Incident details
Operator, cause, commodity and consequences with raw source fields.
GTG incident on 2014-10-15 — TX
Operator
Columbia Gas Transmission, Llc
Cause
Corrosion Failure
Commodity
Natural Gas
Program
GTG
Damage and Injuries
0 fatalities
0 injuries
Property damage (nominal)
$315,650
Incident datetime
2014-10-15 10:05
Report number
Location
TX
Narrative
On october 15, 2014, a contractor employed by columbia gas transmission, llc (columbia) was working on a near-by project, when he detected the odor of natural gas. Upon further investigations, a casing vent was tested for evidence of a non-hazardous natural gas leak inside a casing. Operations personnel were notified to assist in securing the site pending further assessment and necessary safety measures. The segment was isolated by columbia personnel and the line was blown down. Hence, the site was secured. Upon further investigation, a decision was made to replace the casing and the pipe with a pipe. Upon removal of the pipe, an external corrosion pit with 100 percent wall penetration was determined to be the cause of the unintended natural gas release. The corrosion pit was approximately 3.75 inches inside of the north end of the casing at the 5 o'clock position when facing north. The pit was at a location of damaged or missing coating. The damaged coating was located under the rubber casing isolator. Both rubber isolators and wooden centralizers were observed to be in use upon removal of the casing. However, the carrier pipe was not centered through the casing. Water marks were observed on both the carrier pipe and on the casing, indicating that the casing seals had been compromised and, at times, water had been present in the annular space. Water flowed out of the south side of the casing when the south side casing seal was exposed. No known soil conditions or measured potential readings commonly associated with microbiologically influenced corrosion or cathodic protection interference were observed. 1. The external corrosion pit occurred as a result of corrosion at the site of coating damage under the rubber casing isolator on the north side of the casing. 2. The coating damage likely occurred during installation of the casing or during a subsequent excavation of the casing ends. The wooden centralizers caused and/or exacerbated the coating damage. 3. The placement of the casing isolator over the area of damaged coating did not isolate the exposed steel from eventual electrolyte intrusion. With water being present between the casing seal and the pipe, atmospheric and crevice corrosion pitted the pipe to cause the leak. 4. The introduction of water as an electrolyte to the exposed steel created a localized corrosion cell under the rubber casing isolator. External corrosion occurred when the non-level casing filled with water completely to the north (high) side of the road and atmospheric corrosion occurred when the casing was not completely filled. 5. During the time when the casing was completely filled with water, the rubber casing isolator shielded the exposed steel from cathodic protection current that could have mitigated the corrosion cell during that time. During the time when atmospheric corrosion was occurring, only re-coating the exposed steel or maintaining dry conditions inside the casing could have mitigated the corrosion cell. Key lessons learned/corrective measures: 1) the nature and location of the corrosion pit that caused the leak makes it difficult, if not impossible, to detect during typical, non-excavation casing potential or short tests. Because the corrosion occurred in an electrically shielded area, the only reliable method for detection is the use of in-line inspection tools. Line r-701-n is in the process of being reconfigured for the purpose of running in-line inspection tools in the future. 2) there were no indicators for a low pipe-to-soil potential measurements for the pipeline in the area going back to 2008. Likewise, no casing-to-soil potential measurements indicated short testing was needed. 3) filling the annular space between the carrier pipe and the casing with a dielectric material removes the corrosive environment and can prevent corrosion from occurring. Filling of this casing could have prevented this leak.
Detailed record list
Report Received Date
2014-11-25 00:00:00
Iyear
2014
Report Number
20140128
Supplemental Number
17015
Report Type
Supplemental Final
Operator Id
2616
Name
Columbia Gas Transmission, Llc
Operator Street Address
700 Louisiana St. Suite 700
Operator City Name
Houston
Operator State Abbreviation
TX
Operator Postal Code
77002
Local Datetime
2014-10-15 12:12:00
Location Latitude
39.40228
Location Longitude
-82.51381
Nrc Rpt Num
1099737
Nrc Rpt Datetime
2014-10-30 10:40:00
Commodity Released Type
Natural Gas
Unintentional Release
2
Intentional Release
3745
Accompanying Liquid
0
Fatality Ind
No
Fatal
0
Injury Ind
No
Injure
0
Shutdown Due Accident Ind
Yes
Shutdown Datetime
2014-10-15 13:45:00
Restart Datetime
2014-10-19 05:30:00
Ignite Ind
No
Explode Ind
No
Num Pub Evacuated
0
Incident Identified Datetime
2014-10-15 10:05:00
On Site Datetime
2014-10-15 10:15:00
On Off Shore
Onshore
Onshore State Abbreviation
Oh
Onshore Postal Code
43135
Onshore City Name
Town Of South Bloomingville
Onshore County Name
Hocking County
Designated Location
Survey Station No.
Designated Name
918+56
Pipe Fac Name
Line R-701
Segment Name
Fairview Road
Federal
No
Location Type
Pipeline Right-Of-Way
Incident Area Type
Underground
Incident Area Subtype
Under Pavement
Depth Of Cover
93
Crossing
Yes
Road Crossing Ind
Yes
Road Type
Cased
Pipe Facility Type
Interstate
System Part Involved
Onshore Pipeline, Including Valve Sites
Item Involved
Pipe
Pipe Type
Pipe Body
Pipe Diameter
24
Pipe Wall Thickness
0.25
Pipe Smys
60200
Pipe Specification
5l
Pipe Seam Type
Dsaw
Pipe Manufacturer
Us Steel - National Tube
Pipe Coating Type
Coal Tar
Installation Year
1968
Manufactured Year
1968
Material Involved
Carbon Steel
Release Type
Leak
Leak Type
Pinhole
Class Location Type
Class 1 Location
Could Be Hca
No
Pir Radius
365
Heat Damage Ind
No
Non Heat Damage Ind
No
Hca Fatalities Ind
No
Est Cost Oper Paid
0
Est Cost Unintentional Release
8
Est Cost Intentional Release
14718
Est Cost Prop Damage
315650
Est Cost Emergency
0
Est Cost Other
0
Prpty
330376
Accident Psig
454
Mop Psig
750
Mop Cfr Section
192.619(A)(1)
Accident Pressure
Pressure Did Not Exceed Maop
Pressure Restriction Ind
No
Upstream Valve Type Ind
Manual
Downstream Valve Type Ind
Manual
Length Segment Isolated
31680
Internal Inspection Ind
No
Unsuitable Mainline Ind
Yes
Other Restrictions Ind
Yes
Operation Complications Ind
No
Pipeline Function
Transmission System
Scada In Place Ind
Yes
Scada Operating Ind
Yes
Scada Functional Ind
Yes
Scada Detection Ind
No
Scada Conf Ind
No
Accident Identifier
Ground Patrol By Operator Or Its Contractor
Operator Type
Contractor Working For The Operator
Investigation Status
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)
Investigation Status Details
Controller was not invovlved or had any role in identifying this non-hazardous leak inside the casing of the pipe
Employee Drug Test Ind
No
Contractor Drug Test Ind
No
Cause
Corrosion Failure
Cause Details
External Corrosion
Internal External
External Corrosion
Visual Exam Results
General Corrosion
Atmosphere Corrosion Ind
Yes
Field Exam Basis Ind
Yes
Underground Location
Yes
Under Cathodic Protection Ind
Yes
Cathodic Pro Start Year
1978
Shielding Evident
No
Cathodic Survey Type
No
Prior Damage
Yes
Collected Data Ind
No
Has Hydrtst Conduc Before Ind
No
Direct Asmnt Conducted
No
Non Destructive Exam Ind
No
Preparer Name
G***** H*****
Preparer Title
Engineer
Preparer Email
G******@c**.com
Preparer Telephone
(304)357-3728
Authorizer Name
P**** M* H******
Authorizer Title
Manager
Authorizer Telephone
(304)357-2548
Authorizer Email
M**********@c**.com
Narrative
On october 15, 2014, a contractor employed by columbia gas transmission, llc (columbia) was working on a near-by project, when he detected the odor of natural gas. Upon further investigations, a casing vent was tested for evidence of a non-hazardous natural gas leak inside a casing. Operations personnel were notified to assist in securing the site pending further assessment and necessary safety measures. The segment was isolated by columbia personnel and the line was blown down. Hence, the site was secured. Upon further investigation, a decision was made to replace the casing and the pipe with a pipe. Upon removal of the pipe, an external corrosion pit with 100 percent wall penetration was determined to be the cause of the unintended natural gas release. The corrosion pit was approximately 3.75 inches inside of the north end of the casing at the 5 o'clock position when facing north. The pit was at a location of damaged or missing coating. The damaged coating was located under the rubber casing isolator. Both rubber isolators and wooden centralizers were observed to be in use upon removal of the casing. However, the carrier pipe was not centered through the casing. Water marks were observed on both the carrier pipe and on the casing, indicating that the casing seals had been compromised and, at times, water had been present in the annular space. Water flowed out of the south side of the casing when the south side casing seal was exposed. No known soil conditions or measured potential readings commonly associated with microbiologically influenced corrosion or cathodic protection interference were observed. 1. The external corrosion pit occurred as a result of corrosion at the site of coating damage under the rubber casing isolator on the north side of the casing. 2. The coating damage likely occurred during installation of the casing or during a subsequent excavation of the casing ends. The wooden centralizers caused and/or exacerbated the coating damage. 3. The placement of the casing isolator over the area of damaged coating did not isolate the exposed steel from eventual electrolyte intrusion. With water being present between the casing seal and the pipe, atmospheric and crevice corrosion pitted the pipe to cause the leak. 4. The introduction of water as an electrolyte to the exposed steel created a localized corrosion cell under the rubber casing isolator. External corrosion occurred when the non-level casing filled with water completely to the north (high) side of the road and atmospheric corrosion occurred when the casing was not completely filled. 5. During the time when the casing was completely filled with water, the rubber casing isolator shielded the exposed steel from cathodic protection current that could have mitigated the corrosion cell during that time. During the time when atmospheric corrosion was occurring, only re-coating the exposed steel or maintaining dry conditions inside the casing could have mitigated the corrosion cell. Key lessons learned/corrective measures: 1) the nature and location of the corrosion pit that caused the leak makes it difficult, if not impossible, to detect during typical, non-excavation casing potential or short tests. Because the corrosion occurred in an electrically shielded area, the only reliable method for detection is the use of in-line inspection tools. Line r-701-n is in the process of being reconfigured for the purpose of running in-line inspection tools in the future. 2) there were no indicators for a low pipe-to-soil potential measurements for the pipeline in the area going back to 2008. Likewise, no casing-to-soil potential measurements indicated short testing was needed. 3) filling the annular space between the carrier pipe and the casing with a dielectric material removes the corrosive environment and can prevent corrosion from occurring. Filling of this casing could have prevented this leak.
| Report Received Date | 2014-11-25 00:00:00 |
|---|---|
| Iyear | 2014 |
| Report Number | 20140128 |
| Supplemental Number | 17015 |
| Report Type | Supplemental Final |
| Operator Id | 2616 PHMSA Enforcement |
| Name | Columbia Gas Transmission, Llc |
| Operator Street Address | 700 Louisiana St. Suite 700 |
| Operator City Name | Houston |
| Operator State Abbreviation | TX |
| Operator Postal Code | 77002 |
| Local Datetime | 2014-10-15 12:12:00 |
| Location Latitude | 39.40228 Google Maps OpenStreetMap |
| Location Longitude | -82.51381 Google Maps OpenStreetMap |
| Nrc Rpt Num | 1099737 NRC Report How to search |
| Nrc Rpt Datetime | 2014-10-30 10:40:00 |
| Commodity Released Type | Natural Gas |
| Unintentional Release | 2 |
| Intentional Release | 3745 |
| Accompanying Liquid | 0 |
| Fatality Ind | No |
| Fatal | 0 |
| Injury Ind | No |
| Injure | 0 |
| Shutdown Due Accident Ind | Yes |
| Shutdown Datetime | 2014-10-15 13:45:00 |
| Restart Datetime | 2014-10-19 05:30:00 |
| Ignite Ind | No |
| Explode Ind | No |
| Num Pub Evacuated | 0 |
| Incident Identified Datetime | 2014-10-15 10:05:00 |
| On Site Datetime | 2014-10-15 10:15:00 |
| On Off Shore | Onshore |
| Onshore State Abbreviation | Oh |
| Onshore Postal Code | 43135 |
| Onshore City Name | Town Of South Bloomingville |
| Onshore County Name | Hocking County |
| Designated Location | Survey Station No. |
| Designated Name | 918+56 |
| Pipe Fac Name | Line R-701 |
| Segment Name | Fairview Road |
| Federal | No |
| Location Type | Pipeline Right-Of-Way |
| Incident Area Type | Underground |
| Incident Area Subtype | Under Pavement |
| Depth Of Cover | 93 |
| Crossing | Yes |
| Road Crossing Ind | Yes |
| Road Type | Cased |
| Pipe Facility Type | Interstate |
| System Part Involved | Onshore Pipeline, Including Valve Sites |
| Item Involved | Pipe |
| Pipe Type | Pipe Body |
| Pipe Diameter | 24 |
| Pipe Wall Thickness | 0.25 |
| Pipe Smys | 60200 |
| Pipe Specification | 5l |
| Pipe Seam Type | Dsaw |
| Pipe Manufacturer | Us Steel - National Tube |
| Pipe Coating Type | Coal Tar |
| Installation Year | 1968 |
| Manufactured Year | 1968 |
| Material Involved | Carbon Steel |
| Release Type | Leak |
| Leak Type | Pinhole |
| Class Location Type | Class 1 Location |
| Could Be Hca | No |
| Pir Radius | 365 |
| Heat Damage Ind | No |
| Non Heat Damage Ind | No |
| Hca Fatalities Ind | No |
| Est Cost Oper Paid | 0 |
| Est Cost Unintentional Release | 8 |
| Est Cost Intentional Release | 14718 |
| Est Cost Prop Damage | 315650 |
| Est Cost Emergency | 0 |
| Est Cost Other | 0 |
| Prpty | 330376 |
| Accident Psig | 454 |
| Mop Psig | 750 |
| Mop Cfr Section | 192.619(A)(1) View CFR 49 §192 |
| Accident Pressure | Pressure Did Not Exceed Maop |
| Pressure Restriction Ind | No |
| Upstream Valve Type Ind | Manual |
| Downstream Valve Type Ind | Manual |
| Length Segment Isolated | 31680 |
| Internal Inspection Ind | No |
| Unsuitable Mainline Ind | Yes |
| Other Restrictions Ind | Yes |
| Operation Complications Ind | No |
| Pipeline Function | Transmission System |
| Scada In Place Ind | Yes |
| Scada Operating Ind | Yes |
| Scada Functional Ind | Yes |
| Scada Detection Ind | No |
| Scada Conf Ind | No |
| Accident Identifier | Ground Patrol By Operator Or Its Contractor |
| Operator Type | Contractor Working For The Operator |
| Investigation Status | 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) |
| Investigation Status Details | Controller was not invovlved or had any role in identifying this non-hazardous leak inside the casing of the pipe |
| Employee Drug Test Ind | No |
| Contractor Drug Test Ind | No |
| Cause | Corrosion Failure |
| Cause Details | External Corrosion |
| Internal External | External Corrosion |
| Visual Exam Results | General Corrosion |
| Atmosphere Corrosion Ind | Yes |
| Field Exam Basis Ind | Yes |
| Underground Location | Yes |
| Under Cathodic Protection Ind | Yes |
| Cathodic Pro Start Year | 1978 |
| Shielding Evident | No |
| Cathodic Survey Type | No |
| Prior Damage | Yes |
| Collected Data Ind | No |
| Has Hydrtst Conduc Before Ind | No |
| Direct Asmnt Conducted | No |
| Non Destructive Exam Ind | No |
| Preparer Name | G***** H***** |
| Preparer Title | Engineer |
| Preparer Email | G******@c**.com |
| Preparer Telephone | (304)357-3728 |
| Authorizer Name | P**** M* H****** |
| Authorizer Title | Manager |
| Authorizer Telephone | (304)357-2548 |
| Authorizer Email | M**********@c**.com |
| Narrative | On october 15, 2014, a contractor employed by columbia gas transmission, llc (columbia) was working on a near-by project, when he detected the odor of natural gas. Upon further investigations, a casing vent was tested for evidence of a non-hazardous natural gas leak inside a casing. Operations personnel were notified to assist in securing the site pending further assessment and necessary safety measures. The segment was isolated by columbia personnel and the line was blown down. Hence, the site was secured. Upon further investigation, a decision was made to replace the casing and the pipe with a pipe. Upon removal of the pipe, an external corrosion pit with 100 percent wall penetration was determined to be the cause of the unintended natural gas release. The corrosion pit was approximately 3.75 inches inside of the north end of the casing at the 5 o'clock position when facing north. The pit was at a location of damaged or missing coating. The damaged coating was located under the rubber casing isolator. Both rubber isolators and wooden centralizers were observed to be in use upon removal of the casing. However, the carrier pipe was not centered through the casing. Water marks were observed on both the carrier pipe and on the casing, indicating that the casing seals had been compromised and, at times, water had been present in the annular space. Water flowed out of the south side of the casing when the south side casing seal was exposed. No known soil conditions or measured potential readings commonly associated with microbiologically influenced corrosion or cathodic protection interference were observed. 1. The external corrosion pit occurred as a result of corrosion at the site of coating damage under the rubber casing isolator on the north side of the casing. 2. The coating damage likely occurred during installation of the casing or during a subsequent excavation of the casing ends. The wooden centralizers caused and/or exacerbated the coating damage. 3. The placement of the casing isolator over the area of damaged coating did not isolate the exposed steel from eventual electrolyte intrusion. With water being present between the casing seal and the pipe, atmospheric and crevice corrosion pitted the pipe to cause the leak. 4. The introduction of water as an electrolyte to the exposed steel created a localized corrosion cell under the rubber casing isolator. External corrosion occurred when the non-level casing filled with water completely to the north (high) side of the road and atmospheric corrosion occurred when the casing was not completely filled. 5. During the time when the casing was completely filled with water, the rubber casing isolator shielded the exposed steel from cathodic protection current that could have mitigated the corrosion cell during that time. During the time when atmospheric corrosion was occurring, only re-coating the exposed steel or maintaining dry conditions inside the casing could have mitigated the corrosion cell. Key lessons learned/corrective measures: 1) the nature and location of the corrosion pit that caused the leak makes it difficult, if not impossible, to detect during typical, non-excavation casing potential or short tests. Because the corrosion occurred in an electrically shielded area, the only reliable method for detection is the use of in-line inspection tools. Line r-701-n is in the process of being reconfigured for the purpose of running in-line inspection tools in the future. 2) there were no indicators for a low pipe-to-soil potential measurements for the pipeline in the area going back to 2008. Likewise, no casing-to-soil potential measurements indicated short testing was needed. 3) filling the annular space between the carrier pipe and the casing with a dielectric material removes the corrosive environment and can prevent corrosion from occurring. Filling of this casing could have prevented this leak. |
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