Download:
pdf |
pdfInstructions (rev 1-2020) for Form PHMSA F 7100.2 (rev 1-2020)
INCIDENT REPORT – GAS TRANSMISSION
AND GATHERING SYSTEMS
GENERAL INSTRUCTIONS
Each operator of a gas transmission or gathering pipeline system shall file Form PHMSA F 7100.2
for an incident that meets the criteria in 49 CFR §191.3 as soon as practicable but not more than 30
days after detection of the incident. Requirements for submitting reports are in §191.7 and §191.15.
The intentional and controlled release of gas for the purpose of maintenance or other routine
operating activities is not to be reported. Reports are required if the loss of gas unintentionally
released is 3 million cubic feet or more.
Special considerations apply when a pipeline failure or release occurs involving secondary ignition.
Secondary ignition is a fire where the origin of the fire is unrelated to the gas systems subject to
Parts 191 or 192, such as electrical fires, arson, etc., and includes events where fire or explosion
not originating from a pipeline system failure or release was the primary cause of the pipeline
system failure or release, such as a refinery fire that subsequently resulted in – but was not caused
by – a gas transmission or gas gathering pipeline system failure or release. An event caused by
secondary ignition is not to be reported unless a release of gas escaping from facilities subject to
regulation under Parts 191 or 192 results in one or more of the consequences as described in §191.3
under "Incident" (1). The determination of consequences from a pipeline incident caused by
secondary ignition, though, is an area of possible confusion when reporting incidents. PHMSA is
providing the following guidance for operators to use when secondary ignition is involved
(sometimes referred to as “Fire First” incidents):
• A pipeline incident attributed to secondary ignition is to be reported to PHMSA
if any fatalities or injuries are involved unless it can be established with
reasonable certainty that all of the casualties either preceded the pipeline system
failure or release, or would have occurred whether or not the pipeline system
failure or release occurred.
• A pipeline incident attributed to secondary ignition is NOT to be reported to
PHMSA if the only reportable criterion is unintentional loss of gas of 3 million
cubic feet or more as described in §191.3 under "Incident" (1)(iii).
• A pipeline incident attributed to secondary ignition is NOT to be reported to
PHMSA unless the damage to facilities subject to Parts 191 or 192 equals or
exceeds $50,000.
These considerations apply to several pipeline incident cause categories as indicated in pertinent
sections of these instructions.
Form PHMSA F 7100.2 and these instructions can be found on
http://phmsa.dot.gov/pipeline/library/forms. The applicable documents are listed in the section
titled Accident/Incident/Annual Reporting Forms.
Page 1 of 37
Instructions (rev 1-2020) for Form PHMSA F 7100.2 (rev 1-2020)
INCIDENT REPORT – GAS TRANSMISSION
AND GATHERING SYSTEMS
ONLINE REPORTING REQUIREMENTS
Incident Reports must be submitted online through the PHMSA Portal at
https://portal.phmsa.dot.gov/portal, unless an alternate method is approved (see Alternate Reporting
Methods below). You will not be able to submit reports until you have met all of the Portal
registration requirements – see
http://opsweb.phmsa.dot.gov/portal_message/PHMSA_Portal_Registration.pdf
Completing these registration requirements could take several weeks. Plan ahead and register well
in advance of the report due date.
Use the following procedure for online reporting:
1. Go to the PHMSA Portal at https://portal.phmsa.dot.gov/portal
2. Enter PHMSA Portal Username and Password ; press enter
3. Select OPID; press “continue” button.
4. On the left side menu under “Incident/Accident (2010 to present)” select “ODES 2.0”
5. Under “Create Reports” on the left side of the screen, select “Gas Transmission and
Gathering” and proceed with entering your data.
6. Click “Submit” when finished with your data entry to have your report uploaded to
PHMSA’s database as an official submission of an Incident Report; or click “Save” which
doesn’t submit the report to PHMSA but stores it in a draft status to allow you to come
back to complete your data entry and report submission at a later time. Note: The “Save”
feature will allow you to start a report and save a draft of it which you can print out and/or
save as a PDF to email to colleagues in order to gather additional information and then
come back to accurately complete your data entry before submitting it to PHMSA.
7. Once you click “Submit”, the system will check if all applicable portions of the report have
been completed. If portions are incomplete, a listing of these portions will appear above
the row of Parts. If all applicable portions have been completed, the system will show your
Saved Incident/Accident Reports in the top portion of the screen and your Submitted
Incident/Accident Reports in the bottom portion of the screen. Note: To confirm that your
report was successfully submitted to PHMSA, look for it in the bottom portion of the screen
where you can also view a PDF of what you submitted.
Supplemental Report Filing – Follow Steps 1 through 4 above, and then double-click a submitted
report from the Submitted Incident/Accident Reports list. The report will default to a “Read Only”
mode that is pre-populated with the data you submitted previously. To create a supplemental report,
click on “Create Supplemental” found in the upper right corner of the screen. At this point, you
can amend your data and make an official submission of the report to PHMSA as either a
Supplemental Report or as a Supplemental Report plus Final Report (see “Specific Instructions, PART
Page 2 of 37
Instructions (rev 1-2020) for Form PHMSA F 7100.2 (rev 1-2020)
INCIDENT REPORT – GAS TRANSMISSION
AND GATHERING SYSTEMS
A, Report Type”), or you can use the “Save” feature to create a draft of your Supplemental Report to
be submitted at some future date.
Alternate Reporting Methods
Operators for whom electronic reporting imposes an undue burden and hardship may submit a
written request for an alternate reporting method. Operators must follow the requirements in
§191.7(d) to request an alternate reporting method and must comply with any conditions imposed
as part of PHMSA’s approval of an alternate reporting method.
RETRACTING A 30-DAY WRITTEN REPORT
An operator who reports an incident in accordance with §191.15 (oftentimes referred to as a 30-day
written report) and upon subsequent investigation determines that the event did not meet the criteria
in §191.3 may request that the report be retracted. Requests to retract a 30-day written report are
to be emailed to [email protected]. Requests are to include the following
information:
a. The Report ID (the unique 8-digit identifier assigned by PHMSA)
b. Operator name
c. PHMSA-issued OPID number
d. The number assigned by the National Response Center (NRC) when an
immediate notice was made in accordance with §191.5. If Supplemental Reports
were made to the NRC for the event, list all NRC report numbers associated with
the event.
e. Date of the event
f. Location of the event
g. A brief statement as to why the report should be retracted.
Note: PHMSA no longer requests that operators rescind erroneously reported “Immediate Notices”
filed with the NRC in accordance with §191.5 (oftentimes referred to as “Telephonic Reports”).
Page 3 of 37
Instructions (rev 1-2020) for Form PHMSA F 7100.2 (rev 1-2020)
INCIDENT REPORT – GAS TRANSMISSION
AND GATHERING SYSTEMS
SPECIAL INSTRUCTIONS
Certain data fields must be completed before an Original Report will be accepted. Your Original
Report will not be able to be submitted online until the required information has been provided,
although your partially completed form can be saved online so that you can return at a later time to
provide the missing information.
1. An entry should be made in each applicable space or check box, unless otherwise directed by
the section instructions.
2. If the data is unavailable, enter “Unknown” for text fields and leave numeric fields and fields
using check boxes or “radio” buttons blank.
3. Estimate data only if necessary. Provide an estimate in lieu of answering a question with
“Unknown” or leaving the field blank. Estimates should be based on best-available information
and reasonable effort.
4. For unknown or estimated data entries, the operator should file a Supplemental Report when
additional or more accurate information becomes available.
5. If the question is not applicable, enter “N/A” for text fields and leave numeric fields and fields
using check boxes or “radio” buttons blank. Do not enter zero unless this is the actual value
being submitted for the data in question.
6. If OTHER is checked for any answer to a question, include an explanation or description on
the line provided, making it clear why “Other” was the necessary selection.
7. Pay close attention to each question for the phrase:
a. (select all that apply)
b. (select only one)
If the phrase is not provided for a given question, then “select only one” should apply. “Select
only one” means that you should select the single, primary, or most applicable answer. DO
NOT SELECT MORE ANSWERS THAN REQUESTED. “Select all that apply” requires that
all applicable answers (one or more than one) be selected.
8. Date format = mm/dd/yy or for year = /yyyy/
9. Time format: All times are reported as a 24-hour clock:
Time format Examples:
a. (0000) = midnight = /0/0/0/0/
b. (0800) = 8:00 a.m. = /0/8/0/0/
c. (1200) = Noon
= /1/2/0/0/
d. (1715) = 5:15 p.m. = /1/7/1/5/
e. (2200) = 10:00 p.m. = /2/2/0/0/
Page 4 of 37
Instructions (rev 1-2020) for Form PHMSA F 7100.2 (rev 1-2020)
INCIDENT REPORT – GAS TRANSMISSION
AND GATHERING SYSTEMS
Local time always refers to time at the site of the incident. Note that time zones at the
incident site may be different than the time zone for the person discovering or reporting the
event. For example, if a release occurs at an gas transmission facility in Denver, Colorado
at 2:00 pm MST, but an individual located in Houston is filing the report after having been
notified at 3:00 pm CST, the time of the incident is to be reported as 1400 hours based on
the time in Denver, which is the physical site of the incident.
PART A – KEY REPORT INFORMATION
Report Type: (select all that apply)
Select the appropriate report box or boxes to indicate the type of report being filed. Depending on
the descriptions below, the following combinations of boxes – and only one of these combinations
- may be selected:
• Original Report only
• Original Report plus Final Report
• Supplemental Report only
• Supplemental Report plus Final Report
Original Report
Select if this is the FIRST report filed for this incident and you expect that additional or updated
information will be provided later.
Original Report
plus
Final Report
Select both Original Report and Final Report if ALL of the information requested is known and
can be provided at the time the initial report is filed, including final property damage costs and
apparent failure cause information. If new, updated, and/or corrected information becomes
available, you are still able to file a Supplemental Report.
Supplemental Report
Select only if you have already filed an Original Report AND you are now providing new, updated,
and/or corrected information. Multiple Supplemental Reports are to be submitted, as necessary, in
order to provide new, updated, and/or corrected information when it becomes available and, per
§191.15(c), each Supplemental Report containing new, updated, and/or corrected information is to
be filed as soon as practicable. Submission of new, updated, and/or corrected information is NOT
to be delayed in order to accumulate “enough” to “warrant” a Supplemental Report, or to complete
a Final Report. Supplemental Reports must be filed as soon as practicable following the
Operator’s awareness of new, updated, and/or corrected information. Failure to comply with
these requirements can result in enforcement actions, including the assessment of civil penalties as
provided in 49 USC 60122.
Page 5 of 37
Instructions (rev 1-2020) for Form PHMSA F 7100.2 (rev 1-2020)
INCIDENT REPORT – GAS TRANSMISSION
AND GATHERING SYSTEMS
For Supplemental Reports filed online, all data previously submitted will automatically populate in
the form. Page through the form to make edits and additions where needed.
Supplemental Report
plus
Final Report
If an Original Report has already been filed AND new, updated, and/or corrected information is
now being submitted via a Supplemental Report AND the operator is reasonably certain that no
further information will be forthcoming, then Final Report is to also be selected along with
Supplemental Report. If you subsequently find that new, updated, and/or corrected information
needs to be provided, submit another Supplemental Report.
A1. Operator’s OPS -Issued Operator Identification Number (OPID)
For online entries, the OPID will automatically populate based on the selection you made when
entering the Portal. If you have log-in credentials for multiple OPID, be sure the report is being
created for the appropriate OPID. Contact PHMSA’s Information Resources Manager at 202-3668075 if you need assistance with an OPID. Business hours are 8:30 AM to 5:00 PM Eastern Time.
A2. Name of Operator
This is the company name associated with the OPID. For online entries, the name will
automatically populate based on the OPID entered in A1. If the name that appears is not correct,
you need to submit an Operator Name Change (Type A) Notification.
A3. Address of Operator
For online entries, the headquarters address will automatically populate based on the OPID entered
in A1. If the address that appears is not correct, you need to change it in the online Contacts module.
A4. Earliest local time (24-hour clock) and date an incident reporting criteria was met
Enter the earliest local date/time an incident reporting criteria was met. In some cases, this
date/time must be estimated based on information gathered during the investigation.
See “Special Instructions”, numbers 8 and 9 for examples of Date format and Time format
expressed as a 24-hour clock.
A4a. Select the local time zone where the Incident occurred (select only one).
A4b. Select “Yes” if Daylight Saving was in effect at the time of the Incident, or “No” if
it was not.
Page 6 of 37
Instructions (rev 1-2020) for Form PHMSA F 7100.2 (rev 1-2020)
INCIDENT REPORT – GAS TRANSMISSION
AND GATHERING SYSTEMS
A5. Location of Incident
The latitude and longitude of the incident are to be reported as Decimal Degrees with a minimum
of 5 decimal places (e.g. Lat: 38.89664 Long: -77.04327), using the NAD83 or WGS84 datums.
If you have coordinates in degrees/minutes or degrees/minutes/seconds, use the formula below to
convert to decimal degrees:
degrees + (minutes/60) + (seconds/3600) = decimal degrees
e.g. 38° 53' 47.904" = 38 + (53/60) + (47.904/3600) = 38.89664°
All locations in the United States will have a negative longitude coordinate, which has already
been included on the data entry form so that operators do not have to enter the negative sign.
If you cannot locate the incident with a GPS or some other means, there are online tools that may
assist you at http://viewer.nationalmap.gov/viewer/. Any questions regarding the required format,
conversion, or how to use the tools noted above can be directed to Amy Nelson (202-493-0591 or
[email protected]).
A6. Gas released
Select the type of gas released. An example of Synthetic Gas is manufactured gas based on
naphtha. Landfill Gas includes biogas.
Important Note for Questions 7, 8, and 9: Volumes consumed by fire and/or explosion are to be
included in the estimated volumes reported.
A7. Estimated volume of gas released unintentionally
Estimate the amount of gas that was released (in thousands of standard cubic feet, mcf) from the
beginning of the incident until such time as gas is no longer being released from the pipeline system
or until intentional and controlled blowdown has commenced. Estimates are to be based on bestavailable information. Important Note: Volumes consumed by fire and/or explosion are to be
included in the estimated volume reported.
The volumes released during an Emergency Shutdown (ESDs) or relief valve activation should be
reported. When ESDs or relief valves are activated as the result of a safety condition that has
occurred, the volume released should be included in the “unintentional” category, even if safety
equipment performed as designed (such as a power loss or upon a PLC command). This would
include when an employee intentionally activates the ESD in response to an unintentional safety
condition, such as a grass fire in the station yard.
A8. Estimated volume of intentional and controlled release/blowdown
Estimate the amount of gas that was released (in thousands of standard cubic feet, mcf) during any
intentional release or controlled blowdown conducted as part of responding to or recovering from
Page 7 of 37
Instructions (rev 1-2020) for Form PHMSA F 7100.2 (rev 1-2020)
INCIDENT REPORT – GAS TRANSMISSION
AND GATHERING SYSTEMS
the incident. Intentional and controlled blowdown implies a level of control of the site and situation
by the operator such that the area and the public are protected during the controlled release.
Occasionally actions associated with response to an incident can involve activation of the
Emergency Shutdown (ESD) and associated relief equipment that occurs on a planned maintenance
basis after the incident initial safety response and the area has been evaluated for damage. For
example, an engine crankcase explosion has occurred and only one compressor in the area is
damaged. The immediate unintentional release was to activate the blowdown equipment associated
with this engine only. However, upon reviewing the damage, it was determined that the ESD
system should be activated for an entire station as more than one engine’s systems were affected
by the incident. The volume of intentional ESD release or associated relief devices that has
occurred after the evaluation in anticipation for the repairs should be included in the “intentional”
volume released.
A9. Estimated volume of accompanying liquid released
Estimate the amount of accompanying liquid that was spilled to the ground (or other containment)
as a liquid (in barrels) from the beginning of the incident until such time as the liquid is no longer
being released from the system. Barrel means a unit of measurement equal to 42 U.S. standard
gallons. If less than 1 barrel, report to 1 decimal place using the conversion table below. Small
volumes, including but not limited to those which sometimes result in some form of ignition, are to
be reported as 0.1 barrels.
If estimated volume
is
<5
5-10
11-14
15-18
19-23
gallons
gallons
gallons
gallons
gallons
Report
0.1
0.2
0.3
0.4
0.5
barrels
barrels
barrels
barrels
barrels
If estimated volume
is
24-27
28-31
32-35
36-39
40-42
gallons
gallons
gallons
gallons
gallons
Report
0.6
0.7
0.8
0.9
1.0
barrels
barrels
barrels
barrels
barrels
A10. Were there fatalities?
If a person dies at the time of the incident or within 30 days of the initial incident date due to injuries
sustained as a result of the incident, report as a fatality. If a person dies subsequent to an injury
more than 30 days past the incident date, report as an injury. (Note: This aligns with the
Department of Transportation's general guidelines for all jurisdictional transportation modes for
reporting deaths and injuries.)
Select “Yes” or “No” and if “Yes” is selected, enter the category of person(s) and number of
fatalities resulting from the Incident.
Contractor employees working for the operator are individuals hired to work for or on behalf of
the operator of the pipeline. These individuals are not to be reported as “Operator employees”.
Page 8 of 37
Instructions (rev 1-2020) for Form PHMSA F 7100.2 (rev 1-2020)
INCIDENT REPORT – GAS TRANSMISSION
AND GATHERING SYSTEMS
Non-Operator emergency responders are individuals responding to render professional aid at the
incident scene, including on-duty and volunteer fire fighters, rescue workers, EMTs, police officers,
etc. “Good Samaritans” that stop to assist are to be reported as “General public.”
Workers Working on the Right-of-Way, but NOT Associated with this Operator means people
authorized to work in or near the right-of-way, but not hired by or working on behalf of the
operator of the pipeline. This includes all work conducted within the right-of-way including
work associated with other underground facilities sharing the right-of-way, building/road
construction in or across the right-of-way, or farming. This category most often includes
employees of other pipelines or underground facilities operators, or their contractors, working
in or near a shared right-of-way. Workers performing work near, but not on, the right-of-way
and who are affected are to be reported as “General public”.
A11. Were there injuries requiring inpatient hospitalization?
Injuries requiring inpatient hospitalization are injuries sustained as a result of the incident and that
require both hospital admission and at least one overnight stay.
Select “Yes” or “No” and if “Yes” is selected, enter the category of person(s) and number of
fatalities resulting from the Incident.
See Question A10 for additional definitions that apply.
A12. What was the Operator’s initial indication of the Failure? (select only one)
Select the best option to describe the manner in which the operator initially identified the failure
resulting in this reported Incident.
Controller means a qualified individual whose function within a shift is to remotely monitor and/or
control the operations of entire or multiple sections of pipeline systems via a SCADA system from
a pipeline control room, and who has operational authority and accountability for the daily remote
operational functions of pipeline systems.
Local Operating Personnel including contractors means employees or contractors working on
behalf of the operator outside the control room.
A12a. If the Incident was identified by Operator’s personnel or a contractor working for the
Operator (including controller, air and ground patrols) in A12, identify if it was by an Operator
employee, or a contractor working for the Operator.
A13. When did the operator identify the failure?
Enter the date/time of the operator’s initial indication of the failure. The earliest date/time that an
incident reporting criteria was met is reported in item A4. In some cases, the operator may become
aware of a failure before an incident reporting criteria is met. In other cases, one or more incident
reporting criteria may be met before the operator becomes aware of the failure.
Page 9 of 37
Instructions (rev 1-2020) for Form PHMSA F 7100.2 (rev 1-2020)
INCIDENT REPORT – GAS TRANSMISSION
AND GATHERING SYSTEMS
A14. What part of the system was involved in the Incident?
Select the best description of the part of the system that was involved in the Incident. Only one
selection may be made.
A15. What was the operational status of the pipeline at the time the failure was identified?
Select the best description of the operating status of the pipeline system at the date/time reported
in A4.
Post-Construction Commissioning means the introduction of product, testing and
commissioning of the pipeline prior to the start of commercial operations.
Post-Maintenance/Repair means purging and packing of the pipeline when returning it to
service from maintenance or repairs.
Routine Start-Up means the start-up of the pipeline, facility or system in normal operations, or
returning from maintenance or other idle status following a time of no flow, but the where the
pipeline remained liquid full, and the start-up was being conducted under normal start-up
procedures.
Routine Shutdown means the stoppage of equipment or the system from a normal operation
status.
Normal Operation, include pauses during maintenance means the pipeline is operating
normally, and any of the maintenance that is occurring does not require product to be removed
from the pipeline or system. Product sampling, inhibitor injection, in-line inspection, installation
of repairs, and other activities covered by the operator’s Operation and Maintenance Procedures
are examples of the maintenance included in this category.
Idle means that the pipeline has been removed from service for commercial reasons or to make
repairs. The pipeline may contain product, an inert gas, or be empty. When residual product
accumulates in an excavation and ignites, Idle is the proper status.
A16. Was the pipeline/facility shut down due to the Incident?
If A15. is Routine Start-Up or Normal Operations, indicate if shutdown occurred as a result of the
incident, including but not limited to those required for damage assessment, temporary repair,
permanent repair, and clean-up. Do not include equipment shutdowns that do not affect the pipeline
or system operation. For example, if a compressor shutdown occurred as part of the incident, but
the pipeline was able to continue operating, select No. If No is selected, explain the reason that no
shutdown was needed in the space provided. A possible explanation for the example above would
be “The pipeline continued to operate through the station bypass piping and did not require a
pipeline shutdown.”
If Yes is selected, complete Questions 16a and 16b.
16a. Local time (24hr clock) and date of shutdown
Page 10 of 37
Instructions (rev 1-2020) for Form PHMSA F 7100.2 (rev 1-2020)
INCIDENT REPORT – GAS TRANSMISSION
AND GATHERING SYSTEMS
16b. Local time pipeline/facility restarted
The time is to be shown by 24-hour clock notation, and is to reflect the time in the time zone where
the incident was physically located. (See “Special Instructions”, numbers 9 and 10.) Enter the time
and date the pipeline was isolated or equipment stopped in 16a. The affected facilities may still
contain gas at this time. Enter the time and date of restart in 16b. The intent with this data is to
capture the total time that the pipeline or facility is shutdown due to the incident. If the pipeline or
facility has not been restarted, select “Still shut down” for Question 15b and then include the restart
time and date in a future Supplemental Report.
A17. Operator Communication with Local, State, or Federal Emergency Responders
In an Advisory Bulletin dated October 11, 2012, PHMSA reminded Operators of the need to
communicate with Emergency Responders in the early stages of a potential Incident. This is
typically accomplished by contacting Public Safety Access Points (PSAPs) along the pipeline route.
The purpose of the communication is to assist in the identification, location, and planning for
response to pipeline Incidents through coordination and information sharing.
A17a. Select Yes if there was communication about the incident. If A12. is “Notification from
Emergency Responder”, A17a. will automatically populate with Yes.
If 17a. is no, skip 17b. and 17c.
A17b. Select the party initiating the communication. If A12. is “Notification from Emergency
Responder”, A17b. will automatically populate with “Local/State/Federal Emergency
Responder”.
A17c. Enter the local date and time of the initial communication. If A12. is “Notification from
Emergency Responder”, A17c. will automatically populate with the value in A13.
A18. What time did Operator resources arrive on site?
Enter the date/time operator responders, company or contract, arrived on site. The time is to be
shown by 24-hour clock notation and reported in the time zone where the incident occurred. (See
“Special Instructions”, numbers 8 and 9.) PHMSA will use this data to calculate incident response
times.
A19. reserved
A20a. Local time (24-hr clock) and date of initial operator report to the National Response
Center
Enter the time and date of the initial Immediate Notice of the incident to the NRC. The time is to
be shown by 24-hour clock notation in the time zone where the incident occurred. All NRC reports
are time stamped for the eastern time zone. Be sure to convert to local time if the incident did not
occur in the eastern time zone. (See “Special Instructions”, numbers 9 and 10.)
A20b. Initial Operator National Response Center (NRC) Report Number
Page 11 of 37
Instructions (rev 1-2020) for Form PHMSA F 7100.2 (rev 1-2020)
INCIDENT REPORT – GAS TRANSMISSION
AND GATHERING SYSTEMS
§191.5 requires that incidents meeting the criteria outlined in §191.3 be reported directly to the 24hour National Response Center (NRC) at 1-800-424-8802 at the earliest practicable moment .
The NRC assigns numbers to each call. Enter the number assigned to the operator’s initial
Immediate Notice (sometimes referred to as the “Telephonic Report”). If a NRC report was not
made, select the option that best describes why: NRC Notification Not Required, NRC Notification
Required But Not Made, Do Not Know NRC Report Number.
A20c. Additional NRC Report Numbers
If the operator made more than one call to the NRC, enter each additional NRC report number.
A21. Did the gas ignite?
Ignite means the released gas caught fire, or a conflagration, detonation or explosion occurred,
even if there was no residual fire after the initial ignition event. If the answer is “Yes,” enter the
time and date of the ignition in 21a. The time is to be shown by 24-hour clock notation in the time
zone where the Incident occurred. If the fire was extinguished, select “Operator/Contractor” or
“Local/State/Federal Emergency Responder,” to indicate who extinguished the fire, or select
“Allowed to Burn Out,” if it was not extinguished, in 21b. Enter the estimated volume of gas
consumed by fire in thousands of standard cubic feet, MCF in 21c.
A21d. Did the gas explode?
Explode means the ignition of the released gas occurred with a sudden and violent release of
energy.
A22. Flow Control
If A14. is “Onshore Pipeline, Including Valve Sites” OR “Offshore Pipeline, Including Riser and
Riser Bend”, answer A22.
The initial response to gas pipeline emergencies is typically understood to be isolation of the
incident location from the source of gas. However, sometimes there are operational means other
than valve closures to achieve this goal. These questions are intended to understand the response
actions and the time of valve closures intended to isolate the incident location. Valve data is for
the first upstream or downstream valve selected by the operator to minimize the release volume but
may not be the closest to the incident site or the one that was eventually used for the final isolation
of the release site for repair.
Upstream of Failure - If an action other than valve closure was taken to isolate the incident site
from the upstream pipeline, select “Operational Control” for 22a and provide a description of the
operation control employed.
If 22a. is “Valve Closure”, complete 22b. and 22c.
A22b. Enter the time of the valve closure that achieved isolation of the incident location from
upstream piping.
Page 12 of 37
Instructions (rev 1-2020) for Form PHMSA F 7100.2 (rev 1-2020)
INCIDENT REPORT – GAS TRANSMISSION
AND GATHERING SYSTEMS
A22c. Identify the type of valve used to initially isolate the release on the upstream side.
Downstream of Failure - If an action other than valve closure was taken to isolate the incident site
from the downstream pipeline, select “Operational Control” for 22d. and provide a description of
the operation control employed.
If 22d. is “Valve Closure”, complete 22e. and 22f.
A22e. Enter the time of the valve closure that achieved isolation of the incident location from
downstream piping.
A22f. Identify the type of valve used to initially isolate the release on the downstream side.
A23. Number of general public evacuated
The number of people evacuated is to be estimated based on operator knowledge, or police, fire
department, or other emergency responder reports. If there was no evacuation involving the general
public, report zero (0).
Page 13 of 37
Instructions (rev 1-2020) for Form PHMSA F 7100.2 (rev 1-2020)
INCIDENT REPORT – GAS TRANSMISSION
AND GATHERING SYSTEMS
PART B – ADDITIONAL LOCATION INFORMATION
B1. Was the origin of the incident onshore?
Populated automatically based on response to A14.
B1a. Pipeline/Facility name
Multiple pipeline systems and/or facilities are often operated by a single operator. This information
identifies the particular pipeline system or pipeline facility name commonly used by the operator
on which the incident occurred, for example, the “West Line 24” Pipeline”, or “Gulf Coast
Pipeline”, or “Wooster Storage Facility”.
B1b. Segment name/ID
Within a given pipeline system and/or facility, there are typically multiple segment or station
identifiers, names, or ID’s which are commonly used by the operator. The information to be
reported here helps locate and/or record the more precise incident location, for example, “Segment
4-32”, or “MP 4.5 to Wayne County Line”, or “Dublin Compressor Station”, or “Witte Reducing
Station”. Consideration should be given to using the same pipeline segment name that was
submitted to NPMS, where appropriate.
If Onshore
B2. – B5. Incident Location
Provide the state, zip code, city, and county/parish in which the incident occurred. If the incident
did not occur within a municipality, select Not Within Municipality in the City field. If the incident
did not occur within county/parish, select Not Within County/Parish.
B6. and B7. Operator-designated location
This is intended to be the designation that the operator would use to identify the location of the
incident on its pipeline system. Enter the appropriate milepost or survey station number. This
designator is intended to allow PHMSA personnel to refer to the physical location of the incident
using the operator’s maps and records.
B8. Was the Incident on Federal Lands other than the Outer Continental Shelf?
Federal Lands other than Outer Continental Shelf means all lands the United States owns, including
military reservations, except lands in National Parks and lands held in trust for Native Americans.
Incidents at Federal buildings, such as Federal Court Houses, Custom Houses, and other Federal
office buildings and warehouses, are NOT to be reported as being on Federal Lands.
Page 14 of 37
Instructions (rev 1-2020) for Form PHMSA F 7100.2 (rev 1-2020)
INCIDENT REPORT – GAS TRANSMISSION
AND GATHERING SYSTEMS
B9. Location of Incident
Operator-controlled Property would normally apply to an operator’s facility, which may or may
not have controlled access, but which is often fenced or otherwise marked with discernible
boundaries. This “operator-controlled property” does not refer to the pipeline right-of-way, which
is a separate choice for this question.
B10. Area of Incident (as found)
This refers to the location on the pipeline system at which gas was released, resulting in the incident.
It does not refer to adjacent locations in which released gas may have accumulated or ignited.
Underground means pipe, components, or other facilities installed below the natural ground level,
road bed, or below the underwater natural bottom.
Under pavement includes under streets, sidewalks, paved roads, driveways, and parking lots.
Exposed due to Excavation means that a normally buried pipeline had been exposed by any party
(operator, operator’s contractor, or third party) preparatory to or as a result of excavation. The
cause of the release, however, may or may not necessarily be related to excavation damage. This
category could include a corrosion leak not previously evidenced by dead vegetation, but found
during an ILI dig, or a release caused by a non-excavation vehicle where contact happened to occur
while the pipeline was exposed for a repair or examination. Natural forces might also damage a
pipeline that happened to be temporarily exposed. In each case, the cause is to be appropriately
reported in PART G of this form.
Exposed due to loss of cover means that erosion, flooding, or some other non-excavation action
has removed the cover that was previously over the pipeline. This loss of cover may be previously
known or unknown by the pipeline operator, but to be reported in this category, the pipeline was
believed to have been exposed prior to the Incident. Loss of cover as a result of the Incident
should not be reported under this category. For example – if a pipeline was buried below
ground immediately prior to a failure, and the force of the failure unearthed the pipeline – it should
still be reported as “Under soil,” for the purposes of this report.
Aboveground means pipe, components, or other facilities that are above the natural grade.
Typical aboveground facility piping includes any pipe or components installed aboveground such
as those at compressor stations, valve sites, launcher and receiver and reducing stations.
Transition area means the junction of differing material or media between pipes, components, or
facilities such as those installed at a belowground-aboveground junction (soil/air interface), another
environmental interface, or in close contact to supporting elements such as those at water crossings,
compressor stations, and gas storage facilities.
If B10. is Underground, answer 10a. and 10b:
B10a. Depth of Cover
Page 15 of 37
Instructions (rev 1-2020) for Form PHMSA F 7100.2 (rev 1-2020)
INCIDENT REPORT – GAS TRANSMISSION
AND GATHERING SYSTEMS
Report the depth of cover in inches immediately before the incident. In cases where the incident
changed the depth of cover, the depth prior to the incident will be an estimate.
B10b. Indicate if other underground facilities were found within 12 inches of the failure location.
B11. Did Incident occur in a crossing?
Use Bridge Crossing if the pipeline is suspended above a body of water or roadway, railroad rightof-way, etc. either on a separately designed pipeline bridge or as a part of or connected to a road,
railroad, or passenger bridge.
Use Railroad Crossing or Road Crossing, as appropriate, if the pipeline is buried beneath rail bed
or road bed.
Use Water Crossing if the pipeline is in the water, beneath the water, in contact with the natural
ground of the lake bed, etc., or buried beneath the bed of a lake, reservoir, stream or creek, whether
the crossing happens to be flowing water at the time of the incident or not. The name of the body
of water is to be provided if it is commonly known and understood among the local population.
(The purpose of this information is to allow persons familiar with the area in which the incident
occurred to identify the location and understand it in its local context. Research to identify names
that are not commonly used is not necessary since such names would not fulfill the intended
purpose. If a body of water does not have a name that is commonly used and understood in the
local area, this field may be left blank).
For Approximate water depth (ft) of the lake, reservoir, etc., estimate the typical water depth at
the location and time of the incident, ignoring seasonal, weather-related, and other factors which
may affect the water depth from time to time.
If B11 is yes, indicate whether the pipe is cased.
If a water crossing, specify the pipe installation method and answer the question about the
length of the crossing.
If Offshore
B12. Approximate water depth (ft.) at the point of the Incident
This is to be the estimated depth from the surface of the water to the seabed at the point of the
incident regardless of whether the pipeline is below/on the bottom, underwater but suspended above
the bottom, or above the surface (e.g., on a platform).
B13. Origin of the Incident
Area and Tract/Block numbers are to be provided for either State or OCS waters, whichever is
applicable.
Page 16 of 37
Instructions (rev 1-2020) for Form PHMSA F 7100.2 (rev 1-2020)
INCIDENT REPORT – GAS TRANSMISSION
AND GATHERING SYSTEMS
For Nearest County/Parish, as with the name of an onshore body of water (see Question 12 above),
the data collected is intended to allow persons familiar with the area in which the incident occurred
to identify the location and understand it in its local context. Accordingly, it is not necessary to
take measurements to determine which county/parish is precisely “nearest” in cases where the
incident location is approximately equidistant from two (or more). In such cases, the name of one
of the nearby counties/parishes is to be provided.
For Incidents on the Outer Continental Shelf (OCS), identify the region where the Incident occurred
by selecting one of the four options listed.
B15. Area of the Incident
For all Offshore Incidents, specify the area of the Incident by selecting the best description of the
location where the Incident occurred.
PART C – ADDITIONAL FACILITY INFORMATION
C1. Is the pipeline or facility [Interstate or Intrastate]?
Interstate gas pipeline facility means a gas pipeline facility or that part of a gas pipeline facility
that is used to transport gas and is subject to the jurisdiction of the Federal Energy Regulatory
Commission (FERC) under the Natural Gas Act (15 U.S.C. 717 et seq.).
Intrastate gas pipeline facility means a gas pipeline facility or that part of a gas pipeline facility
that is used to transport gas within a state and is not subject to the jurisdiction of FERC under the
Natural Gas Act (15 U.S.C. 717 et seq.).
The reported jurisdiction should match both the Annual Report and NPMS submittals for the
pipeline, if applicable.
C2. Material involved in Incident
Enter the material involved in the Incident. If the material is other than Carbon Steel or Plastic,
select “Material other than Carbon Steel or Plastic” and specify the type of material in the space
provided.
C3. Item involved in Incident
Pipe (whether pipe body or pipe seam) means the pipe through which product is transported, not
including auxiliary piping, tubing, or instrumentation.
Nominal Pipe Size. It is the diameter in whole number inches (except for pipe less than 5”) used
to describe the pipe size; for example, 8-5/8” pipe has a nominal pipe size of 8. Decimals are
unnecessary for this measure (except for pipe less than 5”). For more details, see
http://en.wikipedia.org/wiki/Nominal_Pipe_Size
Enter pipe wall thickness in inches. Wall thickness is typically less than an inch. Accordingly,
use three decimal places to report wall thickness: 0.312, 0.281, etc.
Page 17 of 37
Instructions (rev 1-2020) for Form PHMSA F 7100.2 (rev 1-2020)
INCIDENT REPORT – GAS TRANSMISSION
AND GATHERING SYSTEMS
SMYS means specified minimum yield strength and is the yield strength prescribed by the
specification under which the material is purchased from the manufacturer. If the SMYS is
unknown, and the Operator has designated it as 24,000 for the purposes of MAOP calculations,
enter 24,000.
Pipe Specification is the specification to which the pipe was manufactured, such as API 5L or
ASTM A106.
Pipe seam means the longitudinal seam (longitudinal weld) created during manufacture of the joint
of pipe.
Pipe Seam Type Abbreviations
SAW means submerged arc weld
ERW means electric-resistance weld
DSAW means double submerged arc weld
If the frequency of the ERW pipe seam is unknown, and the pipe was manufactured after 1980,
select Longitudinal ERW – High Frequency. Almost all ERW pipe manufactured prior to 1960 is
Low Frequency, and both High and Low Frequency ERW pipe was manufactured between 1960
and 1980.
If differences exist between pipe on either side of a Girth Weld Failure, Populate C3l. through C3r.
as needed.
If the incident occurred on an item not provided in this section, select “Other” and specify the
item that failed in the space provided. Make every effort to find an item category and avoid
the use of “Other” when reporting the Type of Item involved in the Incident.
C4. Year Installed Enter the year the item that failed was installed.
C5. Year Manufactured If you know the year the item that failed was manufactured, enter it.
Otherwise, select Unknown.
C6. Type of release involved (select only one)
Mechanical puncture means a puncture of the pipeline, typically by a piece of equipment such as
would occur if the pipeline were pierced by directional drilling or a backhoe bucket tooth. Not all
excavation-related damage will be a “mechanical puncture.” (Precise measurement of size – e.g.,
using a micrometer – is not needed. Approximate measurements can be provided in inches and one
decimal.)
Leak means a failure resulting in an unintentional release of gas that is often small in size, usually
resulting in a low flow release of low volume, although large volume leaks can and do occur on
occasion. A leak may be a hole or a crack, and includes separation of materials, pullout and loose
connections. Typically, a Leak can be repaired, whereas a Rupture results in the complete failure
of the pipeline.
Page 18 of 37
Instructions (rev 1-2020) for Form PHMSA F 7100.2 (rev 1-2020)
INCIDENT REPORT – GAS TRANSMISSION
AND GATHERING SYSTEMS
Rupture means the pipeline facility has burst, split, or broken and the operation of the pipeline
facility is immediately impaired and no longer serviceable. The terms “circumferential” and
“longitudinal” refer to the general direction or orientation of the rupture relative to the pipe’s axis.
For example; a rupture of a girth weld would be circumferential, whereas a split that followed the
length of the pipe (whether in the seam, or not) would be longitudinal. (Precise measurement of
size – e.g., micrometer – is not needed. Approximate measurements can be provided in inches and
decimals.)
PART D – ADDITIONAL CONSEQUENCE INFORMATION
See 49 CFR § 192.903 for “high consequence area” definition.
D1. Select the Class Location at the point of the failure.
D2. Did this Incident occur in a High Consequence Area (HCA)?
This question is to be answered based on the classification of the involved segment in the operator’s
Integrity Management (IM) Program at the time of the incident.
D2a. Specify the Method used to identify the HCA:
Answer this question only if the incident occurred in an HCA.
As defined in §192.903, HCAs are determined by one of two methods: Method (1) uses class
locations, and Method (2) uses potential impact circles. The operator is to identify the method used
within its IM program to determine that the location at which the incident occurred was an HCA.
D3. What is the PIR (Potential Impact Radius) for the location of this Incident?
An operator is to answer this question for all incidents, regardless of whether or not the incident
occurred in a high consequence area (HCA) or of the method used to identify an HCA. A PIR is
one of the two methods for identifying an HCA, and this question and those immediately following
are intended to collect data from actual incidents as part of a continuing effort to assure that the
definition of a PIR is appropriate for that purpose. If the Incident involved the release of a nonflammable gas, select “Not Flammable.”
PIR is defined in §191.903 as the radius of a circle within which the potential failure of a pipeline
could have significant impact on people or property. PIR is determined by the formula:
________
r = 0.69 * √ p * d2
where: r is the radius of a circular area in feet surrounding the point of failure,
p is the maximum allowable operating pressure (MAOP) in the pipeline
segment in pounds per square inch and
d is the nominal diameter of the pipeline in inches.
Page 19 of 37
Instructions (rev 1-2020) for Form PHMSA F 7100.2 (rev 1-2020)
INCIDENT REPORT – GAS TRANSMISSION
AND GATHERING SYSTEMS
[0.69 is the factor for natural gas. This number will vary for other gases depending upon their heat
of combustion. An operator transporting gas other than natural gas must use Section 3.2 of
ASME/ANSI B31.8S-2001 (Supplement to ASME B31.8; incorporated into the regulations by
reference, see §192.7) to calculate the impact radius formula.]
D4. Were any structures outside the PIR impacted or otherwise damaged by heat/fire
resulting from the Incident?
Report any damage to structures further from the point of failure than the PIR distance that resulted
from heat radiation or fires started as a result of the incident.
D5. Were any structures outside the PIR impacted or otherwise damaged NOT due to
heat/fire resulting from the Incident?
This would include damage by blast effects, impact from flying debris dislodged by a pipeline
rupture, etc.
D6. Were any of the fatalities or injuries reported for persons located outside the PIR?
This refers only to the injuries reported in A11. Do not consider less severe injuries reported in D8.
and D9. The description of the cause of the fatality or injury should be general in nature. For
example; burns, struck by flying debris, smoke inhalation, crushed by falling object, are examples
of causes that could be used to describe the apparent physical cause of the injury or fatality outside
the PIR.
Moderate consequence area (MCA) is defined in 49 CFR Part 192.
D13a. Did the incident occur in an MCA? If yes, complete D13b. by selecting all that were
present within the potential impact radius.
D7. Estimated Property Damage
All relevant costs available at the time of submission must be included on the initial written Incident
Report as well as being updated as needed on Supplemental Reports. This includes (but is not
limited to) costs due to property damage to the operator’s facilities and to the property of others,
facility repair and replacement, and environmental cleanup and damage. Do NOT include cost of
gas lost. Additionally, do NOT include costs incurred for facility repair, replacement, or changes
that are NOT related to the incident and which are typically done solely for convenience. An
example of doing work solely for convenience is working on non-leaking facilities unearthed
because of the incident. Litigation and other legal expenses related to the incident are not
reportable.
Operators are to report costs based on the best estimate available at the time a report is submitted.
It is likely that an estimate of final repair costs may not be available when the initial report must be
submitted (within 30 days, per §191.15). The best available estimate of these costs is to be included
in the initial report. For convenience, this estimate can be revised, if needed, when Supplemental
Page 20 of 37
Instructions (rev 1-2020) for Form PHMSA F 7100.2 (rev 1-2020)
INCIDENT REPORT – GAS TRANSMISSION
AND GATHERING SYSTEMS
Reports are filed for other reasons, however, when no other changes are forthcoming, Supplemental
Reports are to be filed as new cost information becomes available. If Supplemental Reports are not
submitted for other reasons, a Supplemental Report is to be filed for the purpose of updating or
correcting the estimated cost if these costs differ from those already reported by 20 percent or
$20,000, whichever is greater.
D7a. Public and Non-operator private property damage estimates generally include physical
damage to the property of others, the cost of investigation and remediation of a site not owned or
operated by the operator, laboratory costs, third party expenses such as engineers or scientists, and
other reasonable costs, excluding litigation and other legal expenses related to the incident.
D7b. Operator’s property damage & repairs estimates generally include physical damage to the
property of the operator or owner company such as the estimated installed or replacement value of
the damaged pipe, coating, component, materials, or equipment due to the incident, excluding the
cost of any gas lost. Also to be excluded are litigation and other legal expenses related to the
incident.
When estimating the Cost of repairs to company facilities, the standard shall be the cost necessary
to safely restore property to its predefined level of service. Property damage estimates include the
cost to access, secure, excavate, and repair the pipeline using methods, materials, and labor
necessary to re-establish operations at a predetermined level. These costs may include the cost of
repair sleeves or clamps, re-routing of piping, or the removal from service of an appurtenance or
pipeline component. When more comprehensive repairs or improvements are justified but not
required for continued operation, the cost of such repairs or replacement is not attributable to the
incident. Costs associated with improvements to the pipeline or other facilities to mitigate the risk
of future failures are not included.
D7c. Emergency response includes emergency response operations necessary to return the
incident site to a safe state, actions to minimize the volume of gas released, conduct reconnaissance,
and to identify the extent of incident impacts. They include materials, supplies, labor, and benefits.
If you reimbursed local, state, or federal emergency responders, include these amounts. Costs
related to stakeholder outreach, media response, etc. are not to be included.
D7d. Other costs are to include any and all costs which are not included above. Cost of any gas
lost is NOT to be reported here, but is to be reported under Cost of Gas Released. Operators are
to NOT use this category to report any costs which belong in cost categories separately listed above.
Costs are to be reported in only one category and are not to be double-counted. Costs can be split
between two or more categories when they overlap more than one reporting category.
Cost of Gas Released – enter your gas cost, excluding taxes, in dollars per thousand standard cubic
feet (mcf). The cost of gas released will be calculated based on the volumes reported in A7 and
A8.
Page 21 of 37
Instructions (rev 1-2020) for Form PHMSA F 7100.2 (rev 1-2020)
INCIDENT REPORT – GAS TRANSMISSION
AND GATHERING SYSTEMS
Injured persons not included in A11. The number of persons injured, admitted to a hospital,
and remaining in the hospital for at least one overnight are reported in A11. If a person is
included in A11, do not include them in D8.
D8. Estimated number of persons with injuries requiring treatment in a medical facility but not
requiring overnight in-patient hospitalization.
If a person is included in D8, do not include them in D9.
D9. Estimated number of persons with injuries requiring treatment by EMTs at the site of incident.
Buildings Affected The term ‘affected’ means the building was either damaged, or evacuated,
or had gas service interrupted.
D10. Enter the number of residential buildings affected.
D11. Enter the number of commercial and industrial buildings affected.
D12. If wildlife was impacted, select Yes and indicate the type in D12a. Otherwise, select No.
Page 22 of 37
Instructions (rev 1-2020) for Form PHMSA F 7100.2 (rev 1-2020)
INCIDENT REPORT – GAS TRANSMISSION
AND GATHERING SYSTEMS
PART E – ADDITIONAL OPERATING INFORMATION
E1. Estimated Pressure and Flow Rate
Enter the estimated operating pressure, in psig, at the location and time of the incident.
Enter the estimated flow rate in the pipeline segment at the location and time of the Incident.
E2. Maximum Allowable Operating Pressure (MAOP)
Enter the MAOP, in psig, at the point and time of the Incident.
E2a. MAOP Established By
Select the response that describes the basis for establishing the MAOP at the incident site. A
short explanation of each 192.619 option and “Other” is:
§ 192.619
(paragraph)
(a)
(a)(1)
(a)(2)
(a)(3)
(a)(4)
(c)
(d)
Other
Methodology Description
Introduction: Except as specified in (c) and (d), use the lowest MAOP
determined by (a)(1), (a)(2), (a)(3), (a)(4).
Design Pressure
Post-Construction Pressure Test
High Actual Operation Pressure during 5 years preceding July 1, 1970 – this is
NOT the Grandfather Clause
History of Pipe (primarily corrosion and actual operating pressure)
Grandfather Clause – Highest Actual Operating Pressure during 5 years
preceding 1970, even if this MAOP is higher than pressures determined by other
methodologies in (a)
Alternative MAOP (§ 192.620) and Alternative MAOP Special Permits
Use this category if you did not base your MAOP on any of the paragraphs
within § 192.619 or 192.624(c)
E2b. and E2c. Enter the date the MAOP was established and indicate if the MAOP was established
in conjunction with a flow reversal.
E3. Pressure Description
Select the option that describes the relationship among the operating pressure at the point and time
of the incident, the MAOP, and the allowances in §192.201.
E4. Was the system or facility relating to the Incident operating under an established pressure
restriction with pressure limits below those normally allowed by the MAOP ?
Consider both voluntary and mandated pressure restrictions. A pressure restriction is to be
considered mandated by PHMSA or a state regulator if it was required by an Order, enforcement
action, or other formal correspondence from PHMSA.
Page 23 of 37
Instructions (rev 1-2020) for Form PHMSA F 7100.2 (rev 1-2020)
INCIDENT REPORT – GAS TRANSMISSION
AND GATHERING SYSTEMS
An “established pressure restriction” is defined as a temporary reduction in the MAOP that also
requires a revision to the set points in the operator’s safety devices, processes or controls to ensure
the pressure restriction is not exceeded.
Pressure reductions taken by the operator as a result of a procedural or regulatory requirement, e.g.,
pipeline repairs, movement, investigations, or a pressure reduction taken because an anomaly
identified during an IM assessment could not be repaired within the required schedule
(§192.933(d)), are not considered “mandated by PHMSA.”
E5. Odorization Indicate if the gas at the point of failure was required to be odorized. If it was
required, indicate if the odorization was in accordance with §192.615.
If A14. is “Onshore Pipeline, Including Valve Sites” OR “Offshore Pipeline, Including Riser and
Riser Bend”, answer E6 through E8.
E6. Length of segment isolated between valves (ft)
Identify the length in feet between the upstream and downstream shut-off valves closest to the
failure location.
E9. Function of pipeline system
Transmission System means pipelines that are part of a system whose principal purpose is
transmission of gas.
Transmission Line of Distribution System means a pipeline that meets the definition of
“transmission line” in §192.3 but which is operated as part of a distribution pipeline system.
Typically, this includes portions of the distribution pipeline system for which the operating stress
level exceeds 20 percent SMYS.
Type A and Type B Gathering means a pipeline that transports gas from a current production
facility to a transmission line or main and that meets the criteria for either Type A or Type B in
§192.8.
Offshore Gathering means a gas gathering pipeline located offshore.
Transmission in Storage Field means a transmission pipeline that transports gas within a storage
field.
E10. Was a Supervisory Control and Data Acquisition (SCADA)-based system in place on the
pipeline or facility involved in the Incident?
This does not mean a system designed or used exclusively for leak detection.
E10a. Was it operating at the time of the Incident?
Was the SCADA system in operation at the time of the incident?
Page 24 of 37
Instructions (rev 1-2020) for Form PHMSA F 7100.2 (rev 1-2020)
INCIDENT REPORT – GAS TRANSMISSION
AND GATHERING SYSTEMS
E10b. Was it fully functional at the time of the Incident?
Was the SCADA system capable of performing all of its functions, whether or not it
was actually in operation at the time of the incident? If No, describe functions that
were not operational in PART H – Narrative Description of the Incident.
E10c and d. Did SCADA-based information (such as alarm(s), alert(s), event(s),
and/or volume or pack calculations) assist with the initial indication or confirmed
discovery of the Incident?
Select Yes if SCADA-based information was used to confirm the incident even if the
initial report or identification may have come from other sources. Use of SCADA data
for subsequent estimation of amount of gas lost, etc. is not considered use to confirm
the incident.
Select No if SCADA-based information was not used to assist with identification of the
incident.
E11. Was an investigation initiated into whether or not the controller(s) or control room issues
were the cause of or a contributing factor to the Incident?
Select only one of the choices to indicate whether an investigation was/is being conducted (Yes) or
was not conducted (No). If an investigation has been completed, select all the factors that apply in
describing the results of the investigation.
Cause means an action or lack of action that directly led to or resulted in the pipeline incident.
Contributing factor means an action or lack of action that when added to the existing pipeline
circumstances heightened the likelihood of the release or added to the impact of the release.
Controller Error means that the controller failed to identify a circumstance indicative of a release
event, such as an abnormal operating condition, alarm, pressure drop, change in flow rate, or other
similar event.
Incorrect Controller action means that the controller errantly operated the means for controlling
an event. Examples include opening or closing the wrong valve, or hitting the wrong switch or
button.
PART F – DRUG & ALCOHOL TESTING INFORMATION
Requirements for post-incident drug and alcohol tests are in 49 CFR §199.105 and §199.225
respectively. If the incident circumstances were such that tests were not required by these
regulations, and if no tests were conducted, select No. If tests were administered, select Yes and
report separately the number of operator employees and the number of contractors working for the
operator who were tested and the number of each that failed such tests.
Page 25 of 37
Instructions (rev 1-2020) for Form PHMSA F 7100.2 (rev 1-2020)
INCIDENT REPORT – GAS TRANSMISSION
AND GATHERING SYSTEMS
PART G – APPARENT CAUSE
PART G – Apparent Cause
Select the one, single sub-cause listed under sections G1 thru G8 that best describes the apparent
cause of the Incident. These sub-causes are contained in the shaded column on the left under each
main cause category. Answer the corresponding questions that accompany your selected subcause, and enter any secondary, contributing, or root causes of the Incident in PART K –
Contributing Factors. Make every effort to find a category that fits the Incident’s Apparent
Cause and avoid the use of Other and Unknown when possible. Use of Unknown as an
Apparent Cause will require the submittal of a Supplemental Report to revise the Apparent
Cause when it becomes known.
G1 – Corrosion Failure
Corrosion includes a release or failure caused by galvanic, atmospheric, stray current,
microbiological, selective seam, or other corrosive action. A corrosion release or failure is not
limited to a hole in the pipe or other piece of equipment. If the bonnet or packing gland on a valve
or flange on piping deteriorates or becomes loose and leaks due to corrosion and failure of bolts, it
is to be classified as Corrosion. (Note: If the bonnet, packing, or other gasket has deteriorated to
failure, whether before or after the end of its expected life, but not due to corrosive action, it is to
be classified under G6 - Equipment Failure.)
External Corrosion
2. Type of corrosion – NOTE: Stress Corrosion Cracking (SCC) is no longer an option for the
type of corrosion. SCC failures are to be reported under cause G5, with a sub-cause of
Environmental Cracking-related.
If Stray Current corrosion is selected, specify whether alternating or direct current was involved
and describe the source of the stray current.
4a. Under cathodic protection means cathodic protection in accordance with §192.455,
§192.457, and §192.463. Recognizing that older pipelines may have had cathodic protection added
over a number of years, provide an estimate if the exact year cathodic protection started is unknown.
Internal Corrosion
9. Location of corrosion
A low point in pipe includes portions of the pipe contour in which water might settle out. This
includes, but is not limited to, the low point of vertical bends at a crossing of a foreign line or
road/railroad, etc., an elbow, a drop out or low point drain.
10. Was the gas/fluid treated with corrosion inhibitors or biocides?
Page 26 of 37
Instructions (rev 1-2020) for Form PHMSA F 7100.2 (rev 1-2020)
INCIDENT REPORT – GAS TRANSMISSION
AND GATHERING SYSTEMS
Select Yes if corrosion inhibitors or biocides were included in the gas/fluid transported.
12. Were cleaning/dewatering pigs (or other operations) routinely utilized?
13. Were corrosion coupons routinely utilized?
For purposes of these Questions 12 and 13, “routinely” refers to an action that is performed on more
than a sporadic or one-time basis as part of a regular program with the intent to ensure that water
build-up and/or settling and internal corrosion do not occur.
G2 – Natural Force Damage
Natural Force Damage includes a release or failure resulting from earth movement, earthquakes,
landslides, subsidence, lightning, heavy rains/floods, washouts, flotation, mudslide, scouring,
temperature, frost heave, frozen components, high winds, or similar natural causes.
Earth Movement NOT due to Heavy Rains/Floods refers to incidents caused by land shifts such
as earthquakes, landslides, or subsidence, but not mudslides which are presumed to be initiated by
heavy rains or floods.
Heavy Rains/Floods refer to all water-related natural force causes. While mudslides involve earth
movement, report them here since typically they are an effect of heavy rains or floods.
Lightning includes both damage and/or fire caused by a direct lighting strike and damage and/or
fire as a secondary effect from a lightning strike in the area. An example of such a secondary effect
would be a forest fire started by lightning that results in damage to a pipeline system asset which
results in an incident.
Temperature includes weather-related temperature and thermal stress effects, either heat or cold,
where temperature was the initiating cause.
Thermal stress refers to mechanical stress induced in a pipe or component when
some or all of its parts are not free to expand or contract in response to changes
in temperature.
Frozen components would include incidents where components are inoperable
because of freezing and those due to cracking of a piece of equipment due to
expansion of water during a freeze cycle.
High Winds includes damage caused by wind-induced forces. Select this category if the damage
is due to the force of the wind itself. Damage caused by impact from objects blown by wind would
be reported under G4 - Other Outside Force Damage.
Tree/Vegetation Root includes damages caused by tree and vegetation roots.
Page 27 of 37
Instructions (rev 1-2020) for Form PHMSA F 7100.2 (rev 1-2020)
INCIDENT REPORT – GAS TRANSMISSION
AND GATHERING SYSTEMS
Snow/Ice impact or Accumulation should be indicated when snow and/or ice caused damage to
the gas transmission and gathering system asset which results in an incident.
Other Natural Force Damage. Select this sub-cause for types of Natural Force Damage not
included otherwise, and describe in the space provided. If necessary, provide additional explanation
in PART H – Narrative Description of the Incident.
Answer Questions 6 and 6.a if the incident occurred in conjunction with an extreme weather event
such as a hurricane, tropical storm, or tornado. If an extreme weather event related to something
other than a hurricane, tropical storm, or tornado was involved, indicate Other and describe the
event in the space provided.
G3 – Excavation Damage
Excavation Damage includes a release or failure resulting directly from excavation damage by
operator's personnel (oftentimes referred to as “first party” excavation damage) or by the operator’s
contractor (oftentimes referred to as “second party” excavation damage) or by people or contractors
not associated with the operator (oftentimes referred to as “third party” excavation damage). Also,
this section includes a release or failure determined to have resulted from previous damage due to
excavation activity. For damage from outside forces OTHER than excavation which results in a
release, use G2 - Natural Force Damage or G4 - Other Outside Force, as appropriate. Also, for a
strike, physical contact, or other damage to a pipeline or facility that apparently was NOT related
to excavation and that results in a delayed or eventual release, report the incident under G4 as
“Previous Mechanical Damage NOT related to Excavation.”
Excavation Damage by Operator (First Party) refers to incidents caused as a result of excavation
by a direct employee of the operator.
Excavation Damage by Operator’s Contractor (Second Party) refers to incidents caused as a
result of excavation by the operator’s contractor or agent or other party working for the operator.
Excavation Damage by Third Party refers to incidents caused by excavation damage resulting
from actions by personnel or other third parties not working for or acting on behalf of the operator
or its agent.
Previous Damage due to Excavation Activity refers to incidents that were apparently caused by
prior excavation activity and that then resulted in a delayed or eventual release. Indications of prior
excavation activity might come from the condition of the pipe when it is examined, or from records
of excavation at the site, or through metallurgical analysis or other inspection and/or testing
methods. Dents and gouges in the 10:00-to-2:00 o’clock positions on the pipe, for instance, may
indicate an earlier strike, as might marks from the bucket or tracks of an earth moving machine or
similar pieces of equipment.
Page 28 of 37
Instructions (rev 1-2020) for Form PHMSA F 7100.2 (rev 1-2020)
INCIDENT REPORT – GAS TRANSMISSION
AND GATHERING SYSTEMS
If Excavation Damage by Third Party is selected, answer question 1
1. and 1a. Prior Notification Indicate whether you received prior notification of the excavation
activity. If yes, indicate all of the notification sources.
1b. through 1d. One-Call State Law Exemptions Per the primary Incident Investigator results,
indicate whether State law exempted the excavator from notifying a one-call center. If yes, select
the type of exemption from the list. If “Other” is selected, enter text describing the exemption.
Describe the exempting authority and exempting criteria.
2. – 12. Complete these questions for any excavation damage sub-cause. Instructions for
answering these questions can be found at CGA’s web site,
https://www.damagereporting.org/dr/control/userGuide.do.
NOTE: If you have or will be reporting the information in questions 2 thru 12 to CGA-DIRT,
select “No” in question 2 to avoid duplication of data submitted to CGA.
G4 – Other Outside Force Damage
Other Outside Force Damage includes, but is not limited to, a release or failure resulting from
non-excavation-related outside forces, such as nearby industrial, man-made, or other fire or
explosion; damage by vehicles or other equipment; failures due to mechanical damage; and,
intentional damage including vandalism and terrorism.
Nearby Industrial, Man-made or other Fire/Explosion as Primary Cause of Incident applies
to situations where the fire occurred before - and caused - the release. (See also the discussion of
“secondary ignition” under the General Instructions.) Examples of such an incident would be an
explosion or fire that originated at a neighboring facility or installation (chemical plant, tank farm,
or other industrial facility) or structure, debris, or brush/trees that results in a release at the
operator’s pipeline or facility. This includes forest, brush, or ground fires that are caused by human
activity. If the fire, however, is known to have been started as a result of a lightning strike, the
incident’s cause is to be classified under G2 - Natural Force Damage. Arson events directed at
harming the pipeline or the operator are to be reported as G4 - Intentional Damage (see below).
Damage by Car, Truck, or Other Motorized Vehicle/Equipment NOT Engaged in Excavation.
An example of this sub-cause would be a stopple tee that releases gas when damaged by a pickup
truck maneuvering near the pipeline. Other motorized vehicles or equipment include tractors,
backhoes, bulldozers and other tracked vehicles, and heavy equipment that can move. Include
under this sub-cause incidents caused by vehicles operated by the pipeline operator, the pipeline
operator’s contractor, or a third party and specify the vehicle/equipment operator’s affiliation from
one of these three groups. Pipeline incidents resulting from vehicular traffic loading or other
contact are to also be reported in this category. If the activity that caused the incident involved
digging, drilling, boring, blasting, grading, cultivation or similar excavation activities, report under
G3 - Excavation Damage.
Page 29 of 37
Instructions (rev 1-2020) for Form PHMSA F 7100.2 (rev 1-2020)
INCIDENT REPORT – GAS TRANSMISSION
AND GATHERING SYSTEMS
Damage by Boats, Barges, Drilling Rigs, or Other Maritime Equipment or Vessels Set Adrift
or Which Have Otherwise Lost Their Mooring. This sub-cause includes impacts by maritime
equipment or vessels (including their anchors or anchor chains or other attached equipment) that
have lost their moorings and are carried into the pipeline facility by the current. This sub-cause
also includes maritime equipment or vessels set adrift as a result of severe weather events and
carried into the pipeline facility by waves, currents, or high winds. In such cases, also indicate the
type of severe weather event. Do NOT report in this sub-cause incidents which are caused by the
impact of maritime equipment or vessels while they are engaged in their normal or routine activities;
such incidents are to be reported as “Routine or Normal Fishing or Other Maritime Activity NOT
Engaged in Excavation” under this section G4 (see below) so long as those activities are not
excavation activities. If those activities are excavation activities such as dredging or bank
stabilization or renewal, the incident is to be reported under G3 - Excavation Damage.
Routine or Normal Fishing or Other Maritime Activity NOT Engaged in Excavation. This
sub-cause includes incidents due to shrimping, purse seining, dredging, oil drilling, or oilfield
workover rigs, including anchor strikes, and other routine or normal maritime-related activities
UNLESS: the movement of the maritime asset was inadvertent and due to a severe weather event
(this type of incident is to be reported under “Damage by Boats, Barges, Drilling Rigs, or Other
Maritime Equipment or Vessels Set Adrift or Which Have Otherwise Lost Their Mooring” in this
section G4); or, the incident was caused by excavation activity such as dredging of waterways or
bodies of water (this type of incident is to be reported under G3 - Excavation Damage).
Electrical Arcing from Other Equipment or Facility such as a pole transformer or adjacent
facility’s electrical equipment.
Previous Mechanical Damage NOT Related to Excavation. This sub-cause covers incidents
where damage occurred at some time prior to the release that was apparently NOT related to
excavation activities, and would include prior outside force damage of an unknown nature, prior
natural force damage, prior damage from other outside forces, and any other previous mechanical
damage other than that which was apparently related to prior excavation. Incidents resulting from
previous damage sustained during construction, installation, or fabrication of the pipe or weld from
which the release eventually occurred are to be reported under G5 - Material Failure of Pipe or
Weld. (See this sub-cause for typical indications of previous construction, installation, or
fabrication damage.) Incidents resulting from previous damage sustained as a result of excavation
activities should be reported under G3 – Previous Damage due to Excavation Activity. (See this
sub-cause for typical indications of prior excavation activity.)
Intentional Damage
Vandalism means willful or malicious destruction of the operator’s pipeline facility or
equipment. This category would include arson, pranks, systematic damage inflicted to
harass the operator, motor vehicle damage that was inflicted intentionally, and a variety
of other intentional acts. (See also the discussion of “secondary ignition” under the
General Instructions.)
Page 30 of 37
Instructions (rev 1-2020) for Form PHMSA F 7100.2 (rev 1-2020)
INCIDENT REPORT – GAS TRANSMISSION
AND GATHERING SYSTEMS
Terrorism, per 28 CFR §0.85 General Functions, includes the unlawful use of force
and violence against persons or property to intimidate or coerce a government, the
civilian population, or any segment thereof, in furtherance of political or social
objectives. Operators selecting this item are encouraged to also notify the FBI.
Theft of commodity or Theft of equipment means damage by any individual or entity,
by any mechanism, specifically to steal, or attempt to steal, the transported gas or
pipeline equipment.
Other Describe in the space provided and, if necessary, provide additional explanation
in PART H – Narrative Description of the Incident.
Other Outside Force Damage. Select this sub-cause for types of Other Outside Force Damage
not included otherwise, and describe in the space provided. If necessary, provide additional
explanation in PART H – Narrative Description of the Incident.
5 – 11 Additional Data for Damage by Car, Truck, or Other Motorized Vehicle/Equipment
NOT Engaged in Excavation
When answering the questions, include information that can be substantiated from police reports or
other investigative reports.
The following definitions apply for reporting the type of motorized vehicle in Question 10:
Motorcycle/All-Terrain Vehicle (ATV) - All two or three-wheeled motorized vehicles, and some
four-wheeled vehicles are to be reported in this category. Typical vehicles in this category have
saddle type seats and are steered by handlebars rather than steering wheels. This category includes
motorcycles, motor scooters, mopeds, motor-powered bicycles, and three-wheel motorcycles.
Additionally, four-wheeled off-road and all-terrain vehicles (sometimes referred to as “fourwheelers”) are to be reported under this category.
Passenger Car -- All sedans, coupes, and station wagons manufactured primarily for the purpose
of carrying passengers and including those passenger cars pulling recreational or other light
trailers.
Small Truck - All two-axle, four-tire, vehicles, other than passenger cars. Included in this
classification are pickups, panels, vans, and other vehicles such as campers, motor homes,
ambulances, hearses, carryalls, and minibuses.
Bus - All vehicles manufactured as traditional passenger-carrying buses with two axles and six
tires or three or more axles. This category includes only traditional buses (including school buses)
functioning as passenger-carrying vehicles. Modified buses should be considered to be a truck
and should be appropriately classified.
Large Truck - All vehicles on a single frame including trucks, camping and recreational vehicles,
motor homes, etc., with two or more axles and at least two rear wheels on each side
Page 31 of 37
Instructions (rev 1-2020) for Form PHMSA F 7100.2 (rev 1-2020)
INCIDENT REPORT – GAS TRANSMISSION
AND GATHERING SYSTEMS
When specifying the type of protection in Question 13; select the category “Barricades” for Jersey
barriers, fencing, and other structures that are other than Guard Rails or Bollards/Guard Posts. If
“Other” is selected, enter text describing the protection.
G5 – Material Failure of Pipe or Weld
Use this section to report material failures only if “Item Involved in Incident” (PART C, Question
3) is “Pipe” (whether “Pipe Body” or “Pipe Seam”) or “Weld.” Indicate how the sub-cause was
determined or if the sub-cause is still being investigated.
This section includes releases in or failures from defects or anomalies within the material of the
pipe body or within the pipe seam or other weld due to manufacturing processes, material
imperfections, defects resulting from poor construction, installation, or fabrication practices, and
in-service stresses such as vibration, fatigue, and environmental cracking.
Design-, Construction-, Installation-, or Fabrication-related includes a release or failure caused
by improper design practices, a dent, gouge, excessive stress, or some other defect or anomaly
introduced during the process of constructing, installing, or fabricating pipe and pipe welds in the
field, including welding or other activities performed at the construction job site. Included are
releases from or failures of wrinkle bends, field welds, and damage sustained in transportation to
the construction or fabrication site. Not included are failures due to seam defects, which are to be
reported as Original Manufacturing-related (see below). If a river crossing were directionally
drilled and tied into a buried pipeline without adequate accommodation for expansion and
contraction of the pipe in the drill hole and the pipeline facility fails at the tie-in, this represents an
improper design practice. Select “Design-, Construction-, Installation-, or Fabrication-related” as
the sub-cause.
Original Manufacturing-related (NOT girth welds or other welds formed in the field) includes
a release or failure caused by a defect or anomaly introduced during the process of manufacturing
pipe, including manufacturing and handling of the plate materials, seam defects and defects in the
pipe body. This option is not appropriate for wrinkle bends, field welds, girth welds, or other joints
fabricated in the field. Use this option for failures such as those due to defects of the longitudinal
weld or inclusions in the pipe body. If the girth welds were completed at the pipe mill (such as in
the case of double joints welded prior to delivery to the jobsite) report those failures in this category.
Environmental Cracking-related includes failures by Stress Corrosion Cracking, Sulfide Stress
Cracking, Hydrogen Stress Cracking, Hard Spots or other environmental cracking mechanisms.
If Design-, Construction-, Installation-, or Fabrication-related, or Original Manufacturingrelated is selected, then select any contributing factors. Examples of Mechanical Stress include
failures related to overburden or loss of support.
5. Post-construction Pressure Test
If you know the post-construction pressure test value, enter it in psig.
“Unknown.”
Page 32 of 37
Otherwise, select
Instructions (rev 1-2020) for Form PHMSA F 7100.2 (rev 1-2020)
INCIDENT REPORT – GAS TRANSMISSION
AND GATHERING SYSTEMS
G6 – Equipment Failure
This section applies to failures of items other than “Pipe” (“Pipe Body” or “Pipe Seam”) or
“Weld”.
Equipment Failure includes a release or failure resulting from: malfunction of control/relief
equipment including valves, regulators, or other instrumentation; failures of compressors, or
compressor-related equipment; failures of various types of connectors, connections, and
appurtenances; failures of the body of equipment, vessel plate, or other material (including those
caused by construction-, installation-, or fabrication-related and original manufacturing-related
defects or anomalies); and, all other equipment-related failures.
Malfunction of Control/Relief Equipment. Examples of this type of incident cause include:
overpressurization resulting from malfunction of a control or alarm device; malfunction of a relief
valve; valves failing to open or close on command; or valves which opened or closed when not
commanded to do so. If overpressurization or some other aspect of this incident was caused by
incorrect operation involving human error, the incident is to be reported under G7 - Incorrect
Operation.
ESD System Failure means failure of an emergency shutdown system.
Other Equipment Failure. Select this sub-cause for types of Equipment Failure not included
otherwise, and describe in the space provided. If necessary, provide additional explanation in
PART H – Narrative Description of the Incident.
G7 – Incorrect Operation
Incorrect Operation includes a release or failure resulting from operating, maintenance, repair, or
other errors by facility personnel or pipeline controllers, including, but not limited to improper valve
selection or operation, inadvertent overpressurization, or improper selection or installation of
equipment in the field. If the failure occurs in the pipe body or weld, and is a result of inadequate
design or a design error, the Incident is to be reported under G5 – Material Failure of Pipe or Weld,
Design-, Construction-, Installation-, or Fabrication-related.
Other Incorrect Operation. Select this sub-cause for types of Incorrect Operation not included
otherwise, and describe in the space provided. If necessary, provide additional explanation in
PART H – Narrative Description of the Incident.
G8 – Other Incident Cause
This section is provided for incidents whose cause is currently unknown, or where investigation
into the cause has been exhausted and the final judgment as to the cause remains unknown, or where
a cause has been determined which does not fit into any of the main cause categories listed in
sections G1 thru G7. PHMSA will review all G-8 cause selections and determine if it meets the
definition of any category listed in G1 thru G7 before a Final Report is accepted for closure. All
Page 33 of 37
Instructions (rev 1-2020) for Form PHMSA F 7100.2 (rev 1-2020)
INCIDENT REPORT – GAS TRANSMISSION
AND GATHERING SYSTEMS
sub cause categories of “Unknown” require a Supplemental Report to be filed before being
accepted as Final.
If the incident cause is known but doesn’t fit into any category in sections G1 thru G7, select
Miscellaneous and enter a description of the incident cause, continuing with a more thorough
explanation in PART H - Narrative Description of the Incident.
If the incident cause is unknown at the time of filing this report, select Unknown in this section
and specify one reason from the accompanying two choices. Once the operator’s investigation into
the incident cause is completed, the operator is to file a Supplemental Report as soon as practicable
either reporting the apparent cause or stating definitively that the cause remains Unknown, along
with any other new, updated, and/or corrected information pertaining to the incident. This
Supplemental Report is to include all new, updated, and/or corrected information pertaining to all
portions of the report form known at this time, and not only that information related to the apparent
cause.
Important Note: Whether the investigation is completed or not, or if the cause continues to be
unknown, Supplemental Reports are to be filed reflecting new, updated, and/or corrected
information as and when this information becomes available. In those cases in which
investigations are ongoing for an extended period of time, operators are to file a Supplemental
Report within one year of their last report for the incident even in those instances where no new,
updated, and/or corrected information has been obtained, with an explanation that the cause remains
under investigation in PART H – Narrative Description of Incident. Additionally, final
determination of the apparent cause and/or closure of the investigation does NOT preclude the need
for the operator’s filing of additional Supplemental Reports as and when new, updated, and/or
corrected information becomes available.
Page 34 of 37
Instructions (rev 1-2020) for Form PHMSA F 7100.2 (rev 1-2020)
INCIDENT REPORT – GAS TRANSMISSION
AND GATHERING SYSTEMS
PART J – INTEGRITY INSPECTIONS
Complete the following if the “Item Involved in Accident” (from PART C, Question 3) is Pipe
or Weld and the “Cause” (from Part G) is:
Corrosion (any subCause in Part G1); or
Previous Damage due to Excavation Activity (subCause in Part G3); or
Previous Mechanical Damage NOT Related to Excavation (subCause in Part G4); or
Material Failure of Pipe or Weld (any subCause in Part G5)
J1. Internal Inspection Tools
If Yes, for each tool and technology used, select type of internal inspection tool and technology,
and indicate year of most recent and previous runs.
Axial Magnetic Flux Leakage (MFL) is an in-line inspection (ILI) tool that uses a non-destructive
testing (NDT) method of imposing a magnetic flux in the steel pipe for the detection of corrosion
and pitting. The basic principle behind MFL ILI involves magnetizing the steel pipe to a saturation
level with a magnetic field. MFL ILI tools can be either low- and high-resolution tools, with more
modern tools being high-resolution MFL ILI tools.
Circumferential/Transverse Wave Magnetic Flux Leakage (MFL) is an in-line inspection (ILI)
tool that induces the magnetic flux field into the steel pipe in the circumferential direction, which
allows the measurement of longitudinally oriented anomalies such as tunnel corrosion and
longitudinal weld anomalies.
Ultrasonic is an in-line inspection (ILI) tool that introduces a shear wave ultrasound beam into the
steel pipeline inspection area at an angle, which allows detection of abnormalities based on the
reflection and refraction of the beam. Can be used to detect and size planar (crack and crack-like)
anomalies or measure wall thickness and detect instances of wall loss.
Geometry/Deformation is an in-line inspection (ILI) tool designed to record mechanical or
geometric conditions such as changes in the pipe internal diameter, including dents, ovalities,
wrinkles, expansions, and misalignments.
Electromagnetic Acoustic Transducer (EMAT) is an in-line inspection (ILI) tool that generates
an ultrasonic pulse within the steel pipe without a liquid couplant. EMAT ILI consists of a magnet
and an electrical coil, which uses electro-magnetic forces to introduce sound energy into the steel
pipe. EMAT ILI is used to detect cracking flaws in steel pipe.
Cathodic Protection Current Measurement (CPCM) is an in-line inspection (ILI) tool capable
of reading and recording the magnitude and polarity of current supplied by cathodic protection
(CP). CPCM ILI measures direct current (DC) and alternating current (AC) voltage gradients from
CP current or induced AC as the CPCM ILI tool traverses along the pipeline.
Page 35 of 37
Instructions (rev 1-2020) for Form PHMSA F 7100.2 (rev 1-2020)
INCIDENT REPORT – GAS TRANSMISSION
AND GATHERING SYSTEMS
Complete J1b. only when the “Cause” (from Part G) is:
Previous Damage due to Excavation Activity (subCause in Part G3); or
Previous Mechanical Damage NOT Related to Excavation (subCause in Part G4)
J1b. Indicate if you have reason to believe the internal inspections were completed before the
damage was sustained.
J2. Hydrotest Has one or more hydrotest or other pressure test been conducted since original
construction at the point of the Incident?
Information from the initial post-construction hydrostatic test is NOT reported in J2.
J3. Direct Assessment (DA) Has Direct Assessment been conducted on this segment?
This refers to direct assessment as defined in §192.903. Instances in which one or more indirect
monitoring tools (e.g., close interval survey, DCVG) have been used that might be used as part of
direct assessment but which have not been used as part of the direct assessment process defined in
§192.903 do NOT constitute a Direct Assessment for purposes of this question.
If J3. is yes, enter the year of the most recent assessment(s) in J3a.
J4. Non-destructive Examination
Indicate if one or more non-destructive examination been conducted prior to the Incident at the
point of the Incident since January 1, 2002. If Yes, enter the most recent year of the examination(s)
in J4a.
PART K – CONTRIBUTING FACTORS
Contributing factor means an action or lack of action that when added to the existing
circumstances heightened the likelihood of the release or added to the impact of the release. The
Apparent Cause of the accident is contained in Part G. Do not report the Apparent Cause again in
this Part K. If Contributing Factors were identified, select all that apply and explain each in the
Narrative.
PART H – NARRATIVE DESCRIPTION OF THE INCIDENT
Concisely describe the incident, including the facts, circumstances, and conditions that may have
contributed directly or indirectly to causing the incident. Include secondary, contributing, or root
causes when possible, or any other factors associated with the cause that are deemed pertinent. Use
this section to clarify or explain unusual conditions, and to explain any estimated data.
If you selected Miscellaneous in section G8, the narrative is to describe the incident in detail,
including all known or suspected causes and possible contributing factors.
Page 36 of 37
Instructions (rev 1-2020) for Form PHMSA F 7100.2 (rev 1-2020)
INCIDENT REPORT – GAS TRANSMISSION
AND GATHERING SYSTEMS
PART I – PREPARER AND AUTHORIZED PERSON
The Preparer is the person who compiled the data and prepared the responses to the report and who
is to be contacted for more information (preferably the person most knowledgeable about the
information in the report or who knows how to contact the person or persons most knowledgeable).
Enter the Preparer’s e-mail address if the Preparer has one, and the phone and fax numbers used by
the Preparer.
The Authorized Person is responsible for assuring the accuracy and completeness of the reported
data. In addition to their title, a phone number and email address are to be provided for the
Authorized Person.
Page 37 of 37
| File Type | application/pdf |
| File Title | INSTRUCTIONS FOR FORM PHMSA F 7100.2 (Rev. 06-2011) INCIDENT REPORT – GAS TRANSMISSION AND GATHERING SYSTEMS |
| Author | PHMSA |
| File Modified | 2021-05-14 |
| File Created | 2021-05-14 |