NOTICE: 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.

U.S Department of Transportation
Pipeline and Hazardous Materials Safety Administration

OMB NO: 2137-0522
EXPIRATION DATE: 8/31/2020

Original Report
Date:
No.

06/27/2018
20180067 - 30556
-------------------------------------------------(DOT Use Only)

INCIDENT REPORT - GAS TRANSMISSION AND
GATHERING PIPELINE SYSTEMS
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. All responses to this collection of information are
mandatory. Send comments regarding the burden estimate or any other aspect of this collection of information, including suggestions for reducing the
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/library/forms.

PART A - KEY REPORT INFORMATION
Original:

Report Type: (select all that apply)

Supplemental:

Yes

Last Revision Date:
1. Operator's OPS-issued Operator Identification Number (OPID):
2. Name of Operator
3. Address of Operator:
3a. Street Address
3b. City
3c. State
3d. Zip Code:
4. Local time (24-hr clock) and date of the Incident:
5. Location of Incident:
Latitude:
Longitude:
6. National Response Center Report Number (if applicable):
7. Local time (24-hr clock) and date of initial telephonic report to the
National Response Center (if applicable):
8. Incident resulted from:
9. Gas released: (select only one, based on predominant volume
released)
- Other Gas Released Name:
10. Estimated volume of commodity 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 release (Barrels):
13. Were there fatalities?
- If Yes, specify the number in each category:
13a. Operator employees
13b. Contractor employees working for the Operator
13c. Non-Operator emergency responders
13d. Workers working on the right-of-way, but NOT
associated with this Operator
13e. General public
13f. Total fatalities (sum of above)
14. Were there injuries requiring inpatient hospitalization?
- If Yes, specify the number in each category:
14a. Operator employees
14b. Contractor employees working for the Operator
14c. Non-Operator emergency responders
14d. Workers working on the right-of-way, but NOT
associated with this Operator
14e. General public
14f. Total injuries (sum of above)
15. Was the pipeline/facility shut down due to the incident?
- If No, Explain:

2616
COLUMBIA GAS TRANSMISSION, LLC
700 LOUISIANA ST.
HOUSTON
Texas
77002
06/07/2018 04:16
39.806667
-80.759444
1214458
06/07/2018 06:12
Unintentional release of gas
Natural Gas

165,000.00

No

No

Yes

Form PHMSA F 7100.2

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Final:

 16.
17.
18.
19.

- If Yes, complete Questions 15a and 15b: (use local time, 24-hr clock)
15a. Local time and date of shutdown
06/07/2018 05:20
15b. Local time pipeline/facility restarted
- Still shut down? (* Supplemental Report Required)
Yes
Did the gas ignite?
Yes
Did the gas explode?
Yes
Number of general public evacuated:
0
Time sequence (use local time, 24-hour clock):
19a. Local time operator identified Incident– effective 10-2014,
06/07/2018 04:37
changed from "Incident" to "failure"
19b. Local time operator resources arrived on site
06/07/2018 06:00

PART B - ADDITIONAL LOCATION INFORMATION
1. Was the origin of the Incident onshore?

Yes
- Yes (Complete Questions 2-12)
- No (Complete Questions 13-15)

If Onshore:
2. State:
3. Zip Code:
4. City
5. County or Parish
6. Operator designated location
Specify:
7. Pipeline/Facility name:
8. Segment name/ID:
9. Was Incident on Federal land, other than the Outer Continental Shelf
(OCS)?
10. Location of Incident :
11. Area of Incident (as found) :
Specify:
Other – Describe:
Depth-of-Cover (in):
12. Did Incident occur in a crossing?
- If Yes, specify type below:
- If Bridge crossing –
Cased/ Uncased:
- If Railroad crossing –
Cased/ Uncased/ Bored/drilled
- If Road crossing –
Cased/ Uncased/ Bored/drilled
- If Water crossing –
Cased/ Uncased
Name of body of water (If commonly known):
Approx. water depth (ft) at the point of the Incident:
Select:
If Offshore:
13. Approx. water depth (ft) at the point of the Incident:
14. Origin of Incident:
- If "In State waters":
- State:
- Area:
- Block/Tract #:
- Nearest County/Parish:
- If "On the Outer Continental Shelf (OCS)":
- Area:
- Block #:
15. Area of Incident:

West Virginia
26041
Moundsville
Marshall
Milepost/Valve Station
MP 21.3
Leach Xpress
Mainline Valve LEX-500 to Mainline Valve LEX-600
No
Pipeline Right-of-way
Underground
Under soil
36
No

PART C - ADDITIONAL FACILITY INFORMATION
1. Is the pipeline or facility: - Interstate - Intrastate
2. Part of system involved in Incident:
3. Item involved in Incident:
- If Pipe – Specify:
3a. Nominal diameter of pipe (in):
3b. Wall thickness (in):
3c. SMYS (Specified Minimum Yield Strength) of pipe (psi):

Interstate
Onshore Pipeline, Including Valve Sites
Pipe
Pipe Body
36
.515
70,000

Form PHMSA F 7100.2

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 3d. Pipe specification:
3e. Pipe Seam – Specify:

API 5L X70M
DSAW

- If Other, Describe:
3f. Pipe manufacturer:
3g. Year of manufacture:
3h. Pipeline coating type at point of Incident – Specify:
- If Other, Describe:
- If Weld, including heat-affected zone – Specify:
- If Other, Describe:
- If Valve – Specify:
- If Mainline – Specify:
- If Other, Describe:
3i. Mainline valve manufacturer:
3j. Year of manufacture:
- If Other, Describe:
4. Year item involved in Incident was installed:
5. Material involved in Incident:
- If Material other than Carbon Steel or Plastic – Specify:
6. Type of Incident involved:
- If Mechanical Puncture – Specify Approx. size:
in. (axial) by
in. (circumferential)
- If Leak - Select Type:
- If Other – Describe:
- If Rupture - Select Orientation:
- If Other – Describe:
Approx. size: in. (widest opening):
by in. (length circumferentially or axially):
- If Other – Describe:

Durabond
2015
Fusion Bonded Epoxy

2017
Carbon Steel
Rupture

Circumferential
36
113

PART D - ADDITIONAL CONSEQUENCE INFORMATION
1. Class Location of Incident:
2. Did this Incident occur in a High Consequence Area (HCA)?
- If Yes:
2a. Specify the Method used to identify the HCA:
3. What is the PIR (Potential Impact Radius) for the location of this
Incident?
Feet:
4. Were any structures outside the PIR impacted or otherwise damaged
due to 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?
7. Estimated Property Damage :
7a. Estimated cost of public and non-Operator private
property damage paid/reimbursed by the Operator – effective 62011, "paid/reimbursed by the Operator" removed
Estimated cost of gas released unintentionally – effective 6-2011,
moved to item 7f
Estimated cost of gas released during intentional and controlled
blowdown – effective 6-2011, moved to item 7g
7b. Estimated cost of Operator's property damage & repairs
7c. Estimated cost of Operator's emergency response
7d. Estimated other costs
Describe:
7e. Property damage subtotal (sum of above)

Class 1 Location
No

1,056
No
No
No

$

0

$
0
$
0
$
0
Reasonable Estimated Property of Damage is not available
at this time.
$0

Cost of Gas Released
7f. Estimated cost of gas released unintentionally
7g. Estimated cost of gas released during intentional and
controlled blowdown
7h. Total estimated cost of gas released (sum of 7.f & 7.g above)
Total of all costs

$

437,250

$

0

$
437,250
$ 437,250

Form PHMSA F 7100.2

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 PART E - ADDITIONAL OPERATING INFORMATION
1. Estimated pressure at the point and time of the Incident (psig):
1,280.00
2. Maximum Allowable Operating Pressure (MAOP) at the point and
1,440.00
time of the Incident (psig):
Added 10-2014 2a. MAOP established by 49 CFR section:
192.619(a)(1)
- If Other, specify:
3. Describe the pressure on the system or facility relating to the
Pressure did not exceed MAOP
Incident:
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
No
restriction with pressure limits below those normally allowed by the
MAOP?
- If Yes - (Complete 4a and 4b below)
4a. Did the pressure exceed this established pressure
restriction?
4b. Was this pressure restriction mandated by PHMSA or the
State?
5. Was "Onshore Pipeline, Including Valve Sites" OR "Offshore Pipeline,
Yes
Including Riser and Riser Bend" selected in PART C, Question 2?
- If Yes - (Complete 5a. – 5e. below):
5a. Type of upstream valve used to initially isolate release source:
Manual
5b. Type of downstream valve used to initially isolate release
Automatic
source:
5c. Length of segment isolated between valves (ft):
71,280
5d. Is the pipeline configured to accommodate internal inspection
Yes
tools?
- If 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
- If Other, Describe:
5e. For this pipeline, are there operational factors which
significantly complicate the execution of an internal inspection tool
No
run?
- If 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
- If Other, Describe:
5f. Function of pipeline system:
Transmission System
6. Was a Supervisory Control and Data Acquisition (SCADA)-based
Yes
system in place on the pipeline or facility involved in the Incident?
- If Yes:
6a. Was it operating at the time of the Incident?
Yes
6b. Was it fully functional at the time of the Incident?
Yes
6c. Did SCADA-based information (such as alarm(s), alert(s),
event(s), and/or volume or pack calculations) assist with the
Yes
detection of the Incident?
6d. Did SCADA-based information (such as alarm(s), alert(s),
event(s), and/or volume calculations) assist with the confirmation of
Yes
the Incident?
SCADA-based information (such as alarm(s), alert(s),
7. How was the Incident initially identified for the Operator?
event(s), and/or volume or pack calculations)
- If Other – Describe:
7a. If "Controller", "Local Operating Personnel, including
contractors", "Air Patrol", or "Ground Patrol by Operator or its
contractor" is selected in Question 7, specify:
8. Was an investigation initiated into whether or not the controller(s) or
No, the Operator did not find that an investigation of the
control room issues were the cause of or a contributing factor to the
controller(s) actions or control room issues was necessary
Incident?
due to: (provide an explanation for why the Operator did not
Form PHMSA F 7100.2

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 investigate)
- If 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)
- If Yes, Describe 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:

The control Room was not a suspected cause amd later
was determine not part of the cause of the lease.

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?
- If Yes:
1a. How many were tested:
1b. 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?
- If Yes:
2a. How many were tested:
2b. How many failed:

Yes

1
0
No

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).
G2 - Natural Force Damage

Apparent Cause:

G1 - Corrosion Failure - only one sub-cause can be picked from shaded left-hand column
Corrosion Failure – Sub-cause:
- If External Corrosion:
1. Results of visual examination:
- If Other, Describe:
2. Type of corrosion: (select all that apply)
- Galvanic
- Atmospheric
- Stray Current
- Microbiological
- Selective Seam
- Other
- If Other – Describe:
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
- If Other – Describe:
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 4. Was the failed item buried under the ground?
- If Yes:
4a. Was failed item considered to be under cathodic protection at
the time of the incident?
- If Yes, Year protection started:
4b. Was shielding, tenting, or disbonding of coating evident at the
point of the incident?
4c. Has one or more Cathodic Protection Survey been conducted
at the point of the incident?
If "Yes, CP Annual Survey" – Most recent year conducted:
If "Yes, Close Interval Survey" – Most recent year conducted:
If "Yes, Other CP Survey" – Most recent year conducted:
- If No:
4d. Was the failed item externally coated or painted?
5. Was there observable damage to the coating or paint in the vicinity of
the corrosion?
- If Internal Corrosion:
6. Results of visual examination:
- If Other, Describe:
7. Cause of corrosion (select all that apply):
- Corrosive Commodity
- Water drop-out/Acid
- Microbiological
- Erosion
- Other
- If Other, Describe:
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
- If Other, Describe:
9. Location of corrosion (select all that apply):
- Low point in pipe
- Elbow
- Drop-out
- Other
- If Other, Describe:
10. Was the gas/fluid treated with corrosion inhibitors or biocides?
11. Was the interior coated or lined with protective coating?
12. Were cleaning/dewatering pigs (or other operations) routinely
utilized?
13. Were corrosion coupons routinely utilized?
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?
14a. If Yes, for each tool used, select type of internal inspection tool and indicate most recent year run:
- Magnetic Flux Leakage Tool
Most recent year run:
- Ultrasonic
Most recent year run:
- Geometry
Most recent year run:
- Caliper
Most recent year run:
- Crack
Most recent year run:
- Hard Spot
Most recent year run:
- Combination Tool
Most recent year run:
- Transverse Field/Triaxial
Most recent year run:
- Other
Most recent year run:
If Other, Describe:
15. Has one or more hydrotest or other pressure test been conducted
since original construction at the point of the Incident?
Form PHMSA F 7100.2

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 - If Yes,
Most recent year tested:
Test pressure (psig):
16. Has one or more Direct Assessment been conducted on this
segment?
- If Yes, and an investigative dig was conducted at the point of the Incident:
Most recent year conducted:
- If Yes, but the point of the Incident was not identified as a dig site:
Most recent year conducted:
17. Has one or more non-destructive examination been conducted at
the point of the Incident since January 1, 2002?
17a. 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
Most recent year examined:
- Guided Wave Ultrasonic
Most recent year examined:
- Handheld Ultrasonic Tool
Most recent year examined:
- Wet Magnetic Particle Test
Most recent year examined:
- Dry Magnetic Particle Test
Most recent year examined:
- Other
Most recent year examined:
If Other, Describe:

G2 - Natural Force Damage - only one sub-cause can be picked from shaded left-handed column
Natural Force Damage – Sub-Cause:

Earth Movement, NOT due to Heavy Rains/Floods

- If Earth Movement, NOT due to Heavy Rains/Floods:
1. Specify:

Landslide
- If Other, Describe:

- If Heavy Rains/Floods:
2. Specify:
- If Other, Describe:

- If Lightning:
3. Specify:
- If Temperature:
4. Specify:
- If Other, Describe:

- If Other Natural Force Damage:
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
No
with an extreme weather event?
6a. If yes, specify: (select all that apply):
- Hurricane
- Tropical Storm
- Tornado
- Other
- If Other, Describe:

G3 - Excavation Damage only one sub-cause can be picked from shaded left-hand column
Excavation Damage – Sub-Cause:
- If 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?
1a. If Yes, for each tool used, select type of internal inspection tool and indicate most recent year run:
- Magnetic Flux Leakage
Year:
- Ultrasonic
Year:
- Geometry
Year:

Form PHMSA F 7100.2

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 - Caliper
Year:
- Crack
Year:
- Hard Spot
Year:
- Combination Tool
Year:
- Transverse Field/Triaxial
Year:
- Other:
Year:
Describe:
2. Do you have reason to believe that the internal inspection was
completed BEFORE the damage was sustained?
3. Has one or more hydrotest or other pressure test been conducted
since original construction at the point of the Incident?
- If Yes:
Most recent year tested:
Test pressure (psig):
4. Has one or more Direct Assessment been conducted on the pipeline
segment?
- If Yes, and an investigative dig was conducted at the point of the Incident:
Most recent year conducted:
- If Yes, but the point of the Incident was not identified as a dig site:
Most recent year conducted:
5. Has one or more non-destructive examination been conducted at the
point of the Incident since January 1, 2002?
5a. 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
Year:
- Guided Wave Ultrasonic
Year:
- Handheld Ultrasonic Tool
Year:
- Wet Magnetic Particle Test
Year:
- Dry Magnetic Particle Test
Year:
- Other
Year:
Describe:
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?
6a. If Yes, Notification received from (select all that apply):
- One-Call System
- Excavator
- Contractor
- Landowner
Complete the following mandatory CGA-DIRT Program questions if any Excavation Damage sub-cause is selected.
7. Do you want PHMSA to upload the following information to CGADIRT (www.cga-dirt.com)?
8. Right-of-Way where event occurred (select all that apply):
- Public
- If Public, Specify:
- Private
- If Private, Specify:
- Pipeline Property/Easement
- Power/Transmission Line
- Railroad
- Dedicated Public Utility Easement
- Federal Land
- Data not collected
- Unknown/Other
9. Type of excavator :
10. Type of excavation equipment :
11. Type of work performed :
Form PHMSA F 7100.2

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 12. Was the One-Call Center notified? - Yes - No
12a. If Yes, specify ticket number:
12b. If this is a State where more than a single One-Call Center
exists, list the name of the One-Call Center notified:
13. Type of Locator:
14. Were facility locate marks visible in the area of excavation?
15. Were facilities marked correctly?
16. Did the damage cause an interruption in service?
16a. If Yes, specify duration of the interruption: (hours)
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, then one predominant second level CGA-DIRT Root Cause as well):
- Predominant first level CGA-DIRT Root Cause:
- If One-Call Notification Practices Not Sufficient, Specify:
- If Locating Practices Not Sufficient, Specify:
- If Excavation Practices Not Sufficient, Specify:
- If Other/None of the Above, Explain:

G4 - Other Outside Force Damage - only one sub-cause can be selected from the shaded left-hand column
Other Outside Force Damage – Sub-Cause:
- If Damage by Car, Truck, or Other Motorized Vehicle/Equipment NOT Engaged in Excavation:
1. Vehicle/Equipment operated by:
- If 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
- If Other, Describe:
- If Previous Mechanical Damage NOT Related to Excavation: 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?
3a. If Yes, for each tool used, select type of internal inspection tool and indicate most recent year run:
- Magnetic Flux Leakage
Most recent year run:
- Ultrasonic
Most recent year run:
- Geometry
Most recent year run:
- Caliper
Most recent year run:
- Crack
Most recent year run:
- Hard Spot
Most recent year run:
- Combination Tool
Most recent year run:
- Transverse Field/Triaxial
Most recent year run:
- Other:
Most recent year run:
Describe:
4. Do you have reason to believe that the internal inspection was
completed BEFORE the damage was sustained?
5. Has one or more hydrotest or other pressure test been conducted
since original construction at the point of the Incident?
- If Yes:
Most recent year tested:
Test pressure (psig):
6. Has one or more Direct Assessment been conducted on the pipeline
segment?
Form PHMSA F 7100.2

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 - If Yes, and an investigative dig was conducted at the point of the Incident :
Most recent year conducted:
- If Yes, but the point of the Incident was not identified as a dig site:
Most recent year conducted:
7. Has one or more non-destructive examination been conducted at the
point of the Incident since January 1, 2002?
7a. 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
Most recent year conducted:
- Guided Wave Ultrasonic
Most recent year conducted:
- Handheld Ultrasonic Tool
Most recent year conducted:
- Wet Magnetic Particle Test
Most recent year conducted:
- Dry Magnetic Particle Test
Most recent year conducted:
- Other
Most recent year conducted:
Describe:
- If Intentional Damage:
8. Specify:
- If Other, Describe:
- If Other Outside Force Damage:
9. Describe:

G5 - Pipe, Weld, or Joint Failure

Use this section to report material failures ONLY IF the "Item Involved in
Incident" (from PART C, Question 3) is "Pipe" or "Weld."
Only one sub-cause can be selected from the shaded left-hand column

Pipe, Weld or Join Failure – Sub-Cause:
1. The sub-cause shown above is based on the following (select all that apply):
- Field Examination
- Determined by Metallurgical Analysis
- Other Analysis
- If "Other Analysis", Describe
- Sub-cause is Tentative or Suspected; Still Under Investigation
(Supplemental Report required)
- If Construction-, Installation- or Fabrication
2. List contributing factors: (select all that apply)
- Fatigue or Vibration related:
Specify:
- If Other, Describe:
- Mechanical Stress
- Other
- If Other, Describe:
- If Environmental Cracking-related:
3. Specify:
- If Other, Describe:
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
- Arc Burn
- Crack
- Lack of Fusion
- Lamination
- Buckle
- Wrinkle
- Misalignment
- Burnt Steel
- Other
- If Other, Describe:
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 5. Has one or more internal inspection tool collected data at the point of
the Incident?
5a. If Yes, for each tool used, select type of internal inspection tool and indicate most recent year run:
- Magnetic Flux Leakage
Most recent year run:
- Ultrasonic
Most recent year run:
- Geometry
Most recent year run:
- Caliper
Most recent year run:
- Crack
Most recent year run:
- Hard Spot
Most recent year run:
- Combination Tool
Most recent year run:
- Transverse Field/Triaxial
Most recent year run:
- Other
Most recent year run:
Describe:
6. Has one or more hydrotest or other pressure test been conducted since
original construction at the point of the Incident?
- If Yes:
Most recent year tested:
Test pressure (psig):
7. Has one or more Direct Assessment been conducted on the pipeline
segment?
- If Yes, and an investigative dig was conducted at the point of the Incident:
Most recent year conducted:
- If Yes, but the point of the Incident was not identified as a dig site:
Most recent year conducted:
8. Has one or more non-destructive examination(s) been conducted at
the point of the Incident since January 1,2002?
8a. 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
Most recent year conducted:
- Guided Wave Ultrasonic
Most recent year conducted:
- Handheld Ultrasonic Tool
Most recent year conducted:
- Wet Magnetic Particle Test
Most recent year conducted:
- Dry Magnetic Particle Test
Most recent year conducted:
- Other
Most recent year conducted:
Describe:

G6 - Equipment Failure - only one sub-cause can be selected from the shaded left-hand column
Equipment Failure – Sub-Cause:

- If Malfunction of Control/Relief Equipment:
1. Specify:
- Control Valve
- Instrumentation
- SCADA
- Communications
- Block Valve
- Check Valve
- Relief Valve

Form PHMSA F 7100.2

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 - Power Failure
- Stopple/Control Fitting
- Pressure Regulator
- ESD System Failure
- Other
- If Other, Describe:

- If Compressor or Compressor-related Equipment:
2. Specify:
- If Other, Describe:

- If Threaded Connection/Coupling Failure:
3. Specify:
- If Other, Describe:

- If Non-threaded Connection Failure:
4. Specify:
- If Other, Describe:

- If 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
- If Other, Describe:

G7 – Incorrect Operation - only one sub-cause can be selected from the shaded left-hand column
Incorrect Operation – Sub-Cause:

- If Underground Gas Storage, Pressure Vessel, or Cavern Allowed or Caused to Overpressure:
1. Specify:
- If Other, Describe:

- If 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:
- If Other, Describe:
4. What category type was the activity that caused the Incident:
5. Was the task(s) that led to the Incident identified as a covered task in
your Operator Qualification Program?
5a. If Yes, were the individuals performing the task(s) qualified for
the task(s)?

G8 - Other Incident Cause - only one sub-cause can be selected from the shaded left-hand column
Other Incident Cause – Sub-Cause:

- If Miscellaneous:
1. Describe:

Form PHMSA F 7100.2

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 - If Unknown:
2. Specify:

PART - H NARRATIVE DESCRIPTION OF THE INCIDENT
On June 7th, 2018, an unintended release event of natural gas (material) into atmosphere was reported to the National
Response center (NRC). This event took place on the Leach Express (LEX) pipeline that is operated and maintained by
Columbia Gas Transmission, LLC (Columbia). LEX Pipeline is a 36 inch in diameter and is classified as transmission
with a maximum allowable operating pressure of 1,440 psig. It is uni-directional flow line that starts from Majorsville
compressor station, West Virginia and terminates at the tie-in with R-System Regulator Station (Ohio). At 04:16 Eastern
Standard Time (EST), Columbia Gas Control personnel noted a low pressure SCADA alarm and Columbia Operations
personnel were dispatched to investigate the event. At 04:37 EST Columbia Monitoring Center received a call from the
Marshal County 911 regarding a pipeline failure in Marshal County, WV near WV State Route 21/1 (Nixon Ridge Road).
The failure is within valve section (VS) Mainline Valve LEX-500 to Mainline Valve LEX-600 (Isolated Segment). The
material ignited with limited damage occurred to vegetation and trees within the area of the pipeline failure site. No
structures were identified nearby failure site. No fatalities or injuries were reported in lieu of this pipeline failure. The
failed pipeline section was isolated approximately at 05:20 EST. The incident is under investigation and the failed
sections of the pipeline were sent to a Metallurgical Failure Analysis laboratory to determine the probable cause behind
the failure of the pipeline. The 48-hr update NRC was completed on July 8th, 2018 with Report No. 1214673. The
reportable incident is still under investigation and no probable cause has been identified by the time this report was
submitted.

PART I - PREPARER AND AUTHORIZED SIGNATURE
Preparer's Name
Preparer's Title
Preparer's Telephone Number
Preparer's E-mail Address
Preparer's Facsimile Number
Authorized Signature Title
Authorized Signature Telephone Number
Authorized Signature Email
Date

Kamran Rostami Asrabadi
Compliance Specialist
304-357-2351
Kamran_rostami@transcanada.com
USRC East Manager
304-357-3728
george_ hamaty@transcanada.com
06/27/2018

Form PHMSA F 7100.2

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 NOTICE: 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.

U.S Department of Transportation
Pipeline and Hazardous Materials Safety Administration

OMB NO: 2137-0522
EXPIRATION DATE: 8/31/2020

Original Report
Date:
No.

06/27/2018
20180067 - 30576
-------------------------------------------------(DOT Use Only)

INCIDENT REPORT - GAS TRANSMISSION AND
GATHERING PIPELINE SYSTEMS
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. All responses to this collection of information are
mandatory. Send comments regarding the burden estimate or any other aspect of this collection of information, including suggestions for reducing the
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/library/forms.

PART A - KEY REPORT INFORMATION
Original:

Report Type: (select all that apply)
Last Revision Date:
1. Operator's OPS-issued Operator Identification Number (OPID):
2. Name of Operator
3. Address of Operator:
3a. Street Address
3b. City
3c. State
3d. Zip Code:
4. Local time (24-hr clock) and date of the Incident:
5. Location of Incident:
Latitude:
Longitude:
6. National Response Center Report Number (if applicable):
7. Local time (24-hr clock) and date of initial telephonic report to the
National Response Center (if applicable):
8. Incident resulted from:
9. Gas released: (select only one, based on predominant volume
released)
- Other Gas Released Name:
10. Estimated volume of commodity 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 release (Barrels):
13. Were there fatalities?
- If Yes, specify the number in each category:
13a. Operator employees
13b. Contractor employees working for the Operator
13c. Non-Operator emergency responders
13d. Workers working on the right-of-way, but NOT
associated with this Operator
13e. General public
13f. Total fatalities (sum of above)
14. Were there injuries requiring inpatient hospitalization?
- If Yes, specify the number in each category:
14a. Operator employees
14b. Contractor employees working for the Operator
14c. Non-Operator emergency responders
14d. Workers working on the right-of-way, but NOT
associated with this Operator
14e. General public
14f. Total injuries (sum of above)
15. Was the pipeline/facility shut down due to the incident?
- If No, Explain:

Supplemental:
Yes

07/02/2018
2616
COLUMBIA GAS TRANSMISSION, LLC
700 LOUISIANA ST.
HOUSTON
Texas
77002
06/07/2018 04:16
39.806667
-80.759444
1214458
06/07/2018 06:12
Unintentional release of gas
Natural Gas

165,000.00

No

No

Yes

Form PHMSA F 7100.2

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Final:

 16.
17.
18.
19.

- If Yes, complete Questions 15a and 15b: (use local time, 24-hr clock)
15a. Local time and date of shutdown
06/07/2018 05:20
15b. Local time pipeline/facility restarted
- Still shut down? (* Supplemental Report Required)
Yes
Did the gas ignite?
Yes
Did the gas explode?
Yes
Number of general public evacuated:
0
Time sequence (use local time, 24-hour clock):
19a. Local time operator identified Incident– effective 10-2014,
06/07/2018 04:37
changed from "Incident" to "failure"
19b. Local time operator resources arrived on site
06/07/2018 06:00

PART B - ADDITIONAL LOCATION INFORMATION
1. Was the origin of the Incident onshore?

Yes
- Yes (Complete Questions 2-12)
- No (Complete Questions 13-15)

If Onshore:
2. State:
3. Zip Code:
4. City
5. County or Parish
6. Operator designated location
Specify:
7. Pipeline/Facility name:
8. Segment name/ID:
9. Was Incident on Federal land, other than the Outer Continental Shelf
(OCS)?
10. Location of Incident :
11. Area of Incident (as found) :
Specify:
Other – Describe:
Depth-of-Cover (in):
12. Did Incident occur in a crossing?
- If Yes, specify type below:
- If Bridge crossing –
Cased/ Uncased:
- If Railroad crossing –
Cased/ Uncased/ Bored/drilled
- If Road crossing –
Cased/ Uncased/ Bored/drilled
- If Water crossing –
Cased/ Uncased
Name of body of water (If commonly known):
Approx. water depth (ft) at the point of the Incident:
Select:
If Offshore:
13. Approx. water depth (ft) at the point of the Incident:
14. Origin of Incident:
- If "In State waters":
- State:
- Area:
- Block/Tract #:
- Nearest County/Parish:
- If "On the Outer Continental Shelf (OCS)":
- Area:
- Block #:
15. Area of Incident:

West Virginia
26041
Moundsville
Marshall
Milepost/Valve Station
MP 21.3
Leach Xpress
Mainline Valve LEX-500 to Mainline Valve LEX-600
No
Pipeline Right-of-way
Underground
Under soil
36
No

PART C - ADDITIONAL FACILITY INFORMATION
1. Is the pipeline or facility: - Interstate - Intrastate
2. Part of system involved in Incident:
3. Item involved in Incident:
- If Pipe – Specify:
3a. Nominal diameter of pipe (in):
3b. Wall thickness (in):
3c. SMYS (Specified Minimum Yield Strength) of pipe (psi):

Interstate
Onshore Pipeline, Including Valve Sites
Pipe
Pipe Body
36
.515
70,000

Form PHMSA F 7100.2

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 3d. Pipe specification:
3e. Pipe Seam – Specify:

API 5L X70M
DSAW

- If Other, Describe:
3f. Pipe manufacturer:
3g. Year of manufacture:
3h. Pipeline coating type at point of Incident – Specify:
- If Other, Describe:
- If Weld, including heat-affected zone – Specify:
- If Other, Describe:
- If Valve – Specify:
- If Mainline – Specify:
- If Other, Describe:
3i. Mainline valve manufacturer:
3j. Year of manufacture:
- If Other, Describe:
4. Year item involved in Incident was installed:
5. Material involved in Incident:
- If Material other than Carbon Steel or Plastic – Specify:
6. Type of Incident involved:
- If Mechanical Puncture – Specify Approx. size:
in. (axial) by
in. (circumferential)
- If Leak - Select Type:
- If Other – Describe:
- If Rupture - Select Orientation:
- If Other – Describe:
Approx. size: in. (widest opening):
by in. (length circumferentially or axially):
- If Other – Describe:

Durabond
2015
Fusion Bonded Epoxy

2017
Carbon Steel
Rupture

Circumferential
36
113

PART D - ADDITIONAL CONSEQUENCE INFORMATION
1. Class Location of Incident:
2. Did this Incident occur in a High Consequence Area (HCA)?
- If Yes:
2a. Specify the Method used to identify the HCA:
3. What is the PIR (Potential Impact Radius) for the location of this
Incident?
Feet:
4. Were any structures outside the PIR impacted or otherwise damaged
due to 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?
7. Estimated Property Damage :
7a. Estimated cost of public and non-Operator private
property damage paid/reimbursed by the Operator – effective 62011, "paid/reimbursed by the Operator" removed
Estimated cost of gas released unintentionally – effective 6-2011,
moved to item 7f
Estimated cost of gas released during intentional and controlled
blowdown – effective 6-2011, moved to item 7g
7b. Estimated cost of Operator's property damage & repairs
7c. Estimated cost of Operator's emergency response
7d. Estimated other costs
Describe:
7e. Property damage subtotal (sum of above)

Class 1 Location
No

1,056
No
No
No

$

0

$ 10,000,000
$
0
$
0
$ 10,000,000

Cost of Gas Released
7f. Estimated cost of gas released unintentionally
7g. Estimated cost of gas released during intentional and
controlled blowdown
7h. Total estimated cost of gas released (sum of 7.f & 7.g above)
Total of all costs

$

437,250

$

0

$
437,250
$ 10,437,250

Form PHMSA F 7100.2

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 PART E - ADDITIONAL OPERATING INFORMATION
1. Estimated pressure at the point and time of the Incident (psig):
1,280.00
2. Maximum Allowable Operating Pressure (MAOP) at the point and
1,440.00
time of the Incident (psig):
Added 10-2014 2a. MAOP established by 49 CFR section:
192.619(a)(1)
- If Other, specify:
3. Describe the pressure on the system or facility relating to the
Pressure did not exceed MAOP
Incident:
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
No
restriction with pressure limits below those normally allowed by the
MAOP?
- If Yes - (Complete 4a and 4b below)
4a. Did the pressure exceed this established pressure
restriction?
4b. Was this pressure restriction mandated by PHMSA or the
State?
5. Was "Onshore Pipeline, Including Valve Sites" OR "Offshore Pipeline,
Yes
Including Riser and Riser Bend" selected in PART C, Question 2?
- If Yes - (Complete 5a. – 5e. below):
5a. Type of upstream valve used to initially isolate release source:
Manual
5b. Type of downstream valve used to initially isolate release
Automatic
source:
5c. Length of segment isolated between valves (ft):
71,280
5d. Is the pipeline configured to accommodate internal inspection
Yes
tools?
- If 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
- If Other, Describe:
5e. For this pipeline, are there operational factors which
significantly complicate the execution of an internal inspection tool
No
run?
- If 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
- If Other, Describe:
5f. Function of pipeline system:
Transmission System
6. Was a Supervisory Control and Data Acquisition (SCADA)-based
Yes
system in place on the pipeline or facility involved in the Incident?
- If Yes:
6a. Was it operating at the time of the Incident?
Yes
6b. Was it fully functional at the time of the Incident?
Yes
6c. Did SCADA-based information (such as alarm(s), alert(s),
event(s), and/or volume or pack calculations) assist with the
Yes
detection of the Incident?
6d. Did SCADA-based information (such as alarm(s), alert(s),
event(s), and/or volume calculations) assist with the confirmation of
Yes
the Incident?
SCADA-based information (such as alarm(s), alert(s),
7. How was the Incident initially identified for the Operator?
event(s), and/or volume or pack calculations)
- If Other – Describe:
7a. If "Controller", "Local Operating Personnel, including
contractors", "Air Patrol", or "Ground Patrol by Operator or its
contractor" is selected in Question 7, specify:
8. Was an investigation initiated into whether or not the controller(s) or
No, the Operator did not find that an investigation of the
control room issues were the cause of or a contributing factor to the
controller(s) actions or control room issues was necessary
Incident?
due to: (provide an explanation for why the Operator did not
Form PHMSA F 7100.2

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 investigate)
- If 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)
- If Yes, Describe 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:

The control Room was not a suspected cause amd later
was determine not part of the cause of the lease.

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?
- If Yes:
1a. How many were tested:
1b. 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?
- If Yes:
2a. How many were tested:
2b. How many failed:

Yes

1
0
No

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).
G2 - Natural Force Damage

Apparent Cause:

G1 - Corrosion Failure - only one sub-cause can be picked from shaded left-hand column
Corrosion Failure – Sub-cause:
- If External Corrosion:
1. Results of visual examination:
- If Other, Describe:
2. Type of corrosion: (select all that apply)
- Galvanic
- Atmospheric
- Stray Current
- Microbiological
- Selective Seam
- Other
- If Other – Describe:
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
- If Other – Describe:
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 4. Was the failed item buried under the ground?
- If Yes:
4a. Was failed item considered to be under cathodic protection at
the time of the incident?
- If Yes, Year protection started:
4b. Was shielding, tenting, or disbonding of coating evident at the
point of the incident?
4c. Has one or more Cathodic Protection Survey been conducted
at the point of the incident?
If "Yes, CP Annual Survey" – Most recent year conducted:
If "Yes, Close Interval Survey" – Most recent year conducted:
If "Yes, Other CP Survey" – Most recent year conducted:
- If No:
4d. Was the failed item externally coated or painted?
5. Was there observable damage to the coating or paint in the vicinity of
the corrosion?
- If Internal Corrosion:
6. Results of visual examination:
- If Other, Describe:
7. Cause of corrosion (select all that apply):
- Corrosive Commodity
- Water drop-out/Acid
- Microbiological
- Erosion
- Other
- If Other, Describe:
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
- If Other, Describe:
9. Location of corrosion (select all that apply):
- Low point in pipe
- Elbow
- Drop-out
- Other
- If Other, Describe:
10. Was the gas/fluid treated with corrosion inhibitors or biocides?
11. Was the interior coated or lined with protective coating?
12. Were cleaning/dewatering pigs (or other operations) routinely
utilized?
13. Were corrosion coupons routinely utilized?
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?
14a. If Yes, for each tool used, select type of internal inspection tool and indicate most recent year run:
- Magnetic Flux Leakage Tool
Most recent year run:
- Ultrasonic
Most recent year run:
- Geometry
Most recent year run:
- Caliper
Most recent year run:
- Crack
Most recent year run:
- Hard Spot
Most recent year run:
- Combination Tool
Most recent year run:
- Transverse Field/Triaxial
Most recent year run:
- Other
Most recent year run:
If Other, Describe:
15. Has one or more hydrotest or other pressure test been conducted
since original construction at the point of the Incident?
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 - If Yes,
Most recent year tested:
Test pressure (psig):
16. Has one or more Direct Assessment been conducted on this
segment?
- If Yes, and an investigative dig was conducted at the point of the Incident:
Most recent year conducted:
- If Yes, but the point of the Incident was not identified as a dig site:
Most recent year conducted:
17. Has one or more non-destructive examination been conducted at
the point of the Incident since January 1, 2002?
17a. 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
Most recent year examined:
- Guided Wave Ultrasonic
Most recent year examined:
- Handheld Ultrasonic Tool
Most recent year examined:
- Wet Magnetic Particle Test
Most recent year examined:
- Dry Magnetic Particle Test
Most recent year examined:
- Other
Most recent year examined:
If Other, Describe:

G2 - Natural Force Damage - only one sub-cause can be picked from shaded left-handed column
Natural Force Damage – Sub-Cause:

Earth Movement, NOT due to Heavy Rains/Floods

- If Earth Movement, NOT due to Heavy Rains/Floods:
1. Specify:

Landslide
- If Other, Describe:

- If Heavy Rains/Floods:
2. Specify:
- If Other, Describe:

- If Lightning:
3. Specify:
- If Temperature:
4. Specify:
- If Other, Describe:

- If Other Natural Force Damage:
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
No
with an extreme weather event?
6a. If yes, specify: (select all that apply):
- Hurricane
- Tropical Storm
- Tornado
- Other
- If Other, Describe:

G3 - Excavation Damage only one sub-cause can be picked from shaded left-hand column
Excavation Damage – Sub-Cause:
- If 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?
1a. If Yes, for each tool used, select type of internal inspection tool and indicate most recent year run:
- Magnetic Flux Leakage
Year:
- Ultrasonic
Year:
- Geometry
Year:

Form PHMSA F 7100.2

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 - Caliper
Year:
- Crack
Year:
- Hard Spot
Year:
- Combination Tool
Year:
- Transverse Field/Triaxial
Year:
- Other:
Year:
Describe:
2. Do you have reason to believe that the internal inspection was
completed BEFORE the damage was sustained?
3. Has one or more hydrotest or other pressure test been conducted
since original construction at the point of the Incident?
- If Yes:
Most recent year tested:
Test pressure (psig):
4. Has one or more Direct Assessment been conducted on the pipeline
segment?
- If Yes, and an investigative dig was conducted at the point of the Incident:
Most recent year conducted:
- If Yes, but the point of the Incident was not identified as a dig site:
Most recent year conducted:
5. Has one or more non-destructive examination been conducted at the
point of the Incident since January 1, 2002?
5a. 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
Year:
- Guided Wave Ultrasonic
Year:
- Handheld Ultrasonic Tool
Year:
- Wet Magnetic Particle Test
Year:
- Dry Magnetic Particle Test
Year:
- Other
Year:
Describe:
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?
6a. If Yes, Notification received from (select all that apply):
- One-Call System
- Excavator
- Contractor
- Landowner
Complete the following mandatory CGA-DIRT Program questions if any Excavation Damage sub-cause is selected.
7. Do you want PHMSA to upload the following information to CGADIRT (www.cga-dirt.com)?
8. Right-of-Way where event occurred (select all that apply):
- Public
- If Public, Specify:
- Private
- If Private, Specify:
- Pipeline Property/Easement
- Power/Transmission Line
- Railroad
- Dedicated Public Utility Easement
- Federal Land
- Data not collected
- Unknown/Other
9. Type of excavator :
10. Type of excavation equipment :
11. Type of work performed :
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 12. Was the One-Call Center notified? - Yes - No
12a. If Yes, specify ticket number:
12b. If this is a State where more than a single One-Call Center
exists, list the name of the One-Call Center notified:
13. Type of Locator:
14. Were facility locate marks visible in the area of excavation?
15. Were facilities marked correctly?
16. Did the damage cause an interruption in service?
16a. If Yes, specify duration of the interruption: (hours)
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, then one predominant second level CGA-DIRT Root Cause as well):
- Predominant first level CGA-DIRT Root Cause:
- If One-Call Notification Practices Not Sufficient, Specify:
- If Locating Practices Not Sufficient, Specify:
- If Excavation Practices Not Sufficient, Specify:
- If Other/None of the Above, Explain:

G4 - Other Outside Force Damage - only one sub-cause can be selected from the shaded left-hand column
Other Outside Force Damage – Sub-Cause:
- If Damage by Car, Truck, or Other Motorized Vehicle/Equipment NOT Engaged in Excavation:
1. Vehicle/Equipment operated by:
- If 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
- If Other, Describe:
- If Previous Mechanical Damage NOT Related to Excavation: 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?
3a. If Yes, for each tool used, select type of internal inspection tool and indicate most recent year run:
- Magnetic Flux Leakage
Most recent year run:
- Ultrasonic
Most recent year run:
- Geometry
Most recent year run:
- Caliper
Most recent year run:
- Crack
Most recent year run:
- Hard Spot
Most recent year run:
- Combination Tool
Most recent year run:
- Transverse Field/Triaxial
Most recent year run:
- Other:
Most recent year run:
Describe:
4. Do you have reason to believe that the internal inspection was
completed BEFORE the damage was sustained?
5. Has one or more hydrotest or other pressure test been conducted
since original construction at the point of the Incident?
- If Yes:
Most recent year tested:
Test pressure (psig):
6. Has one or more Direct Assessment been conducted on the pipeline
segment?
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 - If Yes, and an investigative dig was conducted at the point of the Incident :
Most recent year conducted:
- If Yes, but the point of the Incident was not identified as a dig site:
Most recent year conducted:
7. Has one or more non-destructive examination been conducted at the
point of the Incident since January 1, 2002?
7a. 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
Most recent year conducted:
- Guided Wave Ultrasonic
Most recent year conducted:
- Handheld Ultrasonic Tool
Most recent year conducted:
- Wet Magnetic Particle Test
Most recent year conducted:
- Dry Magnetic Particle Test
Most recent year conducted:
- Other
Most recent year conducted:
Describe:
- If Intentional Damage:
8. Specify:
- If Other, Describe:
- If Other Outside Force Damage:
9. Describe:

G5 - Pipe, Weld, or Joint Failure

Use this section to report material failures ONLY IF the "Item Involved in
Incident" (from PART C, Question 3) is "Pipe" or "Weld."
Only one sub-cause can be selected from the shaded left-hand column

Pipe, Weld or Join Failure – Sub-Cause:
1. The sub-cause shown above is based on the following (select all that apply):
- Field Examination
- Determined by Metallurgical Analysis
- Other Analysis
- If "Other Analysis", Describe
- Sub-cause is Tentative or Suspected; Still Under Investigation
(Supplemental Report required)
- If Construction-, Installation- or Fabrication
2. List contributing factors: (select all that apply)
- Fatigue or Vibration related:
Specify:
- If Other, Describe:
- Mechanical Stress
- Other
- If Other, Describe:
- If Environmental Cracking-related:
3. Specify:
- If Other, Describe:
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
- Arc Burn
- Crack
- Lack of Fusion
- Lamination
- Buckle
- Wrinkle
- Misalignment
- Burnt Steel
- Other
- If Other, Describe:
Form PHMSA F 7100.2

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 5. Has one or more internal inspection tool collected data at the point of
the Incident?
5a. If Yes, for each tool used, select type of internal inspection tool and indicate most recent year run:
- Magnetic Flux Leakage
Most recent year run:
- Ultrasonic
Most recent year run:
- Geometry
Most recent year run:
- Caliper
Most recent year run:
- Crack
Most recent year run:
- Hard Spot
Most recent year run:
- Combination Tool
Most recent year run:
- Transverse Field/Triaxial
Most recent year run:
- Other
Most recent year run:
Describe:
6. Has one or more hydrotest or other pressure test been conducted since
original construction at the point of the Incident?
- If Yes:
Most recent year tested:
Test pressure (psig):
7. Has one or more Direct Assessment been conducted on the pipeline
segment?
- If Yes, and an investigative dig was conducted at the point of the Incident:
Most recent year conducted:
- If Yes, but the point of the Incident was not identified as a dig site:
Most recent year conducted:
8. Has one or more non-destructive examination(s) been conducted at
the point of the Incident since January 1,2002?
8a. 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
Most recent year conducted:
- Guided Wave Ultrasonic
Most recent year conducted:
- Handheld Ultrasonic Tool
Most recent year conducted:
- Wet Magnetic Particle Test
Most recent year conducted:
- Dry Magnetic Particle Test
Most recent year conducted:
- Other
Most recent year conducted:
Describe:

G6 - Equipment Failure - only one sub-cause can be selected from the shaded left-hand column
Equipment Failure – Sub-Cause:

- If Malfunction of Control/Relief Equipment:
1. Specify:
- Control Valve
- Instrumentation
- SCADA
- Communications
- Block Valve
- Check Valve
- Relief Valve

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 - Power Failure
- Stopple/Control Fitting
- Pressure Regulator
- ESD System Failure
- Other
- If Other, Describe:

- If Compressor or Compressor-related Equipment:
2. Specify:
- If Other, Describe:

- If Threaded Connection/Coupling Failure:
3. Specify:
- If Other, Describe:

- If Non-threaded Connection Failure:
4. Specify:
- If Other, Describe:

- If 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
- If Other, Describe:

G7 – Incorrect Operation - only one sub-cause can be selected from the shaded left-hand column
Incorrect Operation – Sub-Cause:

- If Underground Gas Storage, Pressure Vessel, or Cavern Allowed or Caused to Overpressure:
1. Specify:
- If Other, Describe:

- If 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:
- If Other, Describe:
4. What category type was the activity that caused the Incident:
5. Was the task(s) that led to the Incident identified as a covered task in
your Operator Qualification Program?
5a. If Yes, were the individuals performing the task(s) qualified for
the task(s)?

G8 - Other Incident Cause - only one sub-cause can be selected from the shaded left-hand column
Other Incident Cause – Sub-Cause:

- If Miscellaneous:
1. Describe:

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 - If Unknown:
2. Specify:

PART - H NARRATIVE DESCRIPTION OF THE INCIDENT
On June 7th, 2018, an unintended release event of natural gas (material) into atmosphere was reported to the National
Response center (NRC). This event took place on the Leach Express (LEX) pipeline that is operated and maintained by
Columbia Gas Transmission, LLC (Columbia). LEX Pipeline is a 36 inch in diameter and is classified as transmission
with a maximum allowable operating pressure of 1,440 psig. It is uni-directional flow line that starts from Majorsville
compressor station, West Virginia and terminates at the tie-in with R-System Regulator Station (Ohio). At 04:16 Eastern
Standard Time (EST), Columbia Gas Control personnel noted a low pressure SCADA alarm and Columbia Operations
personnel were dispatched to investigate the event. At 04:37 EST Columbia Monitoring Center received a call from the
Marshal County 911 regarding a pipeline failure in Marshal County, WV near WV State Route 21/1 (Nixon Ridge Road).
The failure is within valve section (VS) Mainline Valve LEX-500 to Mainline Valve LEX-600 (Isolated Segment). The
material ignited with limited damage occurred to vegetation and trees within the area of the pipeline failure site. No
structures were identified nearby failure site. No fatalities or injuries were reported in lieu of this pipeline failure. The
failed pipeline section was isolated approximately at 05:20 EST. The incident is under investigation and the failed
sections of the pipeline were sent to a Metallurgical Failure Analysis laboratory to determine the probable cause behind
the failure of the pipeline. The 48-hr update NRC was completed on June 8th, 2018 with Report No. 1214673. The
reportable incident is still under investigation and no probable cause has been identified by the time this report was
submitted.

PART I - PREPARER AND AUTHORIZED SIGNATURE
Preparer's Name
Preparer's Title
Preparer's Telephone Number
Preparer's E-mail Address
Preparer's Facsimile Number
Authorized Signature Title
Authorized Signature Telephone Number
Authorized Signature Email
Date

Kamran Rostami Asrabadi
Compliance Specialist
304-357-2351
kamran_rostami@transcanada.com
USRC East Manager
304-357-3728
george_hamaty@transcanada.com
07/02/2018

Form PHMSA F 7100.2

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