the samples to a lab for corrosion and we also use a refractometer to read the levels of glycol to water mix


M: a) Checked as part of annual inspection b) Coil is not removed c) Looking for the anti-freeze properties.



O: No answer provided

P: a) annually b) 10 yr c) we send the sample to the coolant supplier for analysis

Q: a) Annually b) No set schedule c) We follow the recommendations of our supplier of inhibitors which is based on the annual chemical analysis.

R: a) Annually. b) Not done on regular interval. c) Dictated by manufacturer’s recommendation.

S: We do not have indirect fired heaters in our territory.

T: a) Annually or more frequently if necessary. Corrosion coupons (tested/replaced annually) are used to monitor chemistry effectiveness. b) 10 years c) Monitor concentrations, specific gravity, pH, conductivity, alkalinity, and freeze point where applicable.

U: a) 0 b) 0 c) none

V: a) Annually b) No set schedule. Dependant on inspection results. c) Glycol concentration, pH, alkalinity, corrosion inhibitors, corrosives, glycol degradation, and contaminants present

34. What is your company's source of large volumes (i.e. over 10,000 scf) of nitrogen or dry air when conducting

pressure testing to 500 psig? What equipment (if any) does your company own to make, process and/or deliver the pressurized nitrogen or dry air?

A: Contract tanker companies or bottled gas. We do not own any equipment to make, process, or deliver testing medium, at large volumes.

B: None; None

C: We use standard air compressors up to ~100 psig, then contract nitrogen companies to bring the nitrogen via trucks for higher pressures.

D: Prefer hydrotest to large volumes of nitrogen for pressure testing. However, for instances where nitrogen is used, we use nitrogen bottles, and for large volumes use a rented nitrogen truck, truck vendor supplies all equipment to connect to our piping system to be tested.

E: We utilize a 3rd party supplier to provide this material/equipment.

F: Our company uses local gas/chemical supply companies to acquire high pressure nitrogen for tests. The nitrogen is delivered in high pressure bottles, or in a nitrogen truck if a large amount is needed (a truck is likely needed for the amount described). Our company can use truck-mounted air compressors for small-volume, high-pressure


tests, and will nearly always use them for distribution-level tests (90-120 psig).

G: We use water for pressure testing mains that operate above 124 psig. We have ordered nitrogen in bulk delivered by tube trailers with 2,000 psig cylinders for some projects.

H: Contract the service to an outside company, do not own equipment

I: We normally do not use that amount of nitrogen for testing and we don’t have any nitrogen or air plants to provide nitrogen or air. Testing with nitrogen generally uses standard cylinders of nitrogen.

J: A third party (Praxair) is used for our source of large volume of nitrogen. Depending on the application a tractor trailer or a nitrogen bulk pack is used. All delivery equipment, with the exception of the test-head assemblies are owned by the third party. Test-head assemblies must be designed, built, and pressure tested in accordance with Company policies. Before each use, the test-head assembly must be visually inspected for defects, gouges, grooves, and dents. This includes welded and threaded connections on the test head assembly.

K: No answer provided


M: Haven’t done this. Typically have hydrotested at those pressures.

N: Generally we use water, but would use a tanker truck for nitrogen.

O: The test media is typically procured by a contractor.

P: We have contractors with Liquefied N2 and vaporizer units that we bring in for large pressure tests.

Q: We use contractors to provide nitrogen or dry air for pressure testing large volumes. They provide the tanker trucks as needed. We currently don’t own any equipment for this type of process.

R: We only use water for pressure testing at these volumes.

S: [Our company] does not own equipment for these test medium applications. Third party contractors are used to provide Nitrogen and desiccant driers and compressors.

T: We obtain nitrogen for pressure testing from an outside vendor. We own the hoses and regulators necessary to connect the nitrogen to our facilities

U: At this time we only nitrogen test to 225 psi. For small volume pipe tests a standard nitrogen tank is used and for larger volumes a nitrogen trailer is ordered. A regulator and a 300 psi mercury circle chart are used to document the test.

V: We will bring in vendor tankers to supplement if needed, but prefer hydrotesting for large scale testing. We also use heated nitrogen or dry air for pipeline drying after hydrotesting.


SEMCO – Colton Lentz

35. What are other companies doing to ensure sanitary sewer leads are not damaged during main and service

installation? (When the local municipality don't provide or have do not have records for the locations of the sewer leads)

A: Nothing today. Currently investigating future program.

B: Scope sewer. Electrically or Non Electrically locate sewer

C: Most HDD contractors have procedures to use fish tapes and line locators to find and spot sewer services/laterals to ensure that they don’t bore through them.

D: Assuming sewer leads are services, this is still an area of concern, started testing a couple methods to locate sanitary sewer services, and started a pilot program to look for potential cross-bores through sewer lines.

E: Visual confirmation during excavation.

F: If the location has been identified as being a bore, we will pothole our facilities at a point where the bore bit will pass within 24 inches of our facility. If it will cross within the 24 inches, the entire circumference of the facility must be cleared. In addition, in locations where we identified gas lines that were installed via a bore, we have visually inspected those sewer laterals with a camera to ensure no cross bore occurred.

G: We test hole over all facilities to verify location. In the event we cannot locate, we camera the line afterward to insure we did not penetrate the sewer lateral.

H: Camera sewer laterals after installation if gas line is installed by HDD


J: The constructor must request a sewer lateral locate from the municipality in areas serviced by municipal sewers. If a municipal sewer lateral locate is not provided, the field review is used to determine if a private sewer lateral locate must be completed. If a private sewer lateral locate is not successful, make a site specific action plan and record it on the service ticket/as-laid drawing/field notes.

K: Prior to any construction, gas main or service, using trenchless technology, other than insertion, [our company] requires both the sewer mains and associated laterals be located. The sewer facilities can be located either by physically excavating the facility or by camera inspection. If the sewer facility is located by camera inspection then a second camera inspection will be required after construction and prior to being placed in service. [Our company] does require the camera inspection company to provide a DVD copy of the final inspection. Also, [our company] has recently extended their shared service agreement with the Metropolitan Sewer District of Greater Cincinnati through 2016. This agreement allows both companies to benefit from the camera inspection as well as sharing the cost of the inspection.

L: We have recently adopted the requirement of performing a post construction sewer inspection whenever trenchless technology is utilized. Prior to construction, sewers are identified through a One-Call system, paper records review and field observation. Our state One-Call law was recently amended to require sewer jurisdictions to indicate the location of sewer lateral taps when performing mark out activities.

M: We are testing several methods, including post installation camera, bio-balls, and pot-


holing over sewer.

N: Sewer Cameras

O: Our construction procedures have been revised to expose all sewer crossings. In cases where there the facility locations are unknown, we perform post construction camera runs.

P: Boring and other trenchless technology is not permitted in the presence of sewer mains, sewer laterals and other utilities without confirming the depth of those facilities.

Q: For directional drill method, see question 43. For open cut, observations during construction.

R: In this scenario, we use heightened caution and perform hand-digging when it’s anticipated that we’re in the immediate area of an unmarked sewer service.

S: Visual inspection of sewer laterals post construction.


U: Vent boxes are used to identify the general location of sewer lines and hand excavation is used in that vicinity.

V: We are utilizing ground penetrating radar along the length of all trenchless main installations, and physically locating the laterals when crossing during directional drilling.

36. Are any companies using Coriolis flow meters? If yes, explain how successful or unsuccessful they’ve been?

A: No

B: No

C: No experience in my area.

D: Do not use Coriolis flow meters for gas distribution, use one for liquid flow and it works very well.

E: Not as of yet, however we are investigating the use of Coriolis Meters to monitor fuel usage at compressor stations.

F: No, we are not using them.

G: Only in CNG Refueling Stations. They seem to work well. We calibrate them annually using a field transfer prover developed specifically for CNG stations.

H: No we do not use Coriolis meters

I: We have had generally good results using Coriolis Meters. We have used them to measure odorant, fuel for compressors, and outlet at City Gates.

J: Yes, Coriolis flow meters are used. They are successful and accurate. Built to a custody transfer standard, but may not have the custody transfer approved software.


K: [Our company] currently only uses the Micro Motion Coriolis flow meters at our Propane plants to measure the liquid flowing to the vaporizers. On the plus side, the Coriolis flow meters are easy to maintain -- requiring little to no maintenance and calibration. There have been a few issues with electronics at one location but other than that these meters are pretty reliable. As far as accuracy, [our company]only requires a reasonable amount of accuracy at the plants so the meters meet our needs.

L: We do not use these meters.

M: We do not.

N: No

O: Yes. They have been installed in small number of locations and the results have been positive.

P: No

Q: No

R: We have never used Coriolis flow meters.

S: We use Coriolis meters to meter natural gas into CNG vehicles. The reliability has been very good for this application. We do not use them for other applications.

T: We have a very small number of these installed, but are not currently installing any new Coriolis meters.

U: No

V: No, we do not use.

37. Are any companies using cathodic protection of their wells? What other methods are being used to protect

wells?

A: NA

B: Yes. Wireline test and sample coupons to trend corrosion

C: N/A

D: Do not own gas wells.

E: Default design – no CP on wells.

F: We do not have any wells if we are talking about Gas Wells.

G: Yes. Rectifier impressed current systems.

H: Some of our wells have cp systems installed, but we currently do not have a standard. Some reservoir engineers believe that casings in concrete create an oxide film on the metal surface which passivates the metal such that further mitigation isn’t required. The need for a companywide standard is under review.


I: We do typically bond the “injection” well flanges so that the wells receive cathodic protection current. However, a few years ago, we did have to disconnect the bond on some wells that were drawing excessive current to allow enough current to remain on the laterals and mainlines that we are REQUIRED to protect. For observation wells, we typically install a few anodes at the surface which will provide some protection, but it is unlikely it protects the entire well length.

J: There is cathodic protection on wellheads.

K: n/a

L: Yes, via impressed current.

M: We do not have wells.

N: n/a

O: We protect wells like pipe with rectifiers and deep well ground beds.

P: n/a

Q: We do not have any wells.

R: Yes, we use CP for well protection. We also use wax wrap for atmospheric protection.

S: We are developing a Well Integrity Management Program that is designed to monitor and assess the condition of the surface casing and production casing. The program includes pressure and rate monitoring, inspections of the production casing with MFL tools, and the utilization of other logging tools to determine if leaks are present on the production casing. The storage wells also have flow control to ensure the wells are not over flowed which could result the wells producing sand and induce erosion. All storage wells have cathodic protection. We are unaware of other companies’ procedures.

T: We do not operate any wells.

U: N/A

V: No, we do not have wells.

38. What is your communication plan in the event that cell phones go down?

A: Satellite phones.

B: None

C: Still maintain a company radio system.

D: Typically if company cell phones go down, can still use the two-way radio function (also have personal cells for many of our field crews). Other means would be I/M in our mobile dispatching system, pagers, corporate e-mail. We also have a messaging ALERT system which we can send messages to all mobile computers in the field – either by group or to entire mobile force…we typically only use that for emergencies.

E: We maintain a company radio system.


F: We use multiple communication methods that include email, text messaging, radio, cellular phones, and push-to-talk phones.

G: Business continuity plans as well as organizational emergency response plans incorporate the use of POT phones, two-way radios, and the use of messenger’s to deliver key information would be implemented when/if the first two back-up options are unavailable.

H: We rely on our radio system.

I: Utilize company radios.

J: In the event of failure of the cellular or landline telephone systems, field personnel shall attempt to communicate with dispatch by push to talk over cellular (two way radios) (if so equipped) to communicate their status and receive instruction. Where all systems are down, field personnel will report to their depot for instruction. Satellite telephones and spare radios are available in all depot offices and will be used to receive emergency calls in the area.

K: Since this question addresses cell phones going down, we have accessible land lines, as well as a hand held radio system in place. In the event of a large scale emergency, we have guidelines to instruct employees where to report to get instructions for work assignments and to maintain business continuity. These instructions are for normal business hours and after-hours operations.

L: Our backup means of communication would rely on radio, text messaging, and email alerts broadcast to all pertinent personnel, both in the field and in our offices for their support in performing emergency actions.

M: We have a dedicated radio system.

N: Back-up radios located in utility trucks

O: There is currently no other form of wireless communication in-place.

P: Emergency responders have radios in their vehicles.

Q: Crew radios

R: In this scenario, company radios equipped in each vehicle and operations office would be the main method of communication.

S: We have some Radio capability but coverage issues in some of our territory exist, satellite phones are stationed/tested within our divisions.

T: We maintain a trunked radio system for communications when cell phones are not available.

U: We will use hand-held radios, which were recently provided to all frontline supervisors and first responders (crews and technicians).

V: Our field crews, dispatchers and supervisors have a back-up radio system available.

Southwest Gas – Sheridan Greene


39. What transmission performance metrics are companies using to evaluate their integrity program, other than

those already collected in the PHMSA annual report)?

A: Those required by B31.8S and number of CIS miles completed, footage of CIS reads < -0.85, essential valves inoperable and repaired, SCADA communication malfunctions, non-compliant encroachments discovered, aerial patrol mileage, contractor attendees at one call meetings, agencies attending pipeline association meetings.

B: We track near-misses as well as failures and have expanded threat data sets to identify integrated threats and those raised risk areas to apply mitigating actions. We track that risk score annually. We also track total number of anomalies we repair regardless of within or outside of HCA and the number of one-year, monitored and scheduled indications identified along with the required immediate.

C: N/A

D: Other than the annual report information, do not collect other performance information. We track all remediations, and compare previous results, but no special metrics.

E: Preventive and Mitigative Measures applied after assessments (should decrease); Number of Emergency Response Drills performed/year; Average/Median Risk Scores per year. % of population within the PIR assessed.

F: We don’t have any metrics other than those collected in the PHMSA annual report.

G: [Our company] has a performance plan in place, as part of our Integrity Management Plan, which captures all of the requirements specified by PHMSA, as well as specified in ASME B31.8S. In addition, the Gas Transmission Engineering group conducts periodic meetings to discuss results, perform a peer review of specific pipeline assessments, and presents the results of recent assessments to other groups within the company via Transmission Task Force Meetings.

H: We use the metrics corrected in the annual report, 3rd party and Internal Audit, and number of integrity digs per year.

I: Miles assessed and Remediation digs completed annually

J: Other than the performance metrics collected in the PHMSA annual report no other metrics are currently gathered.

K: Track ASME B31 table 9 Performance Metrics

L: None


N: Results of integrity assessments

O: No answer provided

P: None

Q: 1. Miles of pipeline upgraded to piggable; 2. % of total transmission main that has had ILI inspection; 3. Casings cut-off or replaced

R: Close interval survey results, in-line inspection data (comparisons to previous runs),


system operations, field operations (such as leaks, evaluations of exposed pipe, 3rd party evaluations of cut out pipe, gas sample analysis, Coupon data, results of cleaning pig findings, etc.).

S: Corrective vs. preventive maintenance, reportable incidents, mark & locate requests completed on time (12 month rolling), over-pressurization event frequency, dig-in rate per 1,000 USA tags, at-fault dig-ins per 1,000 USA tags, leaks per rolling 12 month average, number of CPAs down over 365 days, average cycle time input of as-builts into GIS, inoperable valves, wholesale marketing customer satisfaction survey, and strength test cost per mile.

T: PHMSA report only.

U: N/A

V: We collect “extra” data on the number of Root Cause Repairs, by severity and year.

New Jersey Natural Gas – John Wyckoff

40. For inspection of distribution construction (quality control), what is your ratio of inspectors-to-construction

crews?

A: No standard ratio.

B: Average 1:2

C: Usually one inspector for every three or four contract crews.

D: 1 inspector to 3 or 4 projects which could have multiple crews (service, main, drill, etc.)

E: An inspector typically oversees two jobs at separate locations.

F: Company average is one inspector to four crews.

G: Service crews one Inspector for up to 5 crews based on geography. Main crews one Inspector for up to three crews

H: Preferably one to one, sometimes two crews to one inspector.


J: Currently there is between ¾ - 1 inspector per crew for contract crews. Moving to have an average of 1.5 inspectors per crew to cover for vacation and training.

K: We do not have a specific relationship between construction crews and inspectors. We currently have 27 inspectors who have various assignments. 5 inspectors are assigned to items such as compliance inspections, new and renew services, abandonments, locate issues and transmission digs. The remaining 22 inspectors are focused on main replacement and extension jobs. We typically try not to exceed 4 to 5 miles worth of replacement projects per inspector.

L: We have 10 QA&I inspectors on the gas side and approximately 60-65 service provider crews active at any given time. Most of the work performed does not require a QA presence, but in the worst case scenario, the ratio is approximately 6:1. (See answer


below for more exposition)

M: 1 to 5

N: Replacement/relocates 1:1, Distribution construction 1:2

O: We currently do not track this metric.


Q: On main and service replacement work, we assign one Inspector per contractor crew. We currently have a process for conducting post construction audits on new services, and do not require Inspection for this type of work. This requires the contractor to record all documentation during construction and take pictures of the actual installation process. Both are used for conducting the audit.

R: Company inspectors are only utilized when a contracted construction company is performing the work for our company. Per union contract, we use one inspector for two crews within a “reasonable distance” of each other. If the distance between job sites does not allow for adequate observation, the ratio would be one inspector for one crew.

S: 1 QC Specialist to 35 crews


U: 1:1 ratio

V: Average of 1:5

41. If construction inspection is part time (i.e. 1 inspector per 2+ crews), how much time is the inspector on the job site, on average? Do you have a minimum target time, or is it based on the task expected to be

performed?

A: This is not currently tracked.

B: Depends on the task being performed. Based solely on tasked expected to be performed

C: The priority is to be there at critical times such as pressure testing, tie-ins, taps/stopples, abandonments, etc. When no crews are performing critical tasks, inspectors split the time accordingly.

D: We have no target time, it is on an as-needed basis depending on the tasks at hand. We do require inspectors to be on-site for testing, pigging, and jeeping activities.

E: Inspection frequency depends on type of work and our experience with the contractor.

F: Inspection is based on the task being performed. Tasks such as boring, testing, etc., take priority; however each crew is visited at a minimum of once a week. Inspectors are on job sites approximately 50% of the day. Drive time, paperwork, meetings, training, etc. take up the rest of the time.

G: It is based on tasks being performed. There are certain hold points.


H: No minimum target time, it’s based on the task expected to be performed.

I: Based on task.

J: Based on task/work performed. One inspector for 3R (relocation, replacement & reinforcement) work/joint trench/ work on vital mains. One inspector per 2-3 crews for random service installs, maintenance work (cut-offs) etc. Responsibility charts has been developed to clarify when an inspector is required to be on site. Contractor is required to have a licensed inspector on site at all time and is fully inspected by the company.

K: The inspectors spend the majority of their day on their job sites. There is no minimum target time for an inspector to spend on each job. The amount of inspection required is dependent on the task that is being performed.

L: The time the inspector would be on site depends upon the type of work being performed. There are certain tasks that, per standards, aren’t allowed to be performed unless an inspector is present, so the scheduling of work is structured around ensuring that an inspector will be available to witness the work as required. Our service provider is responsible for developing a quality control plan that assigns the responsibility for direct inspection to crew foremen and quality control staff. {company removed} personnel perform a quality assurance audit function with regards to the service provider’s adherence to this plan. For jobs with higher risk or for work performed by contractors other than our service provider(s), {company removed} personnel may be assigned to directly perform inspection activities.

M: No set or target time. Time spent varies on complexity of job, experience of contract crew/foreman, and any issues arising from that job.

N: 80% direct inspection and 20% office/misc. Task expected to be performed.

O: We currently do not track this metric. Inspectors are expected to be on site to witness certain construction activities.


Q: N/A

R: An inspector is expected to use his discretion when splitting his time among two crews. Items such as damage prevention and collecting construction notes are examples of deciding factors when splitting time.

S: The QC Specialist is full time. Crew assessments are randomly selected and the time spend depends on job type. Average is 3 hours per assessment.


U: Full time inspection is required.

V: Average of 1 hour per inspection. Based on task performed. 42. Is your target of construction inspections different based on the type of work performed (i.e. new business/

replacement, mains/services, etc.)? Is documentation of the inspection completed for all work types?

A: This is not currently tracked.

B: Yes. Yes.


C: See previous response to #41.

D: The target number of inspections varies and is determined by the business area (new business, construction, maintenance). Documentation is captured numerous ways: time sheets, facility inspection reports, safety audits, contractor performance management system, and notes in our work management system.

E: Inspection frequency depends on type of work and our experience with the contractor. Inspections are documented on a weekly inspection form.

F: Inspection requirements regardless of the type of work are fairly equivalent when comparing new business, PVC/PE replacements, new main and services, etc. Note steel inspection response above. All inspection activity is supported by the completion of a Construction Contractor Field Evaluation (Form 252.0) for each site visit. Inspectors strive for one QC per day per crew whenever possible. Again, the ability for the inspection to achieve that benchmark depends on the extent and type of work being observed.

G: We break down Inspectors by Main and Service related work. Daily documentation sheets are completed by the Inspectors.

H: Yes


J: Yes, the target of construction inspection is different based on the type of work performed. Tasks depend on the crews’ work they have been assigned to. Inspectors are required a minimum number of inspections per month. Paperwork is required on all work types. Work includes: reviewing all paperwork, reviewing and approving all invoices are reviewed and approved and trying to see each crew on a daily basis.

K: The target for construction inspection is different based on the type of work. Less complicated jobs would require spot inspections as where complicated jobs such as transmission mains could have an inspector assigned to them full time

L: Yes, our inspections are dependent on the type of work being performed.

M: No real differences. Inspections are documented.

N: No, Yes

O: The target is based on the specific tasks associated with the type of work performed, and the location of the work. All types of work require inspection documentation.

P: Targets are the same. All inspections are documented.

Q: As described above, we do not provide inspection on new services, however, all other types of work are assigned one Inspector for each crew. The documentation is provided for all work types.

R: Inspection objectives are the same regardless the type of work performed by a contracted construction company. Documentation is done for every type of project when inspection occurs.


S: No, Job types are randomly selected. Yes, all assessment documentation is completed for all job types.


U: No. All pipe installation is 100% inspection.

V: Target to visit 100% of all replacement jobs daily, 50% of new business jobs. Other jobs such as CP test station/anode installs visited as available. Documentation is the same for all job types.

43. When installing distribution main by directional drilling, what is your current procedure for locating unmarked

or un-locatable sanitary sewer services that are being crossed?

A: We do not have a formal process for this.

B: Scope all. Expose facility in question if within close proximity of back reamer.

C: Most HDD contractors have procedures to use fish tapes and line locators to find and spot sewer services/laterals to ensure that they don’t bore through them.

D: This is still an area of concern, started testing a couple methods to try to locate sanitary sewer services, but nothing formal yet.

E: Pre and post installation camera inspection of sewer lateral if location and depth cannot be determined at crossing location using known depths at cleanouts and manholes.

F: A contractor is notified by a [company] contract inspector to respond on-site and attempt to locate and/or camera the sewer facility in question before proceeding with scheduled construction. When possible, facilities are marked for replacement/new business crews. If locating and camera methods are unsuccessful, often times the crew will be required to open trench the area of concern to prevent unknown sewer facility directional drilling damage. When possible, we will camera the sewer facility in question post bore to ensure no damage was done to the facility should a major concern exists.

G: Test hole, CCTV Inspection, locating from the lateral from inside the house.

H: Contact municipality for sewer lateral field notes. If un-locatable, camera sewer lines post HDD.


J: When private sewer lateral locate is needed the Locate Service Provider is contacted directly. A drill shot diagram is required from the constructor.

K: Prior to any construction, gas main or service, using trenchless technology, other than insertion, [our company] requires both the sewer mains and associated laterals be located. The sewer facilities can be located either by physically excavating the facility or by camera inspection. If the sewer facility is located by camera inspection then a second camera inspection will be required after construction and prior to being placed in service. [Our company] does require the camera inspection company to provide a DVD copy of the final inspection. Also, [our company] has recently extended their shared service agreement with the Metropolitan Sewer District of Greater Cincinnati through 2016. This agreement allows both companies to benefit from the camera


inspection as well as sharing the cost of the inspection.

L: We require that foreign utilities in the path of trenchlessly installed gas facilities be exposed/windowed and the bore head observed as it crosses. We also require a post-installation inspection of sewers in the area of the construction to confirm that no inadvertent cross bores are left behind.

M: We are testing several methods, including post installation camera, bio-balls, and pot-holing over sewer.

N: We are requiring our contractors to provide sewer camera inspection pre construction as well as post construction on a DVD, which will be a part of the completion report.

O: Our construction procedures have been revised to expose all sewer crossings. In cases where there the facility locations are unknown, we perform post construction camera runs.

P: We won’t use trenchless technologies if we can’t locate a sewer service.

Q: When a sanitary sewer lateral is not marked, and it is required that the crew has to directional drill past the lateral, we require the contractor crew to confirm that the lateral is not damaged by one of the following methods: Maps and Records Method – Maps and records of sewer lines may be used to demonstrate that no conflict between a gas pipeline and a sewer line is possible. Installers must have complete confidence in sewer line maps. Field Investigation Method – On-site investigation may be used to confirm that a minimum horizontal separation of 5 feet exists between the proposed installation and sewer line, so no conflict between the gas pipeline and the sewer line is possible. Exposed Sewer Method (test-hole, pothole, day-lighting, hand dig, etc.) Use a Test-hole to expose the cutting head and/or facility at any crossing to maintain a 6-12” separation. Relative Elevation Method – Determine the highest elevation of an individual sewer line by entering the structure and verifying the sewer drain’s elevation as it leaves the structure. The drilling head must be equipped with a sonde and the drill must at all times be at least three feet above the highest sewer service lateral elevation. The sonde must be calibrated daily. Televising Method – The verification of ‘no conflict’ of the individual sewer line is achieved by televising electronic images, after the gas pipe has been installed. Sonde Method – The sewer line location and depth are determined by a sonde transmitter at the crossed location. If this method is used, the drilling head must also be equipped with a sonde, and must be at least three feet from the sewer line. Each sonde must be calibrated daily.

R: Potholing (excavating to expose the un-locatable sewer service) to a depth of 1-foot below the proposed directional boring path is the typical practice for our company when this scenario occurs.

S: Construction crews will either expose sewer laterals before drilling or video inspect all sewer laterals and sewer mains that are crossed during drilling to insure that gas facilities are not in the sewer system.


U: Vent boxes are used to identify the general location of sewer lines and hand excavation is used in that vicinity.


V: Lateral is exposed during drilling and pullback. Laterals that cannot be found are investigated via ground penetrating radar.

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