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pdfNOTICE: This report is required by 49 CFR Part 191. Failure to report can result in a civil penalty not to exceed
$100,000 for each violation for each day that such violation persists except that the maximum civil penalty shall not
exceed $1,000,000 as provided in 49 USC 60122.
OMB NO: 2137-0522
EXPIRATION DATE: 01/31/2013
Report Date
INCIDENT REPORT – GAS TRANSMISSION AND
GATHERING PIPELINE SYSTEMS
U.S. Department of Transportation
Pipeline and Hazardous Materials
Safety Administration
No.
(DOT Use Only)
A federal agency may not conduct or sponsor, and a person is not required to respond to, nor shall a person be subject to a penalty for failure
to comply with a collection of information subject to the requirements of the Paperwork Reduction Act unless that collection of information
displays a current valid OMB Control Number. The OMB Control Number for this information collection is 2137-0522. Public reporting for this
collection of information is estimated to be approximately 10 hours per response, including the time for reviewing instructions, gathering the
data needed, and completing and reviewing the collection of information. All responses to this collection of information are mandatory. Send
comments regarding this burden estimate or any other aspect of this collection of information, including suggestions for reducing this burden to:
Information Collection Clearance Officer, PHMSA, Office of Pipeline Safety (PHP-30) 1200 New Jersey Avenue, SE, Washington, D.C. 20590.
INSTRUCTIONS
Important:
Please read the separate instructions for completing this form before you begin. They clarify the
information requested and provide specific examples. If you do not have a copy of the instructions, you can obtain
one from the PHMSA Pipeline Safety Community Web Page at http://www.phmsa.dot.gov/pipeline.
PART A – KEY REPORT INFORMATION
Original
**Report Type: (select all that apply)
**1. Operator’s OPS-issued Operator Identification Number (OPID):
/
/
/
/
/
Supplemental
Final
/
**2. Name of Operator: ______________________________________________________________________________________
**3. Address of Operator:
3.a _______________________________________________________________________
(Street Address)
3.b ___________________________________________________
(City)
3.c State: /
/
/
3.d Zip Code: /
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/ - /
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/
**4. Local time (24-hr clock) and date of the Incident:
/
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/
/
Hour
/
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/
Month
**5. Location of Incident:
Latitude:
/ / / . / /
Longitude: - / / / / . /
/
**6. National Response Center Report Number:
/
Day
/
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/
/
Year
**7. Local time (24-hr clock) and date of initial telephonic report to the
National Response Center (if applicable):
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Hour
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Month
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Day
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Year
**8. Incident resulted from:
Unintentional release of gas
Intentional release of gas
Reasons other than release of gas
**9. Gas released: (select only one, based on predominant volume released)
Natural Gas
Propane Gas
Synthetic Gas
Hydrogen Gas
Other Gas
Name:
**10. Estimated volume of gas released unintentionally:
/
/
/,/
/
/
/ Thousand Cubic Feet (MCF)
**11. Estimated volume of intentional and controlled release/blowdown :
/
/
/,/
/
/
/ Thousand Cubic Feet (MCF)
**12. Estimated volume of accompanying liquid released:
/
/
/,/
/
/
/ Barrels
Form PHMSA F 7100.2 (Rev. 01-2010 )
Page 1 of 20
Reproduction of this form is permitted
**13. Were there fatalities? Yes No
If Yes, specify the number in each category:
Yes No
**14. Were there injuries requiring inpatient hospitalization?
If Yes, specify the number in each category:
13.a Operator employees
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/
14.a Operator employees
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13.b Contractor employees
working for the Operator
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14.b Contractor employees
working for the Operator
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13.c Non-Operator
emergency responders
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14.c Non-Operator
emergency responders
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13.d Workers working on the
right-of-way, but NOT
associated with this Operator
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14.d Workers working on the
right-of-way, but NOT
associated with this Operator
13.e General public
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14.e General public
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/
13.f Total fatalities (sum of above)
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14.f Total injuries (sum of above)
/
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/
/
**15. Was the pipeline/facility shut down due to the incident?
Yes No Explain: ______________________________________________________________________________
If Yes, complete Questions 15.a and 15.b: (use local time, 24-hr clock)
15.a Local time and date of shutdown
/
/
/
/
/
/
Hour
15.b Local time pipeline/facility restarted
/
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/
Hour
**16. Did the gas ignite?
Yes
No
**17. Did the gas explode?
Yes
No
18. Number of general public evacuated: /
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/,/
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/
Month
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Month
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Day
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Year
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Day
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Still shut down*
(*Supplemental Report required)
Year
/
19. Time sequence: (use local time, 24-hour clock)
19.a Local time operator identified Incident
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Hour
19.b Local time operator resources arrived on site
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Hour
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Month
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Day
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Month
Form PHMSA F 7100.2 (Rev. 01-2010 )
/
Day
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Year
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Year
Page 2 of 20
Reproduction of this form is permitted
PART B – ADDITIONAL LOCATION INFORMATION
**1. Was the origin of the Incident onshore?
Yes (Complete Questions 2-12)
No
(Complete Questions 13-15)
If Onshore:
If Offshore:
**2. State: /
/
/
**3. Zip Code: /
/
13. Approximate water depth (ft.) at the point of the Incident:
/
/
**4 ______________________
/
/ - /
/
/
/
**5______________________
City
/
/
County or Parish
/
/
/
**14. Origin of Incident:
6. Operator designated location: (select only one)
Milepost/Valve Station (specify in shaded area below)
Survey Station No.
/,/
In State waters
Specify: State: / / /
Area: ___________________
Block/Tract #: /___/___/___/___/
(specify in shaded area below)
Nearest County/Parish: ________________
/___/___/___/___/___/___/___/___/___/___/___/___/___/
7. Pipeline/Facility name: ________________________________
Block #: /___/___/___/___/
8. Segment name/ID: ___________________________________
9. Was Incident on Federal land, other than the Outer Continental
Yes No
Shelf (OCS)?
**10. Location of Incident: (select only one)
Operator-controlled property
Pipeline right-of-way
On the Outer Continental Shelf (OCS)
Specify: Area: ___________________
15. Area of Incident: (select only one)
Shoreline/Bank crossing or shore approach
Below water, pipe buried or jetted below seabed
Below water, pipe on or above seabed
Splash Zone of riser
Portion of riser outside of Splash Zone, including riser bend
Platform
**11. Area of Incident (as found): (select only one)
Belowground storage or aboveground storage vessel,
including attached appurtenances
Underground Specify: Under soil
Under a building
Under pavement
Exposed due to excavation
In underground enclosed space (e.g., vault)
Other ____________________________
Depth-of-Cover (in): / /,/
Aboveground Specify:
/
/
/
Typical aboveground facility piping or appurtenance
Overhead crossing
In or spanning an open ditch
Inside a building
O Inside other enclosed space
O Other ____________________________
Transition Area Specify: Soil/air interface Wall
sleeve Pipe support or other close contact area
Other ____________________________
**12. Did Incident occur in a crossing?
If Yes, specify type below:
Bridge crossing Specify:
Yes
No
Cased Uncased
(select all that apply)
Uncased
Bored/drilled
(select all that apply)
Uncased
Bored/drilled
Railroad crossing
Cased
Road crossing
Cased
Water crossing
Specify: Cased
Uncased
Name of body of water, if commonly known:
_____________________________________
Approx. water depth (ft) at the point of the Incident:
/
/,/
/
/
/
(select only one of the following)
Shoreline/Bank crossing
Below water, pipe in bored/drilled crossing
Below water, pipe buried below bottom (NOT in
bored/drilled crossing)
Below water, pipe on or above bottom
Form PHMSA F 7100.2 (Rev. 01-2010 )
Page 3 of 20
Reproduction of this form is permitted
PART C – ADDITIONAL FACILITY INFORMATION
**1. Is the pipeline or facility:
Interstate
Intrastate
**2. Part of system involved in Incident: (select only one)
Belowground Storage, Including Associated Equipment and Piping
Aboveground Storage, Including Associated Equipment and Piping
Onshore Compressor Station Equipment and Piping
Onshore Regulator/Metering Station Equipment and Piping
Onshore Pipeline, Including Valve Sites
Offshore Platform, Including Platform-mounted Equipment and Piping
Offshore Pipeline, Including Riser and Riser Bend
**3. Item involved in Incident: (select only one)
Pipe
Specify:
Pipe Body
Pipe Seam
**3.a Nominal diameter of pipe (in):
3.b Wall thickness (in):
/
/./
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/./
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/
3.c SMYS (Specified Minimum Yield Strength) of pipe (psi):
/
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/,/
/
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/
3.d Pipe specification: _____________________________
**3.e Pipe Seam
Specify: Longitudinal ERW - High Frequency
Longitudinal ERW - Low Frequency
Longitudinal ERW – Unknown Frequency
Spiral Welded ERW
Spiral Welded SAW
Lap Welded
Seamless
Single SAW
DSAW
Flash Welded
Continuous Welded
Furnace Butt Welded
Spiral Welded DSAW
Other ________________________
3.f Pipe manufacturer: _______________________________
3.g Year of manufacture: /
/
/
/
/
**3.h Pipeline coating type at point of Incident
Fusion Bonded Epoxy
Specify:
Coal Tar
Asphalt
Polyolefin
Extruded Polyethylene Field Applied Epoxy Cold Applied Tape Paint
Composite
None
Other _______________________________
Weld, including heat-affected zone Specify: Pipe Girth Weld Other Butt Weld Fillet Weld Other_____________
Valve
Mainline Specify: Butterfly Check Gate Plug Ball Globe
Other __________________________
3.i Mainline valve manufacturer:
3.j Year of manufacture: /
/
/
/
/
Relief Valve
Auxiliary or Other Valve
Compressor
Meter
Scraper/Pig Trap
Separator/Separator Filter
Strainer/Filter
Dehydrator/Drier/Treater
Regulator/Control Valve
Drip/Drip Collection Device
Pulsation Bottle
Cooler
Repair Sleeve or Clamp
Hot Tap Equipment
Stopple Fitting
Flange
Relief Line
Auxiliary Piping (e.g. drain lines)
Tubing
Instrumentation
Underground Gas Storage or Cavern
Pressure Vessel
Other ___________________________________
4. Year item involved in Incident was installed:
/
/
/
/
/
Form PHMSA F 7100.2 (Rev. 01-2010 )
Page 4 of 20
Reproduction of this form is permitted
**5. Material involved in Incident: (select only one)
Carbon Steel
Plastic
Material other than Carbon Steel or Plastic
Specify: ____________________________________________
6. Type of Incident involved: (select only one)
Mechanical Puncture
Approx. size: /__/__/__/__/./__/in. (axial) by /__/__/__/__/./__/in. (circumferential)
Pinhole
Crack
Rupture Select Orientation: Circumferential
Leak
Select Type:
Connection Failure
Seal or Packing
Other
Longitudinal
Other ________________________________
Approx. size: /__/__/__/__/./__/ in. (widest opening) by /__/__/__/__/__/./__/in. (length circumferentially or axially)
Other Describe: ___________________________________________________________________
Form PHMSA F 7100.2 (Rev. 01-2010 )
Page 5 of 20
Reproduction of this form is permitted
PART D – ADDITIONAL CONSEQUENCE INFORMATION
**1. Class Location of Incident: (select only one)
Class 1 Location
Class 2 Location
Class 3 Location
Class 4 Location
**2. Did this Incident occur in a High Consequence Area (HCA)?
No
Yes 2.a Specify the Method used to identify the HCA:
Method 1
**3. What is the PIR (Potential Impact Radius) for the location of this Incident?
/
/,/
Method 2
/
/
/ feet
4. Were any structures outside the PIR impacted or otherwise damaged by heat/fire resulting from the Incident?
5. Were any structures outside the PIR impacted or otherwise damaged NOT by heat/fire resulting from the Incident?
6. Were any of the fatalities or injuries reported for persons located outside the PIR?
Yes
Yes
Yes
No
No
No
**7. Estimated cost to Operator:
7.a Estimated cost of public and non-Operator private property damage
paid/reimbursed by the Operator
$/
/
/
/,/
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/,/
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/
7.b Estimated cost of gas released unintentionally
$/
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7.c Estimated cost of gas released during
intentional and controlled blowdown
$/
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7.d Estimated cost of Operator’s property damage & repairs
$/
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7.e Estimated cost of Operator’s emergency response
$/
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7.f Estimated other costs
$/
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/,/
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/,/
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/
Describe ___________________________________________________
7.g Estimated total costs (sum of above)
$/
/
Form PHMSA F 7100.2 (Rev. 01-2010 )
Page 6 of 20
Reproduction of this form is permitted
PART E – ADDITIONAL OPERATING INFORMATION
**1. Estimated pressure at the point and time of the Incident (psig):
/
/
/,/
/
/
/
**2. Maximum Allowable Operating Pressure (MAOP) at the point and time of the Incident (psig) :
/
/
/,/
/
/
/
**3. Describe the pressure on the system or facility relating to the Incident: (select only one)
Pressure did not exceed MAOP
Pressure exceeded MAOP, but did not exceed 110% of MAOP
Pressure exceeded 110% of MAOP
**4. Not including pressure reductions required by PHMSA regulations (such as for repairs and pipe movement), 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 ?
No
Yes (Complete 4.a and 4.b below)
4.a Did the pressure exceed this established pressure restriction?
Yes
No
4.b Was this pressure restriction mandated by PHMSA or the State?
PHMSA
State
Not mandated
**5. Was “Onshore Pipeline, Including Valve Sites” OR “Offshore Pipeline, Including Riser and Riser Bend” selected in PART C, Question 2?
No
Yes
(Complete 5.a – 5.f below)
Manual
**5.a Type of upstream valve used to initially isolate release source:
Manual Automatic
Check Valve
**5.b Type of downstream valve used to initially isolate release source:
**5.c Length of segment isolated between valves (ft):
/
/
/
Automatic
/,/
/
/
Remotely Controlled
Remotely Controlled
/
5.d Is the pipeline configured to accommodate internal inspection tools?
Yes
No Which physical features limit tool accommodation? (select all that apply)
Changes in line pipe diameter
Presence of unsuitable mainline valves
Tight or mitered pipe bends
Other passage restrictions (i.e. unbarred tee’s, projecting instrumentation, etc.)
Extra thick pipe wall (applicable only for magnetic flux leakage internal inspection tools)
Other Describe:__________________________________________________________________
5.e For this pipeline, are there operational factors which significantly complicate the execution of an internal inspection tool run?
No
Yes
Which operational factors complicate execution?
(select all that apply)
Excessive debris or scale, wax, or other wall build-up
Low operating pressure(s)
Low flow or absence of flow
Incompatible commodity
Other Describe:__________________________________________________________________
**5.f Function of pipeline system: (select only one)
Transmission System
Type A Gathering
Storage Gathering
Transmission Line of Distribution System
Type B Gathering
Form PHMSA F 7100.2 (Rev. 01-2010 )
Page 7 of 20
Reproduction of this form is permitted
6. Was a Supervisory Control and Data Acquisition (SCADA)-based system in place on the pipeline or facility involved in the Incident?
No
Yes 6.a Was it operating at the time of the Incident?
Yes
No
6.b Was it fully functional at the time of the Incident?
Yes
No
6.c Did SCADA-based information (such as alarm(s), alert(s), event(s), and/or volume or pack calculations) assist with
Yes
No
the detection of the Incident?
6.d Did SCADA-based information (such as alarm(s), alert(s), event(s), and/or volume calculations) assist with the
Yes
No
confirmation of the Incident?
7. How was the Incident initially identified for the Operator? (select only one)
SCADA-based information (such as alarm(s), alert(s), event(s), and/or volume or pack calculations)
Static Shut-in Test or Other Pressure or Leak Test
Controller
Local Operating Personnel, including contractors
Air Patrol
Ground Patrol by Operator or its contractor
Notification from Public
Notification from Emergency Responder
Notification from Third Party that caused the Incident
Other _________________________________________________
7.a If “Controller”, “Local Operating Personnel, including contractors”, “Air Patrol”, or “Ground Patrol by Operator or its contractor” is
selected in Question 7, specify the following: (select only one)
Operator employee
Contractor working for the Operator
8. 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)
Yes, but the investigation of the control room and/or controller actions has not yet been completed by the operator (Supplemental
Report required)
No, the facility was not monitored by a controller(s) at the time of the Incident
No, the operator did not find that an investigation of the controller(s) actions or control room issues was necessary due to:
(provide an explanation for why the operator did not investigate)
__________________________________________________________________________________________________________
__________________________________________________________________________________________________________
__________________________________________________________________________________________________________
Yes, specify investigation result(s): (select all that apply)
Investigation reviewed work schedule rotations, continuous hours of service (while working for the Operator) and other
factors associated with fatigue
Investigation did NOT review work schedule rotations, continuous hours of service (while working for the Operator) and
other factors associated with fatigue (provide an explanation for why not)
_____________________________________________________________________________________________________
_____________________________________________________________________________________________________
_____________________________________________________________________________________________________
Investigation identified no control room issues
Investigation identified no controller issues
Investigation identified incorrect controller action or controller error
Investigation identified that fatigue may have affected the controller(s) involved or impacted the involved controller(s)
response
Investigation identified incorrect procedures
Investigation identified incorrect control room equipment operation
Investigation identified maintenance activities that affected control room operations, procedures, and/or controller
response
Investigation identified areas other than those above Describe: ___________________________________________
_____________________________________________________________________________________________________
_____________________________________________________________________________________________________
_____________________________________________________________________________________________________
Form PHMSA F 7100.2 (Rev. 01-2010 )
Page 8 of 20
Reproduction of this form is permitted
PART F – DRUG & ALCOHOL TESTING INFORMATION
**1. As a result of this Incident, were any Operator employees tested under the post-accident drug and alcohol testing requirements of DOT’s
Drug & Alcohol Testing regulations?
No
Yes
1.a Specify how many were tested:
/
/
/
1.b Specify how many failed:
/
/
/
**2. As a result of this Incident, were any Operator contractor employees tested under the post-accident drug and alcohol testing requirements
of DOT’s Drug & Alcohol Testing regulations?
No
Yes
2.a Specify how many were tested:
2.b
Specify how many failed:
/
/
/
/
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/
Form PHMSA F 7100.2 (Rev. 01-2010 )
Page 9 of 20
Reproduction of this form is permitted
PART G – APPARENT CAUSE
Select only one box from PART G in the shaded column on the left representing the
APPARENT Cause of the Incident, and answer the questions on the right. Describe
secondary, contributing, or root causes of the Incident in the narrative (PART H).
G1 - Corrosion Failure – **only one sub-cause can be picked from shaded left-hand column
External Corrosion
**1. Results of visual examination:
Localized Pitting General Corrosion
Other _____________________________________________________________
2. Type of corrosion: (select all that apply)
Galvanic Atmospheric Stray Current Microbiological Selective Seam
Other _____________________________________________________________
3. The type(s) of corrosion selected in Question 2 is based on the following: (select all that
apply)
Field examination
Determined by metallurgical analysis
Other _____________________________________________________________
**4. Was the failed item buried under the ground?
Yes 4.a Was failed item considered to be under cathodic protection at the time of
the incident?
Yes Year protection started: / / / / /
No
4.b Was shielding, tenting, or disbonding of coating evident at the point of
the incident?
Yes No
4.c Has one or more Cathodic Protection Survey been conducted at
the point of the incident?
Yes, CP Annual Survey Most recent year conducted:
/ / /
Yes, Close Interval Survey Most recent year conducted:
Yes, Other CP Survey Most recent year conducted:
No
No
4.d Was the failed item externally coated or painted?
/
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/
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/
/
/
/
/
/
Yes No
**5. Was there observable damage to the coating or paint in the vicinity of the corrosion?
Yes No
Internal Corrosion
**6. Results of visual examination:
Localized Pitting
General Corrosion
Not cut open
Other ____________________________________________________________
7. Cause of corrosion: (select all that apply)
Corrosive Commodity Water drop-out/Acid Microbiological Erosion
Other ____________ ________________________________________________
8. The cause(s) of corrosion selected in Question 7 is based on the following: (select all that
apply)
Field examination
Determined by metallurgical analysis
Other _____________________________________________________________
9. Location of corrosion: (select all that apply)
Low point in pipe Elbow Drop-out
Other ____________________________________________________________
**10. Was the gas/fluid treated with corrosion inhibitors or biocides?
**11. Was the interior coated or lined with protective coating?
Yes No
Yes No
**12. Were cleaning/dewatering pigs (or other operations) routinely utilized?
Not applicable - Not mainline pipe
Yes
No
**13. Were corrosion coupons routinely utilized?
Not applicable - Not mainline pipe
Yes
Form PHMSA F 7100.2 (Rev. 01-2010 )
No
Page 10 of 20
Reproduction of this form is permitted
Complete the following if any Corrosion Failure sub-cause is selected AND the “Item Involved in Incident” (from PART C, Question 3) is
Pipe or Weld.
**14. Has one or more internal inspection tool collected data at the point of the Incident?
Yes No
14.a. If Yes, for each tool used, select type of internal inspection tool and indicate most recent year run:
Magnetic Flux Leakage Tool
Ultrasonic
Geometry
Caliper
Crack
Hard Spot
Combination Tool
Transverse Field/Triaxial
Other __________________________
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**15. Has one or more hydrotest or other pressure test been conducted since original construction at the point of the Incident?
Yes Most recent year tested: / / / / /
Test pressure (psig): /
/
/
/
/
/
No
**16. Has one or more Direct Assessment been conducted on this segment?
Yes, and an investigative dig was conducted at the point of the Incident
Yes, but the point of the Incident was not identified as a dig site
No
Most recent year conducted: /
/
/
/
/
Most recent year conducted: /
/
/
/
/
17. Has one or more non-destructive examination been conducted at the point of the Incident since January 21, 2002?
Yes No
17.a If Yes, for each examination conducted since January 1, 2002, select type of non-destructive examination and indicate most recent
year the examination was conducted:
Radiography
Guided Wave Ultrasonic
Handheld Ultrasonic Tool
Wet Magnetic Particle Test
Dry Magnetic Particle Test
Other __________________________
/
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G2 - Natural Force Damage - **only one sub-cause can be picked from shaded left-hand column
Earth Movement, NOT due to
Heavy Rains/Floods
**1. Specify:
Earthquake Subsidence Landslide
Other __________________
Heavy Rains/Floods
2. Specify:
Washout/Scouring Flotation Mudslide Other _______________
Lightning
3. Specify:
Direct hit Secondary impact such as resulting nearby fires
Temperature
**4. Specify:
High Winds
Other Natural Force Damage
Thermal Stress
Frozen Components
Frost Heave
Other ________________________________
**5. Describe: _________________________________________________
Complete the following if any Natural Force Damage sub-cause is selected.
**6. Were the natural forces causing the Incident generated in conjunction with an extreme weather event?
6.a If Yes, specify: (select all that apply)
Yes
No
Hurricane Tropical Storm
Tornado
Other ______________________________
Form PHMSA F 7100.2 (Rev. 01-2010 )
Page 11 of 20
Reproduction of this form is permitted
G3 – Excavation Damage - **only one sub-cause can be picked from shaded left-hand column
Excavation Damage by Operator
(First Party)
Excavation Damage by Operator’s
Contractor (Second Party)
Excavation Damage by Third Party
Previous Damage due to Excavation
Activity
Complete Questions 1-5 ONLY IF the “Item Involved in Incident” (from PART C,
Question 3) is Pipe or Weld.
**1. Has one or more internal inspection tool collected data at the point of the Incident?
Yes No
1.a If Yes, for each tool used, select type of internal inspection tool and indicate most
recent year run:
Magnetic Flux Leakage
Ultrasonic
Geometry
Caliper
Crack
Hard Spot
Combination Tool
Transverse Field/Triaxial
Other _____________________
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2. Do you have reason to believe that the internal inspection was completed BEFORE the
damage was sustained? Yes No
**3. Has one or more hydrotest or other pressure test been conducted since original
construction at the point of the Incident?
Yes Most recent year tested:
Test pressure (psig):
/
/
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/
/
/, /
/
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/
/
/
No
**4. Has one or more Direct Assessment been conducted on the pipeline segment?
Yes, and an investigative dig was conducted at the point of the Incident
Most recent year conducted: / / / / /
Yes, but the point of the Incident was not identified as a dig site
Most recent year conducted: / / / / /
No
5. Has one or more non-destructive examination been conducted at the point of the Incident
since January 1, 2002?
Yes No
5.a If Yes, for each examination conducted since January 1, 2002, select type of nondestructive examination and indicate most recent year the examination was conducted:
Radiography
Guided Wave Ultrasonic
Handheld Ultrasonic Tool
Wet Magnetic Particle Test
Dry Magnetic Particle Test
Other __________________________
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Complete the following if Excavation Damage by Third Party is selected as the sub-cause.
**6. Did the operator get prior notification of the excavation activity?
6.a If Yes, Notification received from: (select all that apply)
Yes No
One-Call System
Excavator
Form PHMSA F 7100.2 (Rev. 01-2010 )
Contractor
Landowner
Page 12 of 20
Reproduction of this form is permitted
Complete the following mandatory CGA-DIRT Program questions if any Excavation Damage sub-cause is selected.
Yes
**7. Do you want PHMSA to upload the following information to CGA-DIRT (www.cga-dirt.com)?
No
**8. Right-of-Way where event occurred: (select all that apply)
Public Specify: City Street State Highway County Road Interstate Highway
Private Specify: Private Landowner Private Business Private Easement
Pipeline Property/Easement
Power/Transmission Line
Railroad
Dedicated Public Utility Easement
Federal Land
Data not collected
Unknown/Other
Other
**9. Type of excavator: (select only one)
Contractor
Railroad
County
State
Developer
Utility
Farmer
Municipality
Data not collected
Occupant
Unknown/Other
**10. Type of excavation equipment: (select only one)
Auger
Explosives
Probing Device
Backhoe/Trackhoe
Farm Equipment
Trencher
Boring
Grader/Scraper
Vacuum Equipment
Drilling
Directional Drilling
Hand Tools
Milling Equipment
Data not collected Unknown/Other
**11. Type of work performed: (select only one)
Agriculture
Drainage
Grading
Natural Gas
Sewer (Sanitary/Storm)
Telecommunications
Data not collected
Cable TV
Curb/Sidewalk
Driveway
Electric
Irrigation
Landscaping
Pole
Public Transit Authority
Site Development
Steam
Traffic Signal
Traffic Sign
Unknown/Other
**12. Was the One-Call Center notified?
Yes
12.a If Yes, specify ticket number: /
/
Building Construction
Engineering/Surveying
Liquid Pipeline
Railroad Maintenance
Storm Drain/Culvert
Water
Building Demolition
Fencing
Milling
Road Work
Street Light
Waterway Improvement
No
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12.b If this is a State where more than a single One-Call Center exists, list the name of the One-Call Center notified:
_____________________________________________________________
Contract Locator
Data not collected
Unknown/Other
**14. Were facility locate marks visible in the area of excavation?
No
Yes
Data not collected
Unknown/Other
15. Were facilities marked correctly?
No
Yes
Data not collected
Unknown/Other
**16. Did the damage cause an interruption in service?
No
Yes
Data not collected
Unknown/Other
**13. Type of Locator:
Utility Owner
16.a If Yes, specify duration of the interruption:
/___/___/___/___/ hours
(This CGA-DIRT section continued on next page with Question 17.)
Form PHMSA F 7100.2 (Rev. 01-2010 )
Page 13 of 20
Reproduction of this form is permitted
17. Description of the CGA-DIRT Root Cause (select only the one predominant first level CGA-DIRT Root Cause and then, where available
as a choice, the one predominant second level CGA-DIRT Root Cause as well):
One-Call Notification Practices Not Sufficient: (select only one)
No notification made to the One-Call Center
Notification to One-Call Center made, but not sufficient
Wrong information provided
Locating Practices Not Sufficient: (select only one)
Facility could not be found/located
Facility marking or location not sufficient
Facility was not located or marked
Incorrect facility records/maps
Excavation Practices Not Sufficient: (select only one)
Excavation practices not sufficient (other)
Failure to maintain clearance
Failure to maintain the marks
Failure to support exposed facilities
Failure to use hand tools where required
Failure to verify location by test-hole (pot-holing)
Improper backfilling
One-Call Notification Center Error
Abandoned Facility
Deteriorated Facility
Previous Damage
Data Not Collected
Other / None of the Above (explain)____________________________________________________________________
____________________________________________________________________________________________________
____________________________________________________________________________________________________
____________________________________________________________________________________________________
Form PHMSA F 7100.2 (Rev. 01-2010 )
Page 14 of 20
Reproduction of this form is permitted
G4 - Other Outside Force Damage - **only one sub-cause can be picked from shaded left-hand column
Nearby Industrial, Man-made, or
Other Fire/Explosion as Primary
Cause of Incident
Damage by Car, Truck, or Other
Motorized Vehicle/Equipment NOT
Engaged in Excavation
**1. Vehicle/Equipment operated by: (select only one)
Operator
Operator’s Contractor
Damage by Boats, Barges, Drilling
Rigs, or Other Maritime Equipment or
Vessels Set Adrift or Which Have
Otherwise Lost Their Mooring
**2. Select one or more of the following IF an extreme weather event was a factor:
Hurricane
Tropical Storm
Tornado
Heavy Rains/Flood
Other ______________________________
Routine or Normal Fishing or Other
Maritime Activity NOT Engaged in
Excavation
Electrical Arcing from Other
Equipment or Facility
Previous Mechanical Damage NOT
Related to Excavation
Third Party
Complete Questions 3-7 ONLY IF the “Item Involved in Incident” (from PART C,
Question 3) is Pipe or Weld.
**3. Has one or more internal inspection tool collected data at the point of the Incident?
Yes No
3.a If Yes, for each tool used, select type of internal inspection tool and indicate most
recent year run:
Magnetic Flux Leakage
Ultrasonic
Geometry
Caliper
Crack
Hard Spot
Combination Tool
Transverse Field/Triaxial
Other
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4. Do you have reason to believe that the internal inspection was completed BEFORE the
damage was sustained? Yes No
**5. Has one or more hydrotest or other pressure test been conducted since original
construction at the point of the Incident?
Yes Most recent year tested:
Test pressure (psig):
/
/
/
/
/
/,/
/
/
/
/
/
No
**6. Has one or more Direct Assessment been conducted on the pipeline segment?
Yes, and an investigative dig was conducted at the point of the Incident
Most recent year conducted: / / / / /
Yes, but the point of the Incident was not identified as a dig site
Most recent year conducted: / / / / /
No
(This section continued on next page with Question 7.)
Form PHMSA F 7100.2 (Rev. 01-2010 )
Page 15 of 20
Reproduction of this form is permitted
7. Has one or more non-destructive examination been conducted at the point of the Incident
since January 1, 2002?
Yes No
7.a If Yes, for each examination conducted since January 1, 2002, select type of nondestructive examination and indicate most recent year the examination was conducted:
Radiography
/
/
/
/
/
Guided Wave Ultrasonic
Handheld Ultrasonic Tool
Wet Magnetic Particle Test
Dry Magnetic Particle Test
Other __________________________
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Intentional Damage
8. Specify:
Other Outside Force Damage
**9. Describe: _________________________________________________________
Vandalism
Terrorism
Theft of transported commodity Theft of equipment
Other ________________________________________
Form PHMSA F 7100.2 (Rev. 01-2010 )
Page 16 of 20
Reproduction of this form is permitted
Use this section to report material failures ONLY IF the “Item Involved in
Incident” (from PART C, Question 3) is “Pipe” or “Weld.”
G5 - Material Failure of Pipe or Weld
**Only one sub-cause can be picked from shaded left-hand column
**1. The sub-cause selected below is based on the following: (select all that apply)
Field Examination
Determined by Metallurgical Analysis
Other Analysis__________________________
Sub-cause is Tentative or Suspected; Still Under Investigation
Construction-, Installation-, or
Fabrication-related
Original Manufacturing-related
(NOT girth weld or other welds
formed in the field)
Environmental Cracking-related
(Supplemental Report required)
2. List contributing factors: (select all that apply)
Fatigue- or Vibration-related:
Mechanically-induced prior to installation (such as during transport of pipe)
Mechanical Vibration
Pressure-related
Thermal
Other __________________________________
Mechanical Stress
Other __________________________________
3. Specify: Stress Corrosion Cracking
Sulfide Stress Cracking
Hydrogen Stress Cracking
Other ____________________________________
Complete the following if any Material Failure of Pipe or Weld sub-cause is selected.
4. Additional factors (select all that apply): Dent Gouge Pipe Bend
Lamination
Buckle
Wrinkle
Misalignment
Other __________________________________
Arc Burn Crack
Burnt Steel
**5. Has one or more internal inspection tool collected data at the point of the Incident?
Lack of Fusion
Yes No
5.a If Yes, for each tool used, select type of internal inspection tool and indicate most recent year run:
Magnetic Flux Leakage Tool
Ultrasonic
Geometry
Caliper
Crack
Hard Spot
Combination Tool
Transverse Field/Triaxial
Other __________________________
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**6. Has one or more hydrotest or other pressure test been conducted since original construction at the point of the Incident?
Yes Most recent year tested: / / / / /
Test pressure (psig): /
/
/,/
/
/
/
No
**7. Has one or more Direct Assessment been conducted on the pipeline segment?
Yes, and an investigative dig was conducted at the point of the Incident Most recent year conducted:
Yes, but the point of the incident was not identified as a dig site
No
Most recent year conducted:
/
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/
8. Has one or more non-destructive examination(s) been conducted at the point of the Incident since January 1,2002?
Yes No
8.a If Yes, for each examination conducted since January 1, 2002, select type of non-destructive examination and indicate most recent
year the examination was conducted:
Radiography
Guided Wave Ultrasonic
Handheld Ultrasonic Tool
Wet Magnetic Particle Test
Dry Magnetic Particle Test
Other ________________________________
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Form PHMSA F 7100.2 (Rev. 01-2010 )
Page 17 of 20
Reproduction of this form is permitted
G6 - Equipment Failure - **only one sub-cause can be picked from shaded left-hand column
Malfunction of Control/Relief
Equipment
**1. Specify: (select all that apply)
Control Valve
Instrumentation
SCADA
Communications Block Valve
Check Valve
Relief Valve
Power Failure
Stopple/Control Fitting
Pressure Regulator
ESD System Failure
Other ________________________________________________________
Compressor or Compressor-related
Equipment
**2. Specify: Seal/Packing Failure
Body Failure
Crack in Body
Appurtenance Failure
Pressure Vessel Failure
Other _______________________________________________________
Threaded Connection/Coupling
Failure
**3. Specify:
Pipe Nipple
Valve Threads
Mechanical Coupling
Threaded Pipe Collar Threaded Fitting
Other _______________________________________________________
Non-threaded Connection Failure
**4. Specify:
O-Ring Gasket
Seal (NOT compressor seal) or Packing
Other_______________________________________________________
Defective or Loose Tubing or Fitting
Failure of Equipment Body (except
Compressor), Vessel Plate, or other
Material
Other Equipment Failure
**5. Describe: ___________________________________________________________
_______________________________________________________________________
Complete the following if any Equipment Failure sub-cause is selected.
6. Additional factors that contributed to the equipment failure: (select all that apply)
Excessive vibration
Overpressurization
No support or loss of support
Manufacturing defect
Loss of electricity
Improper installation
Mismatched items (different manufacturer for tubing and tubing fittings)
Dissimilar metals
Breakdown of soft goods due to compatibility issues with transported gas/fluid
Valve vault or valve can contributed to the release
Alarm/status failure
Misalignment
Thermal stress
Other _______________________________________________________
Form PHMSA F 7100.2 (Rev. 01-2010 )
Page 18 of 20
Reproduction of this form is permitted
G7 - Incorrect Operation - **only one sub-cause can be picked from shaded left-hand column
Damage by Operator or Operator’s
Contractor NOT Related to
Excavation and NOT due to
Motorized Vehicle/Equipment
Damage
Underground Gas Storage, Pressure
Vessel, or Cavern Allowed or
Caused to Overpressure
Valve Left or Placed in Wrong
Position, but NOT Resulting in an
Overpressure
1. Specify:
Valve Misalignment
Incorrect Reference Data/Calculation
Miscommunication
Inadequate Monitoring
Other ____________________________________
Pipeline or Equipment
Overpressured
Equipment Not Installed Properly
Wrong Equipment Specified or
Installed
Other Incorrect Operation
**2. Describe: __________________________________________________
Complete the following if any Incorrect Operation sub-cause is selected.
3. Was this Incident related to: (select all that apply)
Inadequate procedure
No procedure established
Failure to follow procedure
Other: ______________________________________________________
**4. What category type was the activity that caused the Incident:
Construction
Commissioning
Decommissioning
Right-of-Way activities
Routine maintenance
Other maintenance
Normal operating conditions
Non-routine operating conditions (abnormal operations or emergencies)
5. Was the task(s) that led to the Incident identified as a covered task in your Operator Qualification Program? Yes
No
5.a If Yes, were the individuals performing the task(s) qualified for the task(s)?
Yes, they were qualified for the task(s)
No, but they were performing the task(s) under the direction and observation of a qualified individual
No, they were not qualified for the task(s) nor were they performing the task(s) under the direction and observation of a
qualified individual
G8 – Other Incident Cause - only one sub-cause can be picked from shaded left-hand column
Miscellaneous
Unknown
**1. Describe:
___________________________________________________________________________
___________________________________________________________________________
**2. Specify:
Investigation complete, cause of Incident unknown
Still under investigation, cause of Incident to be determined*
(*Supplemental Report required)
Form PHMSA F 7100.2 (Rev. 01-2010 )
Page 19 of 20
Reproduction of this form is permitted
PART H – NARRATIVE DESCRIPTION OF THE INCIDENT
(Attach additional sheets as necessary)
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
**PART I – PREPARER AND AUTHORIZED SIGNATURE
Preparer's Name (type or print)
Preparer’s Telephone Number
Preparer's Title (type or print)
Preparer's E-mail Address
Authorized Signature
Preparer’s Facsimile Number
Date
Authorized Signature Telephone Number
Authorized Signature’s Name (type or print)
Authorized Signature’s E-mail Address
Authorized Signature’s Title (type or print)
Form PHMSA F 7100.2 (Rev. 01-2010 )
Page 20 of 20
Reproduction of this form is permitted
INSTRUCTIONS FOR FORM PHMSA F 7100.2 (Rev. 01-2010)
INCIDENT REPORT – GAS TRANSMISSION AND GATHERING
SYSTEMS
GENERAL INSTRUCTIONS
Each gas transmission or gathering system operator 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 the incident. Requirements for submitting reports are in §191.7.
Release of gas, for the purpose of maintenance or other routine activities, need not be
reported if the only reportable criterion is loss of gas of $50,000 or more as described in 49
CFR §191.3 under "Incident" (1)(ii). Damage from secondary ignition need not be
reported unless the damage to facilities subject to Part 191 exceeds $50,000. Secondary
ignition is a fire where the origin is unrelated to the gas facilities, such as electrical fires,
arson, etc, that subsequently damages gas facilities and causes a gas fire.
If you need copies of Form PHMSA F 7100.2 and/or instructions they can be found on the
Pipeline Safety Community main page, http://phmsa.dot.gov/pipeline, by clicking the
Forms hyperlink and scrolling down to the section entitled PHMSA/OPS Forms
(accidents/incidents/annuals). If you have questions about this report or these instructions,
please call (202) 366-8075. Please type or print all entries when submitting forms by mail
or Fax.
§191.3 Definitions.
*
*
*
*
*
Incident means any of the following events:
(1) An event that involves a release of gas from a pipeline or of liquefied
natural gas or gas from an LNG facility and
(i) A death, or personal injury necessitating in-patient hospitalization;
or
(ii) Estimated property damage, including cost of gas lost, of the
operator or others, or both, of $50,000 or more.
(2) An event that results in an emergency shutdown of an LNG facility.
(3) An event that is significant, in the judgment of the operator, even though it
did not meet the criteria of paragraphs (1) or (2).
Instructions:
Incident Report – Gas Transmission & Gathering Systems
Form PHMSA F 7100.2 (Rev. 01-2010)
Page 1 of 27
§191.5 Telephonic notice of certain incidents.
(a) At the earliest practicable moment following discovery, each operator shall
give notice in accordance with paragraph (b) of this section of each incident as defined
in §191.3.
(b) Each notice required by paragraph (a) of this section shall be made by
telephone to 800-424-8802(in Washington, DC, 267-2675) and shall include the
following information:
(1) Names of operator and person making report and their telephone
numbers.
(2) The location of the incident.
(3) The time of the incident.
(4) The number of fatalities and personal injuries, if any.
(5) All other significant facts that are known by the operator that are
relevant to the cause of the incident or extent of the damages.
§ 191.15 Transmission and gathering systems: Incident report.
(a) Except as provided in paragraph (c) of this section, each operator of a
transmission or a gathering pipeline system shall submit Department of
Transportation Form RSPA 1 F 7100.2 as soon as practicable but not more than 30
days after detection of an incident required to be reported under Sec. 191.5.
(b) Where additional related information is obtained after a report is submitted
under paragraph (a) of this section, the operator shall make a supplemental report as
soon as practicable with a clear reference by date and subject to the original report.
(c) The incident report required by paragraph (a) of this section need not be
submitted with respect to LNG facilities.
REPORTING METHODS
1
RSPA, the Research and Special Projects Administration, was a predecessor agency to PHMSA. The
revised form is now designated PHMSA F 7100.2. This reference will be changed in the Code of Federal
Regulations by rulemaking.
Instructions:
Incident Report – Gas Transmission & Gathering Systems
Form PHMSA F 7100.2 (Rev. 01-2010)
Page 2 of 27
Use one of the following methods to submit your report. We prefer online reporting
over hardcopy submissions. If you prefer, you can mail or fax your completed reports to
DOT/PHMSA.
1. Online:
a. Navigate to the ONLINE DATA ENTRY SYSTEM at
http://opsweb.phmsa.dot.gov/ and click on the Incident Report – Gas Transmission
& Gathering Systems link
b. Enter Operator ID and PIN (the name that appears is the operator name assigned to
the operator ID and PIN and is automatically populated by our database and
cannot be changed by the operator at the time of filing).
c. Click “add” to begin
d. Click “submit” when finished. NOTE: For supplemental reports use steps 1a and
1b then click on the report ID to make corrections. Click “save” when finished.
e. A confirmation page will appear for you to print and save for your records
If you submit your report online, PLEASE DO NOT MAIL OR FAX the
completed report to DOT as this may result in duplicate entries.
2. Mail to:
DOT/PHMSA Office of Pipeline Safety
Information Resources Manager,
1200 New Jersey Ave., SE
East Building, 2nd Floor, (PHP-10)
Room Number E22-321
Washington, DC 20590
3. Fax to: Information Resources Manager at (202) 366-4566.
RESCINDING A REPORT
An operator who reports an incident and upon subsequent investigation determines that the
event did not meet the criteria in 49 CFR 191.3 may request that its report be rescinded.
Requests for rescission should be submitted on operator letterhead and mailed or faxed to
the Information Resources Manager at the address/fax number above. Requests may also be
submitted by email to [email protected]. Requests should include
the following information:
a. The Report ID, the unique 8-digit identifier assigned by PHMSA,
b. Operator name,
c. PHMSA-issued operator ID number,
d. The number assigned by the National Response Center when telephonic report
was made in accordance with 49 CFR 191.5,
e. Date of the incident,
f. Location of the incident (e.g., for onshore incidents: city, county, state), and
g. A brief statement as to why the report should be rescinded.
Instructions:
Incident Report – Gas Transmission & Gathering Systems
Form PHMSA F 7100.2 (Rev. 01-2010)
Page 3 of 27
SPECIAL INSTRUCTIONS
1. Certain data fields must be completed before an Original Report will be accepted. The data
fields that must be completed for an Original Report to be accepted are indicated on the form
by a double asterisk (**). If filing a hardcopy of this report, the report will not be accepted
by PHMSA unless all of these fields have been completed. If filing on-line, your Original
Report will not be able to be submitted until the required information has been provided,
although your partially completed form can be saved on-line so that you can return at a later
time to provide the missing information.
2. An entry should be made in each applicable space or check box, unless otherwise directed by
the section instructions.
3. If the data is unavailable, enter “unknown” for text fields and leave numeric fields and fields
using check boxes or “radio” buttons blank.
4. If possible, 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.
5. For unknown or estimated data entries, the operator should file a supplemental report when
additional information becomes available to finalize the report.
6. If the question is not applicable, please enter “N/A” for text fields and leave numeric fields
and fields using check boxes or “radio” buttons blank.
7. For questions requiring numeric answers, all data fields should be filled in using zeroes
when appropriate. When decimal points are required, the decimal point should be placed
in a separate block in the data field.
Examples:
(Part C, item 3.a, ) Nominal diameter of pipe (in):
(Part C, item 3.b), Wall thickness (in)
(Part C, item 3.c), SMYS
/0/0/2/4/ (24 inches)
/3/./5/
(3.5 inches)
/0/./3/1/2/ (0.312 inches)
/0/5/2/,/0/0/0/ (52,000 psi)
8. If OTHER is checked for any answer to a question, please include an explanation or
description on the line provided next to the item checked.
9. Pay close attention to each question for the phrase:
a. (select all that apply)
b. (select only one)
If the phrase does not exist for a given question, then “select only one” is the default
instruction. “Select all that apply” means that you should choose all answers that are
applicable. “Select only one” means that you should select the single, primary or most
Instructions:
Incident Report – Gas Transmission & Gathering Systems
Form PHMSA F 7100.2 (Rev. 01-2010)
Page 4 of 27
applicable answer. DO NOT SELECT MORE ANSWERS THAN REQUESTED.
10. Date format = mm/dd/yy or for year = /yyyy/
11. Time format: All times are reported as a 24-hour clock:
Time format Examples:
a. (0000) = midnight =
b. (0800) = 8:00 a.m. =
c. (1200) = Noon
=
d. (1715) = 5:15 p.m. =
e. (2200) = 10:00 p.m. =
/0/0/0/0/
/0/8/0/0/
/1/2/0/0/
/1/7/1/5/
/2/2/0/0/
12. Local time always refers to time at the site of the incident.
SPECIFIC INSTRUCTIONS
PART A – GENERAL REPORT INFORMATION
Report Type: (select all that apply)
Check the appropriate report box or boxes to indicate the type of report being filed.
Depending on the descriptions below, the following combinations of boxes may be
selected:
Original Report only
Original Report plus Final Report
Supplemental Report only
Supplemental Report plus Final Report
Original Report
Select this type of report if this is the FIRST report filed for this incident.
If all of the information requested is known and provided at the time the initial report is
filed, including final property damages and failure cause information, check the box for
“Final Report” as well as the box for “Original Report,” indicating that no further
information will be forthcoming.
Supplemental Report
Select this type of report only if you have already filed an “Original Report” AND you are
now providing new, updated, and/or corrected information. Multiple supplements are to be
submitted, as necessary, in order to provide new, updated, and/or corrected information as
it becomes available.
Instructions:
Incident Report – Gas Transmission & Gathering Systems
Form PHMSA F 7100.2 (Rev. 01-2010)
Page 5 of 27
For Supplemental Reports filed by fax or mail, please check the Supplemental Report
box, complete Part A, Items 1 through 6, and then enter information that has changed or is
being added. Please do not enter previously submitted information that has not changed
other than Items 1-6, which is needed to provide a way to identify previously filed reports.
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.
Operators are encouraged to file supplemental reports within one year in those instances
where the supplemental report is used to update information from investigations that were
still ongoing when the prior report was filed.
Final Report
Select this type of report if you are filing an “Original Report” for which no further
information will be forthcoming (as described under “Original Report” above) or if you
have already filed an “Original Report” AND you are now providing new, updated, and/or
corrected information via a “Supplemental Report” AND you are reasonably certain that no
further information will be forthcoming. (Note: If an Operator files one of the two types
of “Final” Reports and then subsequently finds that new information needs to be provided,
it should submit another “Supplemental Report” and select the appropriate box or boxes –
“Supplemental + Final” (if appropriate) – for the newly submitted report and include an
explanation in the PART H Narrative.)
Supplemental reports must be filed as soon as practicable following the Operator’s
awareness of new, additional, or updated information. Failure to comply with these
requirements can result in enforcement actions, including the assessment of civil penalties
not to exceed $100,000 for each violation for each day that such violation persists up to a
maximum of $1,000,000.
In Part A, answer questions from 1 thru 19 by providing the requested
information or by checking the appropriate box.
1. Operator’s OPS -Issued Operator Identification Number (OPID):
The Pipeline and Hazardous Materials Safety Administration (PHMSA) assigns the
operator's identification number. Most OPIDs are 5 digits. Older OPIDs may contain
fewer digits. If your OPID contains fewer than 5 digits, insert leading zeros to fill all
blanks. Contact us at (202) 366-8075 if you need assistance with an identification number
during our business hours of 8:30 AM to 5:00 PM Eastern Time.
2. Name of Operator
This is the company name used when registering for an Operator ID and PIN in the Online
Data Entry System. For online entries, the Name of Operator should be automatically
filled in based on the Operator Identification Number entered in question 1. If the name
that appears does not coincide with the Operator ID, contact PHMSA at the number
provided in Question 1.
Instructions:
Incident Report – Gas Transmission & Gathering Systems
Form PHMSA F 7100.2 (Rev. 01-2010)
Page 6 of 27
3. Address of Operator
Enter the address of the operator’s business office to which any correspondence related to
the incident report should be sent.
4. Local time (24-hour clock) and date of the Incident.
For pipeline systems crossing multiple time zones, enter the time at the location of the
Incident.
See page 5 for examples of Date format and Time format expressed as a 24-hour
clock
5. 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 printed on the form.
If you cannot locate the incident with a GPS or some other means, the U.S. Census Bureau
provides a tool for determining latitude and longitude, (http://tiger.census.gov/cgibin/mapbrowse-tbl). You can use the online tool to identify the geographic location of the
incident. The tool displays the latitude and longitude in decimal degrees below the map.
Any questions regarding the required format, conversion or how to use the tool noted above
can be directed to Amy Nelson (202.493.0591 or [email protected]).
6. National Response Center (NRC) Report Number
§ 191.5 requires that incidents meeting the criteria outlined in §191.3 be reported directly
to the 24-hour National Response Center (NRC): at 1-800-424-8802 at the earliest
practicable moment (generally within 2 hours). The NRC assigns numbers to each call.
The number of that telephonic report is to be entered in Question 6.
7. Local time (24-hr clock) and date of initial telephonic report to the National
Response Center:
Enter the time (local time at site of the Incident) and date of the telephonic report of
Incident. The time should be shown by 24-hour clock notation (see page 5 for examples).
Instructions:
Incident Report – Gas Transmission & Gathering Systems
Form PHMSA F 7100.2 (Rev. 01-2010)
Page 7 of 27
8. Incident resulted from:
Indicate whether the incident resulted from intentional or unintentional release of gas or
from reasons other than release of gas.
9. Gas released:
Report the type of gas released. Examples of synthetic gas include landfill gas, biogas,
and manufactured gas based on naptha.
10. Estimated volume of gas released unintentionally:
Estimate the amount of gas that was released (in thousands of cubic feet) from the
beginning of the incident until such time as gas is no longer being released from the
pipeline system or intentional and controlled blowdown has commenced. Estimates
should be based on best-available information.
11. Estimated volume of intentional and controlled release/blowdown :
Estimate the amount of gas that was released (in thousands of cubic feet) during any
intentional release or controlled blowdown conducted as part of responding to or
recovering from 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.
12. Estimated volume of accompanying liquid released
If any accompanying liquid was released as a result of the incident, estimate the quantity
released, in barrels. Barrel means a unit of measurement equal to 42 U.S. standard
gallons. The table below converts gallons to barrels.
Instructions:
Incident Report – Gas Transmission & Gathering Systems
Form PHMSA F 7100.2 (Rev. 01-2010)
Page 8 of 27
If
estimated
volume is
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
Report
gallons
gallons
gallons
gallons
gallons
gallons
gallons
gallons
gallons
gallons
gallons
gallons
gallons
gallons
gallons
gallons
gallons
gallons
gallons
0.12
0.14
0.17
0.19
0.21
0.24
0.26
0.29
0.31
0.33
0.36
0.38
0.41
0.43
0.45
0.48
0.50
0.52
0.55
barrels
barrels
barrels
barrels
barrels
barrels
barrels
barrels
barrels
barrels
barrels
barrels
barrels
barrels
barrels
barrels
barrels
barrels
barrels
If
estimated
volume is
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
Report
gallons
gallons
gallons
gallons
gallons
gallons
gallons
gallons
gallons
gallons
gallons
gallons
gallons
gallons
gallons
gallons
gallons
gallons
0.57
0.60
0.62
0.64
0.67
0.69
0.71
0.74
0.76
0.79
0.81
0.83
0.86
0.88
0.91
0.93
0.95
0.98
1.000
barrels
barrels
barrels
barrels
barrels
barrels
barrels
barrels
barrels
barrels
barrels
barrels
barrels
barrels
barrels
barrels
barrels
barrels
barrels
13. 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. This
aligns with the Department of Transportation's general guidelines for all modes for
reporting deaths and injuries.
Contractor employees working for the operator means people hired to work for or on
behalf of the operator of the pipeline.
Non-operator emergency responders means people responding to render professional
aid at the incident scene including on-duty fire fighters, rescue workers, EMTs, police
officers, etc. “Good Samaritans” that stop to assist should 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.
Instructions:
Incident Report – Gas Transmission & Gathering Systems
Form PHMSA F 7100.2 (Rev. 01-2010)
Page 9 of 27
Workers performing work near, but not on, the right of way and who are affected
should be reported as general public.
14. Were there injuries requiring inpatient hospitalization?
Injuries requiring inpatient hospitalization means injuries sustained as a result of the
incident and which require both hospital admission and at least one overnight stay.
15. Was the pipeline/facility shut down due to the incident?
Report any shutdowns that occur because of damage incurred during the incident or to
make repairs necessitated by the incident. Instances in which an incident was caused by a
release that did not involve damage to the pipeline (e.g., incorrect operations) and in which
no need for repairs resulted need not be reported as being shutdown, even though the
pipeline may have been shutdown as a precautionary measure to inspect for damages.
If No is selected, explain the reason that no shutdown was needed in the blank provided.
If Yes is selected, complete questions 15.a and 15.b.
15.a. Local time (24hr clock) and date of shutdown
For pipeline systems crossing multiple time zones, enter the time at the location of the
incident.
15.b. Local time pipeline/facility restarted
Report the time the pipeline/facility was restarted (if applicable). If the pipeline or facility
has not been restarted at the time of reporting, check “Still shut down” and then include the
restart time in a future Supplemental Report.
16. Did the gas Ignite?
Ignite means the gas caught fire.
17. Did the gas Explode?
Explode means the ignition of the gas with a sudden and violent release of energy.
18. Number of General Public Evacuated:
The number of people evacuated should be estimated based on operator knowledge, or
police, fire or other emergency responder reports. If there was no evacuation involving the
general public, report “0.” If an estimate is not possible for some reason, leave blank but
include an explanation of why it was not possible in the Part H Narrative.
19. Time sequence (use local time, 24-hour clock)
Enter the time the operator became aware that an event constituted an incident (i.e.,
identified the incident) and the time operator personnel or contract resources (i.e.,
personnel or equipment) arrived on site. All times should be local times at the location of
the incident.
Instructions:
Incident Report – Gas Transmission & Gathering Systems
Form PHMSA F 7100.2 (Rev. 01-2010)
Page 10 of 27
PART B – ADDITIONAL LOCATION INFORMATION
1. Was the origin of the incident onshore?
Answer Yes or No as appropriate and complete only the designated questions.
For onshore pipelines
2 – 5. Incident Location
Provide the state, zip code, city, and county/parish in which the incident occurred.
6. 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/valve station or survey
station number. This designator is intended to allow PHMSA personnel to both return to
the physical location of the Incident using the operator’s own maps and identification
systems as well as to identify the “paper” location of the Incident when reviewing operator
maps and records.
7. 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”.
8. 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”.
9. 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.
10. 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
Instructions:
Incident Report – Gas Transmission & Gathering Systems
Form PHMSA F 7100.2 (Rev. 01-2010)
Page 11 of 27
discernible boundaries. This “operator-controlled property” does not refer to the pipeline
right-of-way, which is a separate choice for this question.
11. Area of Incident (as found)
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 stained 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 should be appropriately reported in section G of this form.
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, 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, pump stations and break out tank farms.
12. Did Incident occur in a crossing?
Use Bridge Crossing if the pipeline is suspended above a body of water or roadway,
railroad right-of-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 should 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
Instructions:
Incident Report – Gas Transmission & Gathering Systems
Form PHMSA F 7100.2 (Rev. 01-2010)
Page 12 of 27
name that is commonly used and understood in the local area, this field should 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, allowing for seasonal, weather-related and
other factors which may affect the water depth from time to time.
For offshore pipelines
13. Approximate water depth (ft.):
This should 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).
14. Origin of Incident
Area and Tract/Block numbers should be provided for either State or OCS waters,
whichever is applicable.
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
“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 should be provided.
PART C – ADDITIONAL FACILITY INFORMATION
1. Is the pipeline or facility [Interstate or Intrastate]?
Interstate gas pipeline facility means a gas pipeline facility used to transport gas and
subject to the jurisdiction of the Federal Energy Regulatory Commission under the Natural
Gas Act (15 U.S.C. 717 et seq.).
Intrastate gas pipeline facility means a gas pipeline facility within a State not subject to
the jurisdiction of the FERC under the Natural Gas Act (15 U.S.C. 717 et seq.
3. 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 diameter of pipe is also called Nominal pipe size. It is the diameter in whole
number inches (except for pipe less than 4”) used to describe the pipe size; for example, 85/8 pipe has a nominal pipe size of 8”. Decimals are unnecessary for this measure (except
for pipe less than 4”).
Instructions:
Incident Report – Gas Transmission & Gathering Systems
Form PHMSA F 7100.2 (Rev. 01-2010)
Page 13 of 27
Enter pipe wall thickness in inches. Wall thickness is typically less than an inch, and is
standard among different pipeline types and manufacturers. Accordingly, use three
decimal places to report wall thickness: 0.312, 0.281, etc.
SMYS means specified minimum yield strength and is the yield strength prescribed by the
specification under which the material is purchased from the manufacturer.
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
Auxiliary piping means piping, usually small in diameter that supports the operation of the
mainline or facility piping and does not include tubing. Examples of auxiliary piping
include discharge and drain lines, etc.
If the incident occurred on an item not provided in this section, check the OTHER box
and specify in the space provided the item that failed.
6. 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., 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 a low volume release, although large volume leaks can and do occur on
occasion.
Rupture means a loss of containment event that immediately impairs the operation of the
pipeline. Pipeline ruptures have the potential to be severely detrimental to safety and the
environment. The terms “circumferential” and “longitudinal” refer to the general direction
or orientation of the rupture relative the pipe’s axis. They do not exclusively refer to a
failure involving a circumferential weld such as a girth weld, or to a failure involving a
longitudinal weld such as a pipe seam. (Precise measurement of size – e.g., micrometer –
is not needed. Approximate measurements can be provided in inches and decimals.)
PART D – ADDITIONAL CONSEQUENCE INFORMATION
Instructions:
Incident Report – Gas Transmission & Gathering Systems
Form PHMSA F 7100.2 (Rev. 01-2010)
Page 14 of 27
§192.903 What definitions apply to this subpart?
*
*
*
*
*
High consequence area means an area established by one of the methods described in
paragraphs (1) or (2) as follows:
(1) An area defined as-(i) A Class 3 location under Sec. 192.5; or
(ii) A Class 4 location under Sec. 192.5; or
(iii) Any area in a Class 1 or Class 2 location where the potential impact radius is
greater than 660 feet (200 meters), and the area within a potential impact circle
contains 20 or more buildings intended for human occupancy; or
(iv) Any area in a Class 1 or Class 2 location where the potential impact circle
contains an identified site.
(2) The area within a potential impact circle containing-(i) 20 or more buildings intended for human occupancy, unless the exception in
paragraph (4) applies; or
(ii) An identified site.
(3) Where a potential impact circle is calculated under either method (1) or (2) to
establish a high consequence area, the length of the high consequence area extends
axially along the length of the pipeline from the outermost edge of the first potential
impact circle that contains either an identified site or 20 or more buildings intended
for human occupancy to the outermost edge of the last contiguous potential impact
circle that contains either an identified site or 20 or more buildings intended for
human occupancy. (See figure E.I.A. in appendix E.)
2. Did this Incident occur in a High Consequence Area (HCA)?
This question should be answered based on the classification of the involved segment in the
operator’s integrity management (IM) program at the time of the incident.
2.a. 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 should identify
the method used within its IM program to determine that the location at which the incident
occurred was an HCA.
3. What is the PIR (Potential Impact Radius) for the location of this Incident?
An operator should 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.
Instructions:
Incident Report – Gas Transmission & Gathering Systems
Form PHMSA F 7100.2 (Rev. 01-2010)
Page 15 of 27
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.
(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 Sec. 192.7) to calculate the impact radius formula.)
4. 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.
5. 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 missiles dislodged by a pipeline
rupture, etc.
6. Were any of the fatalities or injuries reported for persons located outside the PIR?
This refers to the fatalities and injuries reported in Part A, questions 13 and 14.
7. Estimated cost to Operator:
All relevant costs to the operator must be included on the initial written incident report as
well as 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, gas lost, facility repair and
replacement, and environmental cleanup and damage. Do not report costs incurred for
facility repair, replacement, or change that are not related to the incident 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 should 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 (30 days, per § 191.15). The best available estimate of
these costs should be included in the initial report. For convenience, this estimate can be
revised, if needed, when supplemental reports are filed for other reasons, however, when no
Instructions:
Incident Report – Gas Transmission & Gathering Systems
Form PHMSA F 7100.2 (Rev. 01-2010)
Page 16 of 27
other changes are forthcoming, supplemental reports should be filed as new cost
information becomes available. If supplemental reports are not submitted for other
reasons, a supplemental report should be filed for the purpose of correcting the estimated
cost if these costs differ from those already reported by 20 percent or $20,000, whichever is
greater.
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.
Paid/reimbursed means that the entity experiencing the property damage was
compensated by the operator or operator’s representative for the damage or the cost to
repair the damage.
Cost of gas released unintentionally should be based on the volume reported in Part A,
Question 10.
Cost of gas released during intentional and controlled blowdown should be based on
the volume reported in Part A, Question 11.
Operator’s property damage estimates generally include physical damage to the property
of Operator or Owner Company such as the estimated installed value of the damaged pipe,
coating, component, materials or equipment due to the Incident, excluding 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, 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 to mitigate the risk of future failures are not included.
Estimated cost of Operator’s 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. Costs related to stakeholder
outreach, media response, etc. should not be included.
Other costs should not include estimated cost categories separately listed above.
Costs should be reported in only one category and should not be double-counted. Costs
can be split between two or more categories when they overlap more than one reporting
category.
Instructions:
Incident Report – Gas Transmission & Gathering Systems
Form PHMSA F 7100.2 (Rev. 01-2010)
Page 17 of 27
PART E – ADDITIONAL OPERATING INFORMATION
4. Not including pressure reductions required by PHMSA regulations (such as for
repairs and pipe movement), 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 should
be considered mandated by PHMSA or a state regulator if it was directed by an order or
other formal correspondence. Pressure reductions imposed by the operator as a result of
regulatory requirements, e.g., a pressure reduction taken because an anomaly identified
during an IM assessment could not be repaired within the required schedule (192.933(d)),
should not be considered mandated by PHMSA.
5.a. Type of upstream valve used to initially isolate release source
Identify the type of valve used to initially isolate the release on the upstream side. In
general, this will be the first upstream valve selected by the Operator to minimize the
release volume but may not be the closest to the incident site.
5.b. Type of downstream valve used to initially isolate release source
Identify the type of valve used to initially isolate the release on the downstream side. In
general, this will be the first downstream valve selected by the Operator to minimize the
release volume but may not be the closest to the incident site.
5.c. Length of segment isolated between valves (ft):
Identify the length in feet between the valves identified in item 5.a and 5.b that were
initially used to isolate the incident area.
5.f. 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.
SMYS means specified minimum yield strength and is the yield strength prescribed by the
specification under which the material is purchased from the manufacturer.
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.
Instructions:
Incident Report – Gas Transmission & Gathering Systems
Form PHMSA F 7100.2 (Rev. 01-2010)
Page 18 of 27
6. 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 exclusively for leak detection.
6.a. Was it operating at the time of the Incident?
Was the SCADA system in operation at the time of the Incident?
6.b. 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 the Narrative Part H
6.c and d. Did SCADA-based information (such as alarm(s), alert(s), event(s), and/or
volume or pack calculations) assist with the detection or confirmation of the Incident?
Check 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.
Check No if data from SCADA was not used to assist with identification of the incident.
7. How was the incident initially identified for the Operator? (select only one)
Controller per the definition in API RP 1168 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.
8. 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?
Check only one of the boxes 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.
Instructions:
Incident Report – Gas Transmission & Gathering Systems
Form PHMSA F 7100.2 (Rev. 01-2010)
Page 19 of 27
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 225
respectively. If the incident circumstances were such that tests were not required by these
sections, and if no tests were conducted, check no. If tests were administered, report
separately the number of operator employees and contractors working for the operator who
were tested and who failed.
PART G – APPARENT CAUSE
In PART G – Apparent Cause
Complete only one of the eight sections listed under G1 thru G8
After identifying the main cause category as designated by G1 thru G8, select the one,
single sub-cause that best describes the proximate cause of the incident in the shaded
column on the left. Answer the corresponding questions that accompany your selected
sub-cause.
G1 – Corrosion Failure
Corrosion includes a leak or failure caused by galvanic, atmospheric, stray current,
microbiological, or other corrosive action, and, for the purposes of this reporting, includes
selective seam corrosion. A corrosion leak is not limited to a hole in the pipe. 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 classified as Corrosion. (If the bonnet,
packing, or other gasket has deteriorated before the end of its expected life but not due to
corrosive action, the failure should be classified as a Equipment Failure – G6.)
External Corrosion
4.a. Under cathodic protection means cathodic protection in accordance with Sections
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
Instructions:
Incident Report – Gas Transmission & Gathering Systems
Form PHMSA F 7100.2 (Rev. 01-2010)
Page 20 of 27
12. Were cleaning/dewatering pigs (or other operations) routinely utilized?
13. Were corrosion coupons routinely utilized?
For purposes of these questions, “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.
Either External or Internal Corrosion
14.a. If Yes, for each tool used, select type of internal inspection tool and indicate
most recent year run:
Magnetic Flux Leakage Tool is an in-line inspection tool using an imposed magnetic flux
to detect instances of pipe wall loss from corrosion. This includes low- and high-resolution
MFL tools. It does not include transverse flux MFL tools, which are a separate choice in
this question.
Ultrasonic refers to an in-line inspection tool that uses ultrasonic technology to measure
wall thickness and detect instances of wall loss.
Transverse Field/Triaxial tools are specialized magnetic flux leakage tools that use a flux
oriented to improve ability to detect crack anomalies.
Combination Tool refers to any in-line inspection tool that uses a combination of these
inspection technologies in a single tool.
15. 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 need not be reported.
16. Has one or more Direct Assessment been conducted on this segment?
This refers to direct assessment as defined in 49 CFR 195.553. 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 195.553 do not constitute a Direct Assessment for
purposes of this question.
G2 – Natural Force Damage
This category includes all outside forces attributable to causes NOT involving humans.
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
Instructions:
Incident Report – Gas Transmission & Gathering Systems
Form PHMSA F 7100.2 (Rev. 01-2010)
Page 21 of 27
to be initiated by heavy rains or floods.
Heavy Rains/Floods refer to all water related incident 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 refers to those causes that are related to ambient temperature effects, either
heat or cold, where temperature was the initial 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 as section G4 “Other Outside Force Damage”.
G3 – Excavation Damage
This section covers damage inflicted by the operator, operator’s contractor, or entities
unrelated to the operator during excavation that results in an immediate release of gas. For
damage from outside forces OTHER than excavation which results in an immediate
release, use G2 “Natural Force Damage” or G4 “Other Outside Force,” as appropriate. For
a strike or other damage to a pipeline or facility that results in a later release, report the
incident in Section G4 as “Rupture or Failure Due to Previous Mechanical Damage.”
Excavation Damage by Operator (First Party)
Check this sub-cause if the incident was caused as a result of excavation by a direct
employee of the operator.
Excavation Damage by Operator’s Contractor (Second Party)
Check this sub-cause if the incident was 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
Check this sub-cause if the incident was 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.
Instructions:
Incident Report – Gas Transmission & Gathering Systems
Form PHMSA F 7100.2 (Rev. 01-2010)
Page 22 of 27
Previous Damage due to Excavation Activity
1.a. If Yes, for each tool used, select type of internal inspection tool and indicate most
recent year run:
Magnetic Flux Leakage Tool is an in-line inspection tool using an imposed magnetic flux
to detect instances of pipe wall loss from corrosion. Includes low- and high-resolution
MFL tools. Does not include transverse flux MFL tools, which are a separate choice in this
question.
Ultrasonic refers to an in-line inspection tool that uses ultrasonic technology to measure
wall thickness and detect instances of wall loss.
Transverse Field/Triaxial tools are specialized magnetic flux leakage tools that use a flux
oriented to improve ability to detect crack anomalies.
Combination Tool refers to any in-line inspection tool that uses a combination of these
inspection technologies in a single tool.
3. 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 need not be reported.
4. Has one or more Direct Assessment been conducted on this segment?
This refers to direct assessment as defined in 49 CFR 195.553. 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 were not used as part of the direct
assessment process defined in 195.553 do not constitute a Direct Assessment for purposes
of this question.
7. – 17. 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.
G4 – Other Outside Force Damage
This section covers incidents caused by outside force damage, other than excavation
damage or natural forces. Check the most appropriate one sub-cause in this section that
applies and answer any questions.
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. An example of
such a failure would be an explosion/fire at a neighboring facility or installation (chemical
plant, tank farm, other industrial facility) that results in a release at the operator’s facility.
(Note that an incident report is required only if damage to facilities subject to Part 192
Instructions:
Incident Report – Gas Transmission & Gathering Systems
Form PHMSA F 7100.2 (Rev. 01-2010)
Page 23 of 27
exceeded $50,000). This section should not be used if the release occurred first and then
the gas ignited. If the fire is known to have been started as a result of a lightning strike, the
incident’s cause should be classified under Section G2, “Natural Force Damage.” Arson
events directed at harming the pipeline or the operator should be reported as “Intentional
Damage” in this section. Forest fires that are caused by human activity and result in a
release should be reported in this section.
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. Pipeline incidents resulting from
vehicular traffic loading or other contact should also be reported in this category. If the
activity involved digging, drilling, boring, grading, cultivation or similar activities, report
in Section G3 “Excavation Damage”.
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 should be
reported as “Routine or Normal Fishing or Other Maritime Activity NOT Engaged in
Excavation” 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 should
be reported in Section G3, “Excavation Damage”.
Routine or Normal Fishing or Other Maritime Activity NOT Engaged in Excavation.
This sub-cause includes incidents due to shrimping, purseining, 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 due to a severe weather event
(this type of incident should be reported under “Damage by Boats, Barges, Drilling Rigs, or
Other Maritime Equipment or Vessels Set Adrift or Which Have Otherwise Lost Their
Mooring”) or the incident was caused by excavation activity such as dredging of
waterways or bodies of water (this type of incident should be reported under Section G3,
“Excavation Damage.”).
Previous Mechanical Damage NOT Related to Excavation. This sub-cause covers
incidents where damage occurred at some time prior to the release, and would include prior
excavation damage, prior outside force damage of an unknown nature, prior natural force
damage, and prior damage from other outside forces. Incidents resulting from damage
sustained during construction, installation, or fabrication of the pipe or a weld should be
reported under Section G5, “Material Failure of Pipe or Weld.”
Instructions:
Incident Report – Gas Transmission & Gathering Systems
Form PHMSA F 7100.2 (Rev. 01-2010)
Page 24 of 27
Intentional Damage
Vandalism means willful or malicious destruction of the operator’s pipeline facility or
equipment. This category would include pranks, systematic damage inflicted to harass the
operator, motor vehicle damage that was inflicted intentionally, and a variety of other
intentional acts.
Terrorism, per 28 C.F.R. § 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 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.
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.”
This section includes leaks, ruptures or other failures from defects within the material of
the pipe body or within the pipe seam or other weld due to faulty manufacturing
procedures, defects resulting from poor construction/installation practices, and in-service
stresses such as vibration, fatigue and environmental cracking.
Construction-, Installation-, or Fabrication-related includes leaks in or failures of
originally sound material due to force being applied during construction or installation that
caused a dent, gouge, excessive stress, or some other defect that eventually failed resulting
in an incident. Included are leaks in or failures of wrinkle bends, field welds, and damage
sustained in transportation to the construction or fabrication site.
Original Manufacturing-related (NOT girth weld or other welds formed in the field)
means an inherent flaw in the material or weld that occurred in the manufacture or at a
point prior to construction, fabrication or installation. Therefore, 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 Construction, Installation, Fabrication-related or Original Manufacturing-related is
selected, then select the failure mechanism.
Examples of Mechanical Stress include failures related to overburden or loss of support.
Instructions:
Incident Report – Gas Transmission & Gathering Systems
Form PHMSA F 7100.2 (Rev. 01-2010)
Page 25 of 27
G6 – Equipment Failure
This section applies to failures of items other than Pipe Body, Pipe Seam, or Welds.
Malfunction of Control/Relief Equipment
Examples of this type of incident cause include: overpressurization resulting from
malfunction of control or alarm device; relief valve malfunction: 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,
the incident should be reported under Section G7, “Incorrect Operation.”
ESD System Failure means failure of an emergency shutdown system.
G7 – Incorrect Operation
These types of incidents most often occur during operating, maintenance or repair
activities. Some examples of this type of failure are improper valve selection or operation,
inadvertent overpressurization, or improper selection or installation of equipment. The
unintentional ignition of the transported gas during a welding or maintenance activity
would also be included in this sub-cause. These types of incidents often involve training or
judgment errors.
G8 – Other Incident Cause
This section is provided for incident causes that do not fit in any of the main cause
categories listed in Sections G1 through G7.
If the incident cause is known but doesn’t fit in any category in sections G1 through G7,
check the Miscellaneous box and enter a description of the incident and continue in Part H,
Narrative Description of the Incident, if more space is needed.
If the incident cause is unknown at time of filing this report, check the Unknown box in
this section and select one reason from the accompanying two choices. If the investigation
is not completed and the cause of the incident is thus still to be determined, file a
supplemental report once the investigation is completed to report the apparent cause.
PART H – NARRATIVE DESCRIPTION OF THE INCIDENT
(Attach additional sheets as necessary)
Concisely describe the incident, including the facts, circumstances, and conditions that may
have contributed directly or indirectly to causing the incident. Include secondary and
contributing causes when possible, or any other factors associated with the cause that are
deemed pertinent. Use this section to clarify or explain unusual conditions, to provide
sketches or drawings, and to explain any estimated data. Operators submitting reports online will be afforded the opportunity to attach/upload files containing sketches, drawings,
or additional data.
Instructions:
Incident Report – Gas Transmission & Gathering Systems
Form PHMSA F 7100.2 (Rev. 01-2010)
Page 26 of 27
If you checked the Miscellaneous block in Section G8, the narrative should describe the
incident in detail, including all known or suspected causes and possible contributing
factors.
Operators should use the narrative to describe any secondary causes that they consider
important but which could not be reported in section G since only the primary cause is
reported there.
PART I – PREPARER AND AUTHORIZED SIGNATURE
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
most knowledgeable). Please enter the Preparer’s e-mail address if the Preparer has one,
and the phone and fax numbers used by the Preparer.
An Authorized Signature must be obtained from an officer, manager, or other person whom
the operator has designated to review and approve (and sign and date) the report. This
individual 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
individual signing as the Authorized Signature.
Instructions:
Incident Report – Gas Transmission & Gathering Systems
Form PHMSA F 7100.2 (Rev. 01-2010)
Page 27 of 27
| File Type | application/pdf |
| File Title | NOTICE: This report is required by 49 CFR Part 195 |
| Author | Debbie |
| File Modified | 2010-02-19 |
| File Created | 2010-02-19 |