Pipeline Accident Report

Natural Gas Pipeline Rupture and Fire

Near Carlsbad, New Mexico

August 19, 2000

National 

Transportation 

Safety Board

Washington, D.C.

A

A

N TION

L TRA SPOR

ATIO

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B OARD

SAF E T Y

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E PLURIBUS UNUM 

NTSB/PAR-03/01

PB2003-916501

Pipeline Accident Report

Natural Gas Pipeline Rupture and Fire

Near Carlsbad, New Mexico

August 19, 2000

NTSB/PAR-03/01

PB2003-916501 National Transportation Safety Board

Notation 7310B 490 LíEnfant Plaza, S.W.

Adopted February 11, 2003 Washington, D.C. 20594
National Transportation Safety Board. 2003. Natural Gas Pipeline Rupture and Fire Near Carlsbad,

New Mexico, August 19, 2000. Pipeline Accident Report NTSB/PAR-03/01. Washington, D.C.

Abstract: At 5:26 a.m., mountain daylight time, on Saturday, August 19, 2000, a 30-inch-diameter natural

gas transmission pipeline operated by El Paso Natural Gas Company ruptured adjacent to the Pecos River

near Carlsbad, New Mexico. The released gas ignited and burned for 55 minutes. Twelve persons who

were camping under a concrete-decked steel bridge that supported the pipeline across the river were killed

and their three vehicles destroyed. Two nearby steel suspension bridges for gas pipelines crossing the river

were extensively damaged. According to El Paso Natural Gas Company, property and other damages or

losses totaled $998,296.

The major safety issues identified in this investigation are the design and construction of the pipeline, the

adequacy of El Paso Natural Gas Companyís internal corrosion control program, the adequacy of Federal

safety regulations for natural gas pipelines, and the adequacy of Federal oversight of the pipeline operator.

As a result of its investigation of this accident, the National Transportation Safety Board makes safety

recommendations to the Research and Special Programs Administration and NACE International.

The National Transportation Safety Board is an independent Federal agency dedicated to promoting aviation, railroad, highway, marine,

pipeline, and hazardous materials safety. Established in 1967, the agency is mandated by Congress through the Independent Safety Board

Act of 1974 to investigate transportation accidents, determine the probable causes of the accidents, issue safety recommendations, study

transportation safety issues, and evaluate the safety effectiveness of government agencies involved in transportation. The Safety Board

makes public its actions and decisions through accident reports, safety studies, special investigation reports, safety recommendations, and

statistical reviews.

Recent publications are available in their entirety on the Web at <http://www.ntsb.gov>. Other information about available publications also

may be obtained from the Web site or by contacting:

National Transportation Safety Board

Public Inquiries Section, RE-51

490 LíEnfant Plaza, S.W.

Washington, D.C. 20594

(800) 877-6799 or (202) 314-6551

Safety Board publications may be purchased, by individual copy or by subscription, from the National Technical Information Service. To

purchase this publication, order report number PB2003-916501 from:

National Technical Information Service

5285 Port Royal Road

Springfield, Virginia 22161

(800) 553-6847 or (703) 605-6000

The Independent Safety Board Act, as codified at 49 U.S.C. Section 1154(b), precludes the admission into evidence or use of Board reports

related to an incident or accident in a civil action for damages resulting from a matter mentioned in the report. 
iii Pipeline Accident Report

Contents

Executive Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . v

Factual Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

Accident Synopsis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

Accident Narrative . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

Emergency Response . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

Pipeline Operations After the Rupture . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

Postaccident On-Site Inspection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

Injuries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

Damages . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

Toxicological Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

Tests and Research . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

Metallurgical Examination . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

Corrosion Products . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

Pipeline 1103 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

Pipeline Features . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

Gas Suppliers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

Pigging Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

Tests and Inspections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

EPNGís Internal Corrosion Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

Internal Corrosion Control Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

Internal Audit Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

Regulatory Oversight . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

Federal Safety Standards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

Preaccident Federal Inspections of EPNG . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

Federal Safety Standards and EnforcementÊMaps and Records . . . . . . . . . . . . . . . . . 29

Postaccident Actions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

Pipeline Reconstruction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

Pipeline Integrity Management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

Federal Response . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

Pipeline Integrity ManagementÊFederal Regulations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

NACE Standards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

ASME Code for Gas Piping (B31.8) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

Guide for Gas Transmission and Distribution Piping Systems . . . . . . . . . . . . . . . . . . . . . . 36

Other Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

Previous EPNG Internal Corrosion Accident . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

Emergency Training and Simulations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38

Exclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38

Emergency Response . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39

Internal Corrosion in Steel Gas Pipelines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39

Internal Corrosion in Line 1103 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40

Physical Features of Line 1103 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

EPNG Internal Corrosion Control Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43
Contents iv Pipeline Accident Report

Federal Safety Regulations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46

Federal Oversight of the Pipeline Operator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46

Industry Standards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48

Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49

Findings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49

Probable Cause . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50

Recommendations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51

Appendixes

A: Investigation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53

B: Summary of Office of Pipeline Safety Corrective Action Order . . . . . . . . . . . . . . . . . . 54

C: Research and Special Programs Administration Advisory Bulletin . . . . . . . . . . . . . . . . 56
v Pipeline Accident Report

Executive Summary

At 5:26 a.m., mountain daylight time, on Saturday, August 19, 2000, a 30-inchdiameter natural gas transmission pipeline operated by El Paso Natural Gas Company

ruptured adjacent to the Pecos River near Carlsbad, New Mexico. The released gas ignited

and burned for 55 minutes. Twelve persons who were camping under a concrete-decked

steel bridge that supported the pipeline across the river were killed and their three vehicles

destroyed. Two nearby steel suspension bridges for gas pipelines crossing the river were

extensively damaged. According to El Paso Natural Gas Company, property and other

damages or losses totaled $998,296.

The National Transportation Safety Board determines that the probable cause of

the August 19, 2000, natural gas pipeline rupture and subsequent fire near Carlsbad, New

Mexico, was a significant reduction in pipe wall thickness due to severe internal

corrosion. The severe corrosion had occurred because El Paso Natural Gas Companyís

corrosion control program failed to prevent, detect, or control internal corrosion within the

companyís pipeline. Contributing to the accident were ineffective Federal preaccident

inspections of El Paso Natural Gas Company that did not identify deficiencies in the

companyís internal corrosion control program.

The major safety issues identified in this investigation are as follows:

ï The design and construction of the pipeline,

ï The adequacy of El Paso Natural Gas Companyís internal corrosion control

program,

ï The adequacy of Federal safety regulations for natural gas pipelines, and

ï The adequacy of Federal oversight of the pipeline operator.

As a result of its investigation of this accident, the National Transportation Safety

Board makes safety recommendations to the Research and Special Programs

Administration and NACE International.

1 Pipeline Accident Report

Factual Information

Accident Synopsis

At 5:26 a.m., mountain daylight time, on Saturday, August 19, 2000, a 30-inchdiameter natural gas transmission pipeline operated by El Paso Natural Gas Company

(EPNG) ruptured adjacent to the Pecos River near Carlsbad, New Mexico. The released

gas ignited and burned for 55 minutes. Twelve persons who were camping under a

concrete-decked steel bridge that supported the pipeline across the river were killed and

their three vehicles destroyed. Two nearby steel suspension bridges for gas pipelines

crossing the river were extensively damaged. According to EPNG, property and other

damages or losses totaled $998,296.

Accident Narrative

The EPNG pipeline system (figure 1) transported gas west from Texas and New

Mexico to Arizona and California. A portion of the pipeline system crossed the Pecos

River about 4 1/2 miles north of the Texas-New Mexico State line and 30 miles south of

Carlsbad, New Mexico. (See figure 2.) About 1 mile west of the river crossing was the

Pecos River compressor station, which received gas from four natural gas transmission

pipelines26-inch-diameter line 1100, 30-inch-diameter line 1103, 30-inch-diameter line

1110, and 16-inch-diameter line 3191. Three of these lines (1100, 1103, and 1110) ran

parallel to Whitethorn Road (also known as Pipeline Road) from the Pecos River to the

Pecos River compressor station. Lines 1103 and 1110 were supported at the river crossing

by a one-lane concrete-decked steel service bridge that was not open to the public. (See

figure 3.) (This bridge, which had been built by EPNG in 1950, also supported a water

pipeline and a gas gathering pipeline. EPNG, which was at the time of the accident a

subsidiary of El Paso Energy, owned and operated the water pipeline but not the gas

gathering pipeline.) Line 1100 was supported across the river on a pipeline suspension

bridge approximately 70 feet northeast of the service bridge. Another EPNG pipeline, 16-

inch-diameter line 1000, was supported by a separate suspension bridge in this area, but

this line had been removed from service and was filled with nitrogen at the time of the

accident. The fourth pipeline, line 3191, ran from EPNGís South Carlsbad compressor

station to the Pecos River compressor station.
Factual Information 2 Pipeline Accident Report

Figure 1. El Paso Natural Gas system.

Figure 2. Accident area.
Factual Information 3 Pipeline Accident Report

At the time of the accident, 12 members of an extended family were camping on

the east bank of the Pecos River near the service bridge.1 (See figure 4.) A locked wire

rope and a ìPrivate Right of WayNo Trespassingî sign at each entrance to the bridge

restricted access to the bridge above the campsite. Two ìCautionHigh Pressure Gas

Lineî signs were posted near the east entrance to the service bridge. Also, a sign reading

as follows:

Warning - No Trespassing - This road and right of way is private property and is

not for public use. This pipeline carries natural gas under high pressure and is

dangerous. All persons are warned of the danger to person and property. KEEP

OFF 

had been posted alongside the right-of-way road (near the intersection with the county

road) leading past the block valves and pig receivers to the service bridge on the east side

of the river.The pipeline system was operated from EPNGís gas control center in El Paso,

Texas, as a north system and a south system. The gas control center was equipped with

three supervisory control and data acquisition (SCADA)2

 system work consoles, each of

which was capable of displaying data for both pipeline systems.

On the morning of August 19, 2000, three EPNG employees, a coordinator of

pipeline control (who was in charge of the shift) and two gas controllers, were nearing the

Figure 3. Accident site.

1 At the time of the accident, a private landowner owned the accident site. After the accident, EPNG

purchased this property and installed fencing to restrict access to the area.

2 Pipeline controllers use a computer-based SCADA system to remotely monitor and control

movement of gas through pipelines. The system makes it possible to monitor operating parameters critical to

pipeline operations, such as flow rates, pressures, equipment status, control valve positions, and alarms

indicating abnormal conditions.
Factual Information 4 Pipeline Accident Report

end of their 12-hour shifts at the gas control center. One of the controllers was operating

the north system and the other the south, while the coordinator assisted the two controllers

and performed administrative oversight and served as a backup controller when needed.

The two controllers were working at separate SCADA terminals to monitor and control

pipeline operations. The employees said they had noted no unusual operating conditions

during their shift, and no unusual conditions had been noted during the previous 12-hour

shift.

The south system controller, at 5:26 a.m.,3

 received SCADA rate-of-change4

alarms for the speed of compressor unit No. 3 at the Pecos River compressor station.5 Less

than a minute later, compressor unit No. 1 at the station shut down, quickly followed by

the automatic closing and opening of station valves, as appropriate, to isolate the

compressor station from the pipeline. Emergency lubricating oil pumps were also

automatically activated at the station. A few seconds later, additional alarms from the

station displayed on the controllerís monitor, including a rate-of-change alarm for falling

Figure 4. Aerial view of accident site looking east.

3 Times in this section are based on SCADA event data recorder records, controller logs, and personnel

statements and interviews.

4 Rate-of-change alarms indicate that a measured variable, such as compressor speed or compressor

suction pressure, is increasing or decreasing at a rate exceeding what would be expected under normal

operating conditions.

5 The unattended Pecos River compressor station had three turbine compressors.
Factual Information 5 Pipeline Accident Report

suction (inlet) pressure at the station. (Unknown to the controller at the time, pressure on

the inlet side of the station dropped because pipeline 1103 had ruptured near the river

crossing.) Noting the alarms, the south controller began to request SCADA data for the

Pecos River compressor station instead of waiting for the data to appear from the

automatic data scans, which occurred at 4-minute intervals.6

At about this time, the transmission of SCADA data between the gas control center

and the Pecos River compressor station was briefly interrupted. According to the south

controller, he was immediately alerted to the data interruption by the display of inverse

video on his SCADA monitor. Inverse video indicated that a proper reply to a request for

data from the SCADA system had not been received and that the displayed data were not

being updated. Although not recorded in the SCADA system event log, this interruption

lasted about 30 seconds.

At approximately 5:30 a.m., the controller telephoned the Pecos River district

station lead operations specialist7 at home and asked him to send people to the Pecos River

compressor station. The south controller later stated:

I noted that we did have a low suction pressure, and generally when our plants go

down, the suction pressure goes up instead of down. I told [the station lead

operations specialist], ëWe need to get somebody out there right away because I

think we have a problem.í

The station lead operations specialist called two operations specialists that he

supervised and who were on duty and told them to go to the Pecos River compressor

station.

About the same time the station lead operations specialist was making this call, an

EPNG operations specialist from the Carlsbad complex, who was at his home south of the

city of Carlsbad, noticed a glow in the sky to the south. (See figure 5.) He said he

immediately suspected that an EPNG pipeline may be involved. He called the gas control

center and asked if its personnel had noticed any sudden pressure changes at the Pecos

River compressor station. He told center personnel of the glow in the sky and said that he

suspected a rupture. The north controller informed him that EPNG had lost a compressor

at the Pecos River compressor station.

The operations specialist then telephoned his supervisor (the pipeline lead

operations specialist), and informed him of the glow in the sky and of his call to the gas

control center. He then told the pipeline lead operations specialist that he was on his way

to the Pecos River compressor station.

6 This SCADA system logged operational data and transferred it to the gas control center via modem.

7 EPNG had two employees in the Pecos River district with the official title ìlead operations

specialist.î One lead operations specialist supervised operations specialists responsible for operating and

maintaining compressor and meter stations. Another lead operations specialist supervised operations

specialists responsible for operating and maintaining pipelines. This report refers to the two employees,

respectively, as the station lead operations specialist and the pipeline lead operations specialist.
Factual Information 6 Pipeline Accident Report

At 5:31 a.m., the gas control center in El Paso again experienced an interruption in

SCADA data transmission from the Pecos River compressor station, which prevented the

controllerís receiving any additional information from the station. The interruption

occurred when the emergency shutdown system at the Pecos River compressor station

activated, which caused a loss of power to the local SCADA computer and modem. The

station was equipped with an uninterruptible power supply, but the station SCADA

computer and modem were not connected to it.8

 SCADA communications with the Pecos

River compressor station were restored at 9:04 a.m. on August 19.

At 5:35 a.m., the south controller again telephoned the station lead operations

specialist at home and told him that he suspected a possible line blowout. At this time, the

south controller did not know which pipeline was involved. The station lead operations

specialist said that after looking out a window of his home in the direction of the Pecos

River compressor station, he told the south controller that he could see a fire and that he

was on his way to the Pecos River compressor station.

Figure 5. Post-rupture fire. At lower left of fireball can be seen the 85-foot-tall support 

structures for the pipeline suspension bridges. 

8 The station was equipped with an uninterruptible power supply to maintain AC power to the station

computer and hazardous gas and fire detection equipment. A 24-volt DC backup system maintained power

to oil pumps, nozzle cooling water equipment, and other emergency equipment in the event of a station

power failure.
Factual Information 7 Pipeline Accident Report

At 5:44 a.m., the south controller called the Keystone compressor station9 and

asked the operator to take down three compressor units. About a minute later, he called the

Eunice plant10 and made the same request.

At 5:50 a.m., the south controller called El Paso Field Services to make sure that

personnel there would shut down all compressor units at the South Carlsbad compressor

station.11 The south controllerís shift ended at 6:00 a.m., but he stayed at the gas control

center until 8:00 a.m. to provide assistance as necessary. During this time, he notified the

El Paso Energy public relations department in Houston, Texas.12

Emergency Response

Within 5 minutes of the rupture, at 5:31 a.m., the local 911 operator received

numerous calls from residents reporting a fire and the sound of an explosion. An off-duty

EPNG employee who lived near the site also called 911 and reported the fire. The gas

control center was called by an off-duty operations specialist when he saw light in the sky

from the fire, and he also called the pipeline lead operations specialist for the local section

of the pipeline.

That pipeline lead operations specialist was the first to arrive at the accident site, at

about 5:45 a.m. He said that while he was en route, he had spoken with the gas control

center and the EPNG general dispatcher from his truck and had asked the control center to

call managers for the Jal and Carlsbad complexes. He recalled that as he neared the Pecos

River compressor station, the fire was so bright that he had trouble seeing the road.

He then went to the pipeline on the west side of the Pecos River compressor station

and began closing valves that were downstream from the fire. As he closed block (shutoff)

valve No. 6 3/4 on line 1100, the operations specialist who had telephoned him earlier

arrived, and the two men closed block valves No. 6 3/4 on lines 1103 and 1110. They also

closed the pig launcher valves on these pipelines.13

The pipeline lead operations specialist and the operations specialist then drove

their trucks to the west side of the service bridge and viewed the fire across the river, but

9 The Keystone compressor station, an attended station about 57 miles east and upstream of the Pecos

River compressor station, supplied gas to the Pecos River compressor station through lines 1103 and 1110.

10 The Eunice plant, an attended station about 53 miles northeast and upstream of the Pecos River River

station, supplied gas to the Pecos River compressor station through line 1100.

11 The South Carlsbad compressor station, an attended station about 25 miles north and upstream of the

Pecos station, supplied gas to the Pecos River compressor station through line 3191.

12 Notifying the public relations department, which was responsible for responding to inquiries

regarding events involving the company, was part of EPNGís emergency response procedures.

13 Pig refers to any of a variety of mechanical devices that can be introduced into a pipeline system

either to clean the pipeline or, through use of various detection technologies, to identify possible pipeline

defects. Pig launchers and pig receivers in lines 1100, 1103, and 1110 at the time of the accident were used

only for cleaning pigs.
Factual Information 8 Pipeline Accident Report

they could not determine which line had ruptured. The pipeline lead operations specialist

said he then told the operations specialist to go around to the other side of the river and

attempt to determine which line had failed.

The operations specialist said he drove across the river at the low-water crossing

and viewed the scene, but because of the proximity of the lines to one another and the fire,

he could not determine which line had ruptured. The operations specialist said that as he

was returning to where he left the pipeline lead operations specialist, he thought he may

have seen vehicles in the fire area just south of the bridge. He continued back across the

river to assist the pipeline lead operations specialist and also told him about the possibility

of vehicles in the fire area. The pipeline lead operations specialist said he told the

operations specialist that they had to get the fire contained and that until that time, there

was nothing they could do. Both employees knew community emergency responders were

waiting at the entrance of the compressor station.

The two men then drove toward the low-water crossing, proceeding down the

right-of-way road toward the fire. The pipeline lead operations specialist later recalled that

when they arrived at the location where they were going to try to close the block valves

upstream of the fire, he carefully opened the door of his truck to confirm that he could

tolerate the heat. About 6:05 a.m., the two employees left their vehicles and proceeded to

the block valves. The pipeline lead operations specialist closed the No. 5 valve on line

1100, but closing this valve did not reduce the intensity of the fire. Together they closed

block valve No. 6 on line 1103, and the operations specialist closed block valve No. 6 on

line 1110. The fireís intensity was noticeably reduced after valve No. 6 on line 1103 was

closed, but the fire continued to burn at the lowered intensity. The pipeline lead operations

specialist told the operations specialist to check the bypass valve on the pig receiver14 on

line 1103 and after it was closed, the fire subsided altogether over a period of several

minutes. At about 6:21 a.m., the pipeline lead operations specialist called the gas control

center and reported the status of the valves and that the fire was out.

The pipeline lead operations specialist then told the operations specialist to go

back to the west side of the river and prevent traffic from entering the area. The operations

specialist said that as he passed where he thought he may have seen the vehicles during the

fire, he now clearly saw burned pickup trucks. He stopped and called the pipeline lead

operations specialist to tell him there were casualties. The pipeline lead operations

specialist then notified his supervisor and told him to call for more ambulances.

The operations specialist took a first-aid kit from his truck and started down on

foot to check on survivors. At this time, the station lead operations specialist pulled up

behind his truck. He knew where the operations specialist was because he had been

monitoring radio traffic. After the two men discussed the situation, the operations

specialist went to assist the victims while the station lead operations specialist drove back

to where he knew fire and emergency medical personnel were waiting. He then led an

ambulance to the fire area. The pipeline lead operations specialist said he drove to the

14 The pig receiver is an arrangement of pipe and valves connected to the pipeline that allows a pig to

be removed from the pipeline.
Factual Information 9 Pipeline Accident Report

location of the No. 6 3/4 block valves and, with the assistance of two other EPNG

employees, closed a valve that double-blocked line 1110 (to prevent gas from entering the

station in case one of the block valves on the line was leaking).

The station pipeline specialist had been called by the gas control center as soon as

the Pecos River compressor station shut down at about 5:30 a.m. to determine if the

problem was at the station. When he arrived at the entrance road to the compressor station

off Whitethorn Road at about 6:10 a.m., he met the two operations specialists he had

telephoned earlier and saw the Loving Fire Department vehicles on Whitethorn Road at

the entrance driveway to the compressor station. He turned into the entrance road, entered

the compressor station, and went to the control room to inspect the equipment. He said he

knew that power was off at the station because no lights were available in the control

room. He said that the automatic emergency shutdown system had vented gas from the

station, shut off electrical service, and started the battery-powered cool-down pumps on

the compressors. He and the two operations specialists then crossed the road to the 3191

block valve for the South Carlsbad line. This valve was just outside the east fence of the

compressor station where line 3191 connects to lines 1103 and 1110. They finished

closing the block valve at about 6:16 a.m., thereby isolating the South Carlsbad

compressor station from the Pecos River station and from lines 1103 and 1110. The station

lead operations specialist telephoned the gas control center and informed personnel there

that the valve was closed and that the South Carlsbad compressor station should be taken

off line. The station lead operations specialist sent the other two employees back to

Whitethorn Road to help with crowd control as needed.

At about 5:51, the first emergency responders arrived on scene and staged on

Whitethorn Road where the driveway into the Pecos River compressor station intersects

the road. Additional emergency responders also staged at this location, which is about 3/4

mile from the accident site. The Carlsbad Fire Departmentís medic units had responded to

the initial call and proceeded as far as the Pecos River compressor station. They remained

there until an ambulance was directed to the victims and EPNG employees admitted the

smaller fire vehicles.15 When one of the fire engines entered the unpaved road from the

west during the fire before the No. 6 block valves were closed, the station lead pipeline

operations specialist stopped them from going farther. He told fireman to stand by while

he shut more valves. As police cars arrived at that location, he told them to go back to the

railroad tracks and let only EPNG vehicles or vehicles with flashing red lights through.

Emergency vehicles were admitted as needed to the accident scene after the fire at the

ruptured line was out.

The victims were camped about 675 feet from the crater, between the crater and

the river. Emergency personnel located victims with the assistance of the operations

specialist. Six victims were found at the camping area; six others had gone into the river

and were either in the river or had been assisted to the banks by the operations specialist.

Paramedics and emergency medical technicians worked to treat the injuries. Volunteer

15 The station lead operations specialist was concerned that the larger fire fighting equipment would

become stuck on the sandy access road.
Factual Information 10 Pipeline Accident Report

firefighters and the crews of Carlsbad medic units then evacuated the six victims to

hospital burn centers in Texas. None of the victims survived.

The New Mexico State Police responded to the accident and assumed

responsibility for emergency management of the incident. Police personnel also provided

support to Safety Board personnel during the on-scene investigation. EPNG reported the

accident to the National Response Center at 8:27 a.m.

Pipeline Operations After the Rupture

EPNG gas controllers called gas suppliers to inform them of the problem and to

request that gas supplies into the affected part of the EPNG system be reduced or

suspended due to the incident and the immediate need to shut in all three lines. While only

one pipeline ruptured, two other pipelines (1100 and 1110) near the rupture site were shut

down and inspected for damage. All compressors at Keystone compressor station ìAî

plant, as well as Unit 3 at the Keystone compressor station ìBî plant, which had been

delivering gas toward the Pecos River, were off by 6:25 a.m.

Meanwhile, the gas control center was in the process of rebalancing the south

pipeline system to compensate for the isolated Pecos River compressor station. At about

6:10 a.m., the gas control center directed personnel at the Washington Ranch storage

facility16 to stop injecting gas into the storage field and to begin withdrawing gas from the

field. Withdrawing gas from storage allowed EPNG to continue to send gas west.

Postaccident On-Site Inspection

The force of the rupture and the violent ignition of the escaping gas created a 51-

foot-wide crater about 113 feet along the pipe. A 49-foot section of the pipe was ejected

from the crater in three pieces measuring approximately 3 feet, 20 feet, and 26 feet in

length. (See figure 6.) The largest piece was found about 287 feet northwest of the crater

in the direction of the suspension bridges. Investigators visually examined the pipeline

that remained in the crater as well as the three ejected pieces. All three ejected pieces

showed evidence of internal corrosion damage, but one of the pieces showed significantly

more corrosion damage than the other two. Pits were visible on the inside surface of this

piece, and at various locations, the pipe wall evidenced significant thinning. At one

location, a through-wall perforation was visible. No significant corrosion damage was

visible on the outside surfaces of the three pieces or on the two ends of the pipeline

remaining in the crater. Pieces were cut from the ruptured pipeline segments and shipped

to the Safety Boardís Materials Laboratory in Washington, D.C., for further evaluation.

(That evaluation is discussed in the ìTests and Researchî section of this report.)

16 Washington Ranch storage facility, an attended facility about 24 miles west and downstream of the

Pecos River compressor station, received and delivered gas through lines 1100, 1103, and 1110.
Factual Information 11 Pipeline Accident Report

The drip17 between block valve No. 6 and the rupture site was removed from the

pipeline and visually examined. The drip was found to contain a blackish oilypowdery/grainy material. At the area of its heaviest concentration, about 13 feet from the

drip opening, this material filled approximately 70 percent of the cross-sectional area of

the drip. No significant material was observed in the area just underneath and several

inches away from the siphon drain at the closed end of the drip. No significant internal

corrosion was observed in the drip.

Injuries

All 12 persons who were camping on the east bank of the Pecos River were fatally

injured in the accident. The causes of death were extensive thermal burns, carbon

monoxide poisoning, and smoke inhalation. (See table 1).

Figure 6. Looking west at a portion of the crater created by the rupture. The missing 

section of pipe between the arrows was ejected from the crater.

17 The drip (described in more detail later in this report) was a 40-foot-long stub line that branched off

the bottom of the gas pipeline. The drip was designed to collect liquids and solids that may have built up in

the pipeline during normal transportation of gas or after pigging operations.
Factual Information 12 Pipeline Accident Report

Table 1. Injuries

Damages 

Approximately 49 feet of the underground portion of line 1103 were ejected in

three pieces from the crater created by the rupture. Two of the pieces of pipe were thrown

234 and 287 feet, respectively, from the northwest end of the crater toward the river. One

of these pieces hit the cables that supported the pipeline suspension bridges across the

river. The concrete anchor blocks for the cables, the cables themselves, and the two

suspension bridge steel structures on the east side of the river were burned, as were the

aboveground portions of the pipelines. The two pipelines that were being supported on the

bridges (EPNGís 26-inch line 1100 and the out-of-service 16-inch line 1000) fell and

came to rest on the ground on each side of the river, but neither leaked. The three vehicles

and camping equipment on the east side of the river were destroyed, and vegetation along

both riverbanks was burned. Based on photographs taken of the fire as it engulfed the

suspension bridges, the height of the flame was calculated to be about 496 feet. EPNG, in

its incident report to the Research and Special Programs Administration (RSPA), stated

the cost of the accident was $998,296.

Toxicological Information

Specimens for drug testing were collected from the controllers and the coordinator

on Sunday, August 20. The EPNG substance testing contractor, Behavioral Training

Institute, Inc., performed the collections and forwarded the specimens to Universal

Toxicology Laboratories in Midland, Texas. The results were reviewed by a medical

review officer at SurgiMed, P.A., in El Paso, Texas. Tests were negative for the tested

drugs.18

Injury Type Public Employees Total

Fatal 12 0 12

Serious 0 0 0

Minor 0 0 0

Total 12 0 12

49 Code of Federal Regulations (CFR) 830.2 defines fatal injury as ìany injury which results in death within 30 days of 

the accidentî and serious injury as ìan injury which: (1) requires hospitalization for more than 48 hours, commencing 

within 7 days from the date the injury was received; (2) results in a fracture of any bone (except simple fractures of 

fingers, toes, or nose); (3) causes severe hemorrhages, nerve, or tendon damage; (4) involves any internal organ; or 

(5) involves second- or third-degree burns, or any burn affecting more than 5 percent of the body surface.î

18 Specimens were tested for marijuana, cocaine, opiates, amphetamines, and phencyclidine (PCP).
Factual Information 13 Pipeline Accident Report

Tests and Research

Metallurgical Examination

On-site examination of the three pieces of pipe that were ejected from the crater at

the rupture site identified severe internal corrosion along the interior bottom of the pipe.

(See figure 7.) From these three segments, eight pieces were excised and transported to the

Safety Boardís Materials Laboratory in Washington, D.C., for further examination. The

examination of these pieces revealed no evidence of corrosion on the outside of the pipe or

the internal surface across the top half of the pipe (between the 9 and 3 oíclock positions

looking downstream/west). Severe wall loss due to corrosion was observed on the inside

of the pipe at the bottom.

The area of corrosion damage extended 21 feet 5 inches. Sections of the girth

(circumferential) and seam (longitudinal) welds that were in the bottom half of the pipe

exhibited damage from internal corrosion similar to that found on the bottom pipe wall.

The extent of corrosion damage (metal loss and number of pits) was most severe along the

bottom of the pipe; the most severely corroded area reduced the original pipe wall

thickness by 72 percent. (See figure 8.) The wall of many of the corrosion pits contained

striations that extended around the pit. (See figure 9.) Within this length of corrosion

damage were five circumferential wrinkles19 in the pipe wall on the top of the pipe.

Figure 7. Fractured section of line 1103.

19 A wrinkle is a smooth fold in the pipe wall that may have a single inward or single outward

displacement or that may include a sinusoidal waveform with both inward and outward displacements. The

five wrinkles in this pipe were outward deflections of the pipe wall.
Factual Information 14 Pipeline Accident Report

Figure 8. Corrosion pitting on inside of pipe near rupture site.

Figure 9. Microscopic view of corrosion pit showing striations
Factual Information 15 Pipeline Accident Report

Examination of the fractures showed that a fracture face extended between the

internal corrosion areas and the external wall of the pipe. The fracture faces resulted from

overstress separation with no evidence of fatigue cracking or corrosion degradation,

indicating that corrosion had not penetrated the wall of the pipe at the rupture point. 

Corrosion Products

The Safety Boardís Materials Laboratory performed x-ray dispersive spectroscopy

analysis on material removed from corrosion pits and areas containing corrosion damage,

both from the inside of the pipe. The analysis found high levels of chlorine and sodium in

the material.

After the accident, corrosion products, deposits, and liquid samples were collected

from various locations in the EPNG transmission system and subjected to chemical and

microbial analysis. Sample collection locations included the Pecos River and Keystone

compressor station inlet scrubbers, the line 1103 drip, the line 1103 pig receiver at valve

No. 6, and the line 1100 pig receiver at valve No. 5. Anaerobic bacteria were present in all

deposit/corrosion product samples, and aerobic bacteria were present in 9 of 11 samples;

sulfate-reducing bacteria were detected in 18 of 22 individual tests (10 of 11 samples), and

acid-producing bacteria were detected in 10 of 22 individual tests (7 of 11 samples). The

chemical analysis indicated the presence of chlorides in all samples. Chloride

concentrations exceeding 9,000 parts per million (ppm) were detected in three of four

samples obtained from Line 1103. One of these three samples, obtained from the line 1103

pig receiver, showed a chloride concentration of 333,000 ppm, or roughly 33 percent of

the sample. The fourth sample, collected from the line 1103 drip at a point away from the

siphon drain, showed a chloride concentration of less than 50 ppm.

Samples taken from corrosion pits detected in line 1103 after the accident at a low

point in the pipeline (about 2,080 feet downstream of the rupture site) showed positive

reactions for all four types of bacteria (sulfate-reducing, acid-producing, anaerobic, and

aerobic). At this location, the pipe contained a circumferential wrinkle across the top half

of the pipe and corrosion on the internal surface of the bottom of the pipe.

Additional chemical and microbial tests were conducted by EPNG on samples

collected from various transmission facilities. These data showed the presence of

acid-producing bacteria in all samples obtained from the corrosion pit areas.

Concentrations greater than 10,000 cells/ml of acid-producing bacteria were observed in 9

out of 13 samples obtained from various pit areas. Only 1 out of these 13 samples showed

microbial concentration less than 10 cells/ml. Chloride levels of less than 100 ppm were

observed in 26 of 85 samples. Chloride levels greater than 1,000 ppm were observed in 34

of 85 sludge/deposit samples. The highest observed chloride level was 400,000 ppm.

Chemical analyses showed that the pH of the liquid collected at the Pecos River

compressor station plant inlet separator scrubber was 6.7 to 6.8. The pH of the liquid

collected at the Keystone compressor station inlet scrubber was 8.2. For the material

collected at the line 1100 and 1103 pig receivers, the pH level was 6.2 to 6.3. The pH of

the inside material collected from a low spot on line 1103 west of the rupture was 6.4.
Factual Information 16 Pipeline Accident Report

Analysis of the material collected near the siphon drain area of the line 1103 drip showed

a pH of 8.9.

Chlorides were observed in all corrosion product/deposit samples. The

morphology of corrosion damage located away from the bottom of the ruptured pipe

appeared similar to water line corrosion.

Pipeline 1103

At the time of the accident, EPNG operated more than 10,000 miles of natural gas

transmission pipelines involving 59 compressor stations and plants and more than 300

compressor units. The company operated three of the four in-service gas pipelines at the

Pecos River crossing, including line 1103, the pipeline that ruptured in this accident.

The section of pipeline 1103 between the Keystone compressor station and the

Pecos River compressor station was constructed in 1950 with pipe purchased from

Republic Steel that had been manufactured in accordance with American Petroleum

Institute standard 5LX, High-Test Line Pipe (first edition, 1948). The pipe was 30-inch

outside diameter (OD), grade X52 (specified minimum yield strength of 52,000 psi20) pipe

with a nominal wall thickness of 0.335 inch, with sections of heavier wall pipe at locations

such as road crossings and block valve assemblies. The longitudinal seam weld in the pipe

was a double submerged arc weld. The pipeline was cathodically protected, and the

coating was coal-tar wrap.

The pipeline was operating at approximately 675 pounds per square inch, gauge

(psig), at the time of the accident. The maximum allowable operating pressure from

Keystone compressor station to the Pecos River compressor station had been established

by EPNG at 837 psig.21

Pipeline Features

Valves. Block valves were spaced along line 1103 between the Keystone and

Pecos River compressor stations at intervals ranging from 1 mile to 19.2 miles. From the

rupture location, block valve No. 6 at the pig receiver was the closest upstream/east valve

(0.25 mile), and block valve No. 6 1/2 at the Pecos River compressor station was the

closest downstream/west valve (0.85 mile).

When pigging facilities, including the pig receiver, were installed in the mid1970s, the valve then designated block valve No. 6 (a 30-inch gate valve) became the

receiver isolation valve. A new plug valve was installed in the bypass around the pig

20 Although yield strength is expressed in pounds per square inch, this number is an expression of the

pipe material strength value, which is not equivalent to a pipeís internal pressure.

21 Equivalent to a stress level of 72 percent of specified minimum yield strength in the 0.335-inch-wallthickness pipe.
Factual Information 17 Pipeline Accident Report

receiver and was designated block valve No. 6. Block valve No. 6 was 0.25 mile

upstream/east of the rupture site.

Line 1103 was cross-connected with other lines upstream of the rupture site as

follows:

ï Lines 1103 and 1110 were cross-connected in three places between the

Keystone and Pecos River compressor stations upstream/east of the rupture

site.

ï Lines 1103 and 1100 were cross-connected between block valve No. 6 and the

line 1103 drip.

Crossover to Line 1100. About 720 feet downstream/west of block valve No. 6, a

16-inch OD crossover (branch line with valves) cross-connected lines 1103 and 1100. The

crossover was installed during the original construction of the pipeline. Line 1100 was

equipped with a drip until 1989, at which time the drip was found to be ìcompletely full of

solidified black solids & oilî and was removed. No internal corrosion was observed.

Line 1103 Drip Assembly. About 990 feet downstream/west of block valve No. 6

was a drip, a liquid collection leg buried beneath the pipeline that consisted of about 40

feet of 30-inch pipe. (See figure 10.) The leg was buried approximately 7 feet directly

below the gas pipeline and sloped downward toward a dead end equipped with a siphon

drain. The leg functioned to collect liquids and solids during normal transportation or after

pigging operations. Also at this location was a liquid storage tank consisting of a 4,620-

gallon aboveground steel tank installed within a concrete dike. The siphon drain in the

liquid collection leg of the drip assembly emptied into this tank. (See figure 11.) The tank

was fitted with piping and valves for loading the collected liquids into a truck for disposal.

The drip assembly was installed during the original construction of the pipeline. Because

of the location and design of this drip, cleaning pigs could not be run in the section of

pipeline that ruptured. After the removal of the line 1100 drip in 1989, liquids and solids

moving down line 1100 toward the Pecos River compressor station during both normal

operations and pigging operations in line 1100 could enter line 1103 upstream of the drip.

Pecos River Crossing. About 2,025 feet downstream/west of block valve No. 6

was a steel bridge with a single-lane concrete service road spanning approximately 430

feet across the Pecos River. Pipeline 1103 rested on, and was strapped to, horizontal steel

support members off the side of the north bridge girders.

Gas Suppliers

Line 1103. In addition to receiving gas from the Keystone compressor station, line

1103 had been connected to and received gas from other gas suppliers beginning in 1979.

Seven receipt points existed between the Keystone and Pecos River compressor stations

where gas flowed into the line for periods ranging from 6 months to 21 years, but at the

time of the accident, only one active supplier, an interstate transmission pipeline, was

connected to line 1103.
Factual Information 18 Pipeline Accident Report

Line 1110. In addition to the gas entering line 1110 from its connection with line

1103, two receipt points flowed gas into line 1110 beginning in 1979 for periods of 14

years and 21 years, respectively. At the time of the accident, only one active supplier, the

same interstate transmission pipeline connected to line 1103, was connected to line 1110.

Line 1100. In addition to the gas entering line 1100 from the EPNGís Eunice plant,

25 receipt points flowed gas into line 1100 beginning in 1949 for periods ranging from 1

1/2 years to 51 years. At the time of the accident, 11 active suppliers were connected to

line 1100.

Pigging Operations

When pigging facilities were added to line 1103 about 25 years after initial

construction, a pig launcher was installed at block valve No. 2 approximately 10.5 miles

downstream/west of the Keystone compressor station, and a pig receiver was installed at

block valve No. 6. At the time of the accident, the line could be pigged from block valve

No. 2 to block valve No. 6. The line was pigged to remove solids and liquids that had

collected in the pipeline. According to EPNG, when possible, cleaning pigs were run a

minimum of twice per year.

Figure 10. Line 1103 drip after excavation.
Factual Information 19 Pipeline Accident Report

Figure 11. Diagram of line 1103 drip.
Factual Information 20 Pipeline Accident Report

There was no pig launcher at block valve No. 6 and no pig receiver at Pecos River

compressor station. For that reason, and because of a reduced port valve22 and other

pipeline features, including the drip, in the section of the pipeline between block valve No.

6 and the Pecos River compressor station, that portion of the pipeline (which included the

rupture location) could not be pigged.

At the time of the accident, the design of the pipeline was such that liquids and

solids not caught at the pig receiver at block valve No. 6 would continue downstream past

the block valve assembly to the drip downstream/west of the block valve. EPNG officials

said gas pressure in the drip was used to blow the material out of the drip after each

pigging operation, causing the materials to move to the adjacent, aboveground storage

tank for later removal by truck. This tank was also used in conjunction with the drip on

line 1110. Officials said that in addition to being emptied after a pigging operation, drips

were blown on the 1st and 17th of each month, although the company did not keep records

of blowdowns.

According to EPNG, material that remained in the pig receiver after a pigging

operation was blown into a dirt pit through a 6-inch pipe off the bottom of the pig receiver

near the closure. This 6-inch pipe also connected to an identical 6-inch pipe, which was

used to blow down the adjacent line 1110 pig receiver into the same disposal pit. After

about 1975, the 6-inch blowdown piping to the disposal pit was taken out of service. A

concrete basin was installed below the closure at the end of the pig receiver, and pigging

residue was removed from the pig receiver via the closure and transferred to portable

fiberglass containers for disposal. There were no drain lines or liquid storage legs

connected to the pig receiver, as the downstream drip served to collect the pig liquids.

In the 3 years before the accident, line 1103 was pigged from near block valve No.

2 to block valve No. 6 four times in 1997, three times in 1998, once in 1999, and once in

2000 before the accident. Records for each pig run noted ìno solids/liquids reported,î

except for the 1999 cleaning, for which ì2100 lbs solid/2 barrels oilî was reported. In

2001, EPNG notified both RSPA and the Safety Board that the 1999 report of ì2100 lbsî

was more likely ì20 lbs.î

According to EPNG officials, fluids and sludge recovered after the pigging

operations were sent to the EPNG laboratory in El Paso, Texas, and analyzed for

hazardous components before disposal. Results of the analysis were provided to the

complex manager and to the environmental compliance engineer responsible for the

complex. Test results were also provided to the principal coordinator, corrosion services,

and retained at the laboratory. The materials were not tested to determine if they were

potentially corrosive to the pipeline. The laboratory superintendent for the EPNG

chemistry laboratory stated that samples from pigging and other inspections had water

concentrations ranging from trace amounts (less than 1 percent) to 10 percent.

22 The opening in a reduced port valve is smaller than the actual valve size, which prevents a pig from

passing through the valve. For example, the passage through a 30-inch valve could be a 24-inch-diameter

opening.
Factual Information 21 Pipeline Accident Report

At the Pecos River compressor station, four inlet scrubbers removed liquids from

the gas stream entering the station from lines 1100, 1103, and 1110. The collected liquids

were analyzed in the same manner as pig liquids. The materials were not tested to

determine if they were potentially corrosive to the pipeline.

In July 1997, because of a recent rupture of line 1300 due to internal corrosion,

EPNG conducted an in-line inspection (using a ìsmart pigî internal inspection tool) of a

70-mile section of line 1300. According to EPNG, this inspection found no areas of

internal corrosion requiring repair, but a visual inspection of the pipeline in the immediate

area of the rupture found an area of internal corrosion, which was repaired. In June and

July 1998, 33 miles of line 1103 and 33 miles of line 1100, which included a segment of

pipe in which a rupture had recently occurred, were inspected with an in-line inspection

tool. The inspected segments of lines 1100 and 1103 were downstream of the Pecos River

compressor station. No areas of internal corrosion requiring repair were discovered. In

February 2000, EPNG conducted in-line inspections of 33 miles of lines 3133/3137

upstream of Goldsmith Plant in Texas. No areas of internal corrosion requiring repair were

discovered.

Tests and Inspections

The line 1103 right-of-way had most recently (before the accident) been inspected

on August 11, 2000, by aerial patrol and on August 18, 2000, by ground patrol. Inspectors

looked for evidence of leaks (such as discolored soil or dying vegetation), erosion, and

excavation near the pipeline. No leaks were reported.

Before the accident, the segment of line 1103 between the Pecos River and

Keystone compressor stations had never been internally inspected, nor had it been

pressure-tested except for two segments, totaling approximately 0.9 mile located

approximately 46 miles upstream of the rupture location, that had been hydrostatically

tested.23

EPNGís Internal Corrosion Program

According to EPNG, before the accident, the company monitored and mitigated

internal corrosion by controlling the quality of gas entering the pipeline, by visually

inspecting the inside of exposed pipe (and, under certain conditions, performing an

ultrasound test to determine pipe wall thickness), by running cleaning pigs through the

pipeline to remove liquids, and by blowing down the drips to remove the liquids and to

verify that the drips were functioning properly. EPNG officials stated that they believed

that line 1103 was not transporting corrosive gas because the line was receiving ìpipeline

23 Current Federal regulations require that gas pipelines be pressure-tested before being placed in

service. These requirements did not exist when line 1103 was constructed, and when the regulations were

issued later, the requirements for pressure-testing did not apply to existing pipelines.
Factual Information 22 Pipeline Accident Report

qualityî gas and that unusual conditions, such as water in the pipeline, were not being

observed at the pig receiver or the drip on line 1103.

Gas quality standards were contained in EPNGís contracts with its gas suppliers

but were not referenced in the companyís corrosion control procedures. Some interconnect

locations had gas quality monitoring, which either closed a valve to stop the flow of gas

into the transmission pipeline or alarmed in the gas control center if the limit of any

specified contaminant was exceeded. Not all contaminants were monitored at each

monitoring location.

For line 1103, gas quality monitoring was installed in the discharge of the

Keystone compressor station, at the suction to the Pecos River compressor station, and at

the receipt point with the interstate transmission pipeline approximately 17 miles

downstream/west of the Keystone compressor station. This interconnect location had an

automatic closing valve (referred to as a ìslam valveî) actuated by high levels of

hydrogen sulfide (H2S), and an alarm actuated by high levels of carbon dioxide (CO2). No

slam valves or alarms were installed at any of the other receipt locations in line 1103

between the Keystone and Pecos River compressor stations.

EPNG was not able to provide water vapor data for line 1103 at the discharge from

the Keystone compressor station for 19 months between 1998 and 2000.24 At this same

location, records showed that moisture monitoring instrument readings remained

unchanged from July 10 to 16, 1992; October 1 to 18, 1994; August 13 to 25 and 27 to 30,

1998. The moisture monitoring instrument at the Pecos River compressor station inlet also

showed unchanged readings from July 11 to 17, 1991; June 16 to July 26, 1994; June 28 to

July 28 and August 1 to 25, 1996. Similarly, moisture monitoring instruments at the Pecos

River compressor station inlet for lines 1100 and 1110 showed periods of unchanged

readings.

For line 1110, gas quality monitoring was installed in the suction to the Pecos

River compressor station and at the receipt point with the interstate transmission pipeline

approximately 17 miles downstream/west of the Keystone compressor station. This

interconnect location had a slam valve actuated by high levels of H2S and an alarm

actuated by high levels of CO2. At the other receipt location on line 1110 between

Keystone and Pecos River compressor stations, there was a slam valve actuated by high

levels of H2S and an alarm actuated by high levels of CO2.

For line 1100 between Eunice plant and the Pecos River compressor station, gas

quality monitoring was installed on the suction to the Pecos River compressor station.

Two of the 26 receipt locations between Eunice plant and the Pecos River compressor

station had slam valves actuated by high levels of H2S and alarms actuated by high levels

of CO2. In the event of an alarm, gas control center personnel notified the pipeline

location supervisor and a technician would be called out to investigate. The remaining

receipt locations were not equipped with slam valves or alarms.

24 EPNG officials advised the Safety Board that they believed that the monitoring instrumentation was

working, but that the data were not recorded electronically.
Factual Information 23 Pipeline Accident Report

EPNG officials said that at other locations, its personnel periodically (at 1- to 6-

month intervals) sampled and analyzed the gas entering the pipeline. There were no

written requirements that corrosion technicians follow up on reports of out-ofspecification gas being received or identify the effect, if any, of this gas on the pipeline.

Corrosion coupons25 or corrosion monitoring devices were not used in this section of line

1103 because, officials said, the gas was not believed to be corrosive. EPNG did not inject

any corrosion inhibitors into line 1103. The program did not require that ultrasonic testing

be performed on the low points of the non-piggable portions of line 1103, and none was

performed before the accident. According to EPNG, visual inspections of line 1103 in the

area of the Keystone and Pecos River compressor stations that were exposed during

operations or maintenance activities before the accident had not shown evidence of

internal corrosion. 

Internal Corrosion Control Procedures

Procedures in Effect Before the Accident. Although at the time of the accident,

EPNG was in the process of implementing updated internal corrosion procedures

(discussed below), the companyís internal corrosion control program in the period leading

up to the rupture was governed by its Operating and Maintenance Procedures manual.

Section 201.2, ìCorrosion Control,î dated September 20, 1999, prescribed the minimum

company requirements for monitoring and protecting metallic structures. The indicated

references were 49 Code of Federal Regulations (CFR) 192.451 through 192.491, which

include Federal regulations regarding internal corrosion. Most of Section 201.2 related to

external corrosion. Requirements for an internal corrosion program were as follows:

If corrosive gas is transported or if internal corrosion is found, Corrosion Services

will recommend the appropriate corrective action and establish an internal

corrosion monitoring program to determine the effectiveness of mitigation

programs. Internal corrosion mitigation will continue until monitoring and testing

determines that the source of corrosion has been removed or other corrective

actions have rendered the gas stream non-corrosive. Internal monitoring will be

performed at least twice each calendar year, but with intervals not to exceed 7 1/2

months. Additional monitoring will be performed if necessary. A Remedial

Action Form will be completed if internal corrosion is discovered on any portion

of the pipeline or ancillary components and vessels containing natural gas.

Each time a pipeline or station pipe segment is exposed for any reason, the coating

and pipe will be evaluated and documented. Whenever any pipe is removed from

a pipeline, it shall be inspected for internal corrosion. If internal corrosion is

found, the adjacent pipe must be investigated to determine its extent and

appropriate measures taken as detailed in these procedures.

25 A corrosion coupon is a small piece of metal with a specially prepared surface for measuring

corrosion rates. Corrosion coupons may be inserted into the pipeline during pipeline operations to help

operators assess the potential for internal corrosion or to evaluate the effectiveness of corrosion mitigation

efforts.
Factual Information 24 Pipeline Accident Report

The procedures did not address the factors that should be considered in

determining whether the gas being transported could cause corrosion. The company stated

that the companyís gas quality standard, set forth in its contracts, addressed several

contaminants, including water, CO2, H2S, and oxygen (O2), but the corrosion control

procedures did not reference these contaminants or their acceptable limits. In the event

that it was determined that corrosive gas was being transported or internal corrosion was

occurring, corrosion-mitigation actions would be taken. But the procedures did not detail

how technicians were to carry out semi-annual monitoring to determine if the corrosion

mitigation measures were effective. The procedures did not provide guidance regarding

how internal corrosion would be detected other than through visual inspection of a pipe

segment after it had been removed.

Procedures in Effect at the Time of the Accident. EPNG acquired Tenneco

Energy in December 1996 and formed El Paso Energy Corporation. In January 2000, El

Paso Energy Corporation acquired Sonat, Inc., another natural gas pipeline company.26 El

Paso Energy Corporation then assembled teams of representatives from each pipeline

company and tasked them with establishing best practices and producing a common

operating and maintenance manual. This new manual was issued on May 15, 2000. The

new Corrosion Control Manual, which detailed the requirements for internal corrosion

control and monitoring, was issued on July 10, 2000.

The section of the Corrosion Control Manual applicable to internal corrosion

control was Section 700, ìInternal Corrosion Control.î The applicable sections of the

Operating and Maintenance Procedures manual were Sections 308.1, ìCorrosion,

General and Records,î and 308.3, ìInternal Corrosion Control.î References included in

these sections were 49 CFR 192.453, 192.475, and 192.477, which address Federal

requirements for internal corrosion control and monitoring.

Section 308.3 of the manual required that gas and liquids be tested to determine if

they are corrosive and required further steps to minimize the possibility of internal

corrosion. Section 700 of the Corrosion Control Manual included a statement that quality

standards for gas and liquids entering the pipeline represent the first line of defense

against internal corrosion and noted that only by regular monitoring and analysis can it be

determined if a pipeline is carrying corrosive gas. Detailed descriptions in section 700 for

sampling procedures indicate that sampling and analysis of gas, liquids, and solids

removed from the pipeline is required.

Section 700 also contained a discussion of corrosive constituents in gas streams;

listed the companyís typical gas and liquid quality standards, velocity standards, and

corrosion coupon and inhibitor guidelines; schedules for pipeline liquid, gas, and solid

sampling; and requirements for preservation of evidence after a leak or failure. Also noted

in the documents was that water and other corrosives may enter the pipeline by accident or

may gradually accumulate in low spots despite gas quality monitoring that shows

26 After acquiring Coastal Corporation in January 2001, El Paso Energy Corporation became El Paso

Corporation. The El Paso Corporation pipeline system now consists of more than 46,000 miles of gas

transmission pipelines.
Factual Information 25 Pipeline Accident Report

adherence to quality standards. It also included the basic regulatory requirements that

corrosive gas may not be transported by pipeline unless the effect of the gas on the

pipeline has been investigated and steps have been taken to minimize internal corrosion;

that the internal surface of a pipeline be inspected whenever the pipe is exposed and

opened; and that coupons or other means be used to determine the effectiveness of the

steps taken to minimize internal corrosion.

Before July 10, 2000, the EPNG operating and maintenance standards did not

address the relationship of flow velocity to liquid accumulation in a pipeline. The

Corrosion Control Manual dated July 10, 2000, included a velocity standards subsection

that stated the velocity of wet gas (defined as gas containing more water vapor than the

amount specified, typically 7 pounds of water per million standard cubic feet of gas) in a

pipeline must be limited to avoid solids-erosion or erosion-corrosion. The procedure

required that consideration be given to flow patterns in the pipeline when evaluating liquid

transported by gas. Flow patterns were described for velocities less than 7.5 feet per

second (dormant pools in a dry gas stream occur), 7.5 to 15 feet per second (agitated pools

and minor spray occur), 15 to 25 feet per second (continuous stream along the bottom of

the pipe, small agitated pools, and spray occur), and greater than 25 feet per second (no

liquids, only spray occurs).

Gas velocity data provided by EPNG for the period 1991 to 2001 indicates that gas

velocities in line 1103 ranged from 2 to 33 feet per second. Typical velocities ranged from

a low of 2 to 7 feet per second to a high of 15 to 23 between 1993 and 2000, with

velocities as high as 33 feet per second in 1991 and 1992.

At the time of the rupture, El Paso Energy was in the process of implementing the

July 10, 2000, corrosion procedures in Section 700 of the Corrosion Control Manual and

had conducted a training session for corrosion technicians in El Paso during the first week

of August 2000. Other personnel assigned corrosion control responsibilities were

scheduled for training at a later date.

After the accident, EPNG revised the sections of the Operating and Maintenance

Procedures and the Corrosion Control Manual that affect internal corrosion control.

EPNGís current manual (Corrosion Control Manual, Section 6, effective

December 31, 2001) states ìidentification of corrosive gas in a pipeline is achieved by

analysis of operating conditions, gas impurity content, monitoring data, mitigation

schemes, and/or other considerationsî and that ìan effective internal corrosion-monitoring

program includes sampling and analysis of liquid, gas and solid materials.î

Internal Audit Program

EPNGís Quality Assurance Auditing Procedures Manual (February 4, 1999,

revised March 3, 1999) describes the companyís internal audit program. For internal

corrosion, the pipeline and plant/stations sections of the manual have a section entitled

ìCorrosion ControlñInternal Coupons.î Answers to the following questions are required

for the audit:
Factual Information 26 Pipeline Accident Report

Is corrosive gas being transported? If so, has the effect of the gas on the pipeline

been investigated? What steps have been taken to minimize internal corrosion?

Corrosion inhibitor? Dehydration? Have internal coupons been installed to

monitor the effectiveness of the corrosion-mitigating program? If so, are the

coupons checked two times each calendar year at intervals not exceeding 7-1/2

months? Is the mil loss per year acceptable?

Preprinted forms were provided in the manual for the auditor to record the results

of an internal audit. For pipelines, these forms did not list the internal corrosion items

identified in the audit questions or provide a space for the auditor to document the results

of the internal corrosion portion of the audit.

An EPNG senior safety staff member who conducted internal audits told

investigators that auditors relied on the location manager/superintendent to tell them

whether or not corrosive gas was being transported through the pipeline. This employee

stated that he was aware that gas quality specifications existed, but he did not know what

they were or what EPNG would consider to be corrosive gas per these specifications. In

September 1996, EPNGís line 1300 ruptured because of internal corrosion. The senior

safety staff member stated that previous internal audits had not found indications that

internal corrosion may be occurring in line 1300 or that the use of corrosion coupons or

other monitoring methods were needed in the line. In addition, he stated that after the

rupture of line 1300, the internal audit program was not revised.

Regulatory Oversight

Federal Safety Standards

RSPA promulgates regulations that establish minimum standards for the

transportation of natural gas by pipeline. The regulations for internal corrosion control for

gas transmission pipelines in effect at the time of the accident are in 49 CFR Part 192,

ìTransportation of Natural and Other Gas by Pipeline: Minimum Federal Safety

Standards,î as follows:

Subpart L, 192.605 Procedural manual for operations, maintenance, and

emergencies

Each operator shall include the following in its operating and maintenance plan:

(a) General. Each operator shall prepare and follow for each pipeline, a manual of

written procedures for conducting operations and maintenance activities and for

emergency response. For transmission lines, the manual must also include

procedures for handling abnormal operations. This manual must be reviewed and

updated by the operator at intervals not exceeding 15 months, but at least once

each calendar year. This manual must be prepared before operations of a pipeline

system commence. Appropriate parts of the manual must be kept at locations

where operations and maintenance activities are conducted.
Factual Information 27 Pipeline Accident Report

(b) Maintenance and normal operations. The manual required by paragraph (a) of

this section must include procedures for the following, if applicable, to provide

safety during maintenance and operations.

(1) Operating, maintaining, and repairing the pipeline in accordance

with each of the requirements of this subpart and Subpart M of this

part.

(2) Controlling corrosion in accordance with the operations and

maintenance requirements of Subpart I of this part.

Subpart I, 192.453 General:

The corrosion control procedures required by ß192.605(b)(2), including those for

the design, installation, operation, and maintenance of cathodic protection

systems, must be carried out by, or under the direction of, a person qualified in

pipeline corrosion control methods.

192.475 Internal corrosion control: General:

Corrosive gas may not be transported by pipeline, unless the corrosive effect of

the gas on the pipeline has been investigated and steps have been taken to

minimize internal corrosion.

Whenever any pipe is removed from a pipeline for any reason, the internal surface

must be inspected for evidence of corrosion. If internal corrosion is found, (1) The

adjacent pipe must be investigated to determine the extent of internal corrosion;

(2) Replacement must be made to the extent required by the applicable paragraphs

of ßß192.485, 192.487 or 192,489; and, (3) Steps must be taken to minimize the

internal corrosion.

Gas containing more than 0.25 grain of hydrogen sulfide per 100 standard cubic

feet (5.8 milligrams/m3) at standard conditions (4 parts per million) may not be

stored in pipe-type or bottle-type holders.

Subpart I, 192.477 Internal corrosion control: Monitoring:

If corrosive gas is being transported, coupons or other suitable means must be

used to determine the effectiveness of the steps taken to minimize internal

corrosion. Each coupon or other means of monitoring internal corrosion must be

checked two times each calendar year, but with intervals not exceeding 7 1/2

months.

The Federal pipeline safety regulations do not include design, construction,

operating, or maintenance requirements that address the relationship of water and

corrosive contaminants to internal corrosion in a gas pipeline.
Factual Information 28 Pipeline Accident Report

Preaccident Federal Inspections of EPNG

From June 1990 to August 1998, RSPAís Office of Pipeline Safety (OPS)

conducted 18 safety inspections of EPNG. Inspections were conducted using a questionand-answer format. Four of these inspections were performed by personnel from the

Arizona State Corporation Commission, as an agent for the OPS for interstate pipelines.

For each of these 18 inspections, compliance with the internal corrosion control

regulations was noted as ìsatisfactoryî or, for items associated with corrosion coupons,

ìN/Aî (not applicable). These inspections were based on an inspection form that typically

had six questions related to internal corrosion: (1) Are corrosion control procedures

established? (2) Are these procedures under the responsibility of a qualified person? (3)

Have coupons been utilized and checked at least twice annually, not to exceed 7.5

months? (4) Is gas tested to determine corrosive properties? (5) Whenever a pipe segment

is removed from a pipeline, is it examined for evidence of internal corrosion? (6)

Remedial action (if required) to minimize internal corrosion? In each of the inspections,

ìsatisfactoryî was entered in response to question 4 regarding testing the gas for corrosive

properties.

In December 1998, the OPS launched a 3-year pilot program designated the

ìsystem integrity inspection pilot program.î EPNG applied for the program in February

1999, and after reviewing EPNGís qualifications, the OPS accepted EPNG into the

program in April 2000. The system integrity inspection pilot program demonstration

period expired at the end of 2001, at which time the program was terminated by the OPS.

EPNG remained in the program until that time. The pilot program was an attempt by the

OPS to develop a method by which the agency could ensure that a pipeline operator had

an effective, compliance-driven internal audit plan and that the plan was effectively

implemented. The program was intended to improve communication and informationsharing between operators and Government and to focus resources on the most important

risks to pipeline safety.

From July 1999 to September 2000, the OPS conducted eight safety inspections of

EPNG under the system integrity inspection pilot program. For each of these eight

inspections, compliance with the internal corrosion control regulations was noted as

ìsatisfactoryî or ìN/A.î There were four internal corrosion related questions on the

inspection report form used for six inspections, and they all were noted ìsatisfactoryî: (1)

Does the company maintain a comprehensive corrosion control program and associated

records? (2) Is the companyís corrosion program under the direction of a qualified person,

with associated records? (3) Are corrosion control procedures in place and do they follow

Part 192/National Association of Corrosion Engineers (NACE)/industry standards, with

associated records? (4) How is the gathered information reviewed and analyzed?

Associated records? OPS memos summarizing several of these inspections noted that

EPNGís internal audit program was working as designed.

One of these eight inspections was a joint team operation and maintenance

procedures inspection conducted in April 2000. The form used for this inspection included

four questions related to internal corrosion. The first was for the operatorís procedure for

internal corrosion control coupon monitoring (rated ìSatisfactoryî); the second was for
Factual Information 29 Pipeline Accident Report

the operatorís procedure for corrosion remedial measures (rated ìSatisfactoryî); the third

was for the records of the coupon monitoring (rated ìNot Applicableî); and the fourth was

for records of the corrosion control remedial measures (rated ìNot Applicableî). There

were no questions or subject areas on the inspection record related to transporting

corrosive gas, the training of internal corrosion control personnel, or the qualifications of

the person directing the internal corrosion control program, as required by 49 CFR

192.453. The OPS summary of this inspection did not identify any deficiencies in internal

corrosion monitoring and control or personnel training. Before August 2000, there were

no enforcement actions against EPNG for its internal corrosion program.

After the accident, the OPS revised the inspection form to include more detailed

questions about internal corrosion. The revised form27 has the following written guidance

for the inspector:

ï Proper procedures for transporting corrosive gas?

ï Is pipe inspected for internal corrosion? If found: is adjacent pipe inspected? Is pipe

replaced if required? Are steps taken to minimize internal corrosion?

ï Internal corrosion control coupon monitoring (2 times per year / 7 1/2 months)

ï The operator should maintain a comprehensive internal corrosion control program that

includes the following (Best Practice):

ï Sufficient fluid sample locations throughout their system for monitoring for corrosive

elements.

ï Does the operator have established threshold limits for various corrosive compounds

in their procedures?

ï Has the operator identified low points throughout their system where fluids are likely

to accumulate and does the operator identify how to remove the fluids from the lines?

ï Does the operator specify the frequency in how often the fluids are removed?

ï Does the operator address fluid accumulation in unpiggable lines? (i.e., fluid samples,

coupons, etc.) (Note: Refer to Advisory Bulletin ADB-00-02, 8/29/00; Internal

Corrosion of Gas Pipelines).

Federal Safety Standards and EnforcementMaps and Records

The Federal regulations for construction records, maps, and operating history for

gas transmission pipelines in effect at the time of the accident are in 49 CFR Part 192,

Subpart L, 192.605, Procedural Manual for Operations, Maintenance, and Emergencies,

which includes the following:

 (b) Maintenance and normal operations: The manual required by paragraph (a) of

this section must include procedures for the following, if applicable, to provide

safety during maintenance and operations:

(1) ....

27 OPS Form-1 (192-90), ìEvaluation Report of Gas Transmission Pipeline,î (Revised 2/01/02 through

amendment 192-90).
Factual Information 30 Pipeline Accident Report

(2) Ö.

(3) Making construction records, maps, and operating history available to

appropriate operating personnel.

For the 26 safety inspections of EPNG (referenced earlier) conducted by the OPS

from June 1990 to September 2000, compliance with 192.605(b)(3) was noted as

ìsatisfactory,î ìnot applicable,î ìnot checked,î or, in some cases, the inspection form did

not include questions specifically related to maps and records.

Before August 2000, there were no enforcement actions against EPNG for their

program for making construction records, maps, and operating history available to

operating personnel.

Postaccident Actions

Pipeline Reconstruction

After the accident, EPNG reconstructed lines 1103 and 1110 in the area of the river

crossing. Line 1103 was modified to make it piggable between the Keystone and Pecos

River compressor stations. During hydrostatic testing, line 1103 failed about 2,097 feet

downstream/west of the accident site between the Pecos River and the Pecos River

compressor station. At the failure location, pitting was observed on the internal surface of

the bottom of the pipe, and the wall thickness had been reduced by approximately 69

percent. A March 2001 in-line inspection of line 1103, which included the segment in

which cleaning pigs had been periodically run (from block valve No. 2 to block valve

No. 6) found no areas of internal corrosion that required repair under the internal

inspection analysis protocol developed by EPNG and reviewed by the OPS.

Line 1110 was modified to make it piggable from its beginning point on line 1103

to the Pecos River compressor station. EPNG investigated nine low points in line 1110

between its beginning point on line 1103 and the Pecos River compressor station. No

indications of internal corrosion were found. Some of these low points were in the section

of line 1110 upstream of block valve No. 6 in which cleaning pigs had been periodically

run.

Line 1100 was removed from the suspension bridge, and new 26-inch pipe was

constructed across the Pecos River and supported off the service bridge. Line 1000, which

previously had been abandoned, was removed. The suspension bridges were removed and

not replaced. EPNG modified the power supply to the SCADA computers and modem at

Pecos River compressor station so that an emergency shutdown would not cause a loss of

power to the local SCADA computer and modem.
Factual Information 31 Pipeline Accident Report

Pipeline Integrity Management

After the accident, EPNG contracted for the development of a program to train

company personnel in internal corrosion. According to EPNG, that program has been

completed and implemented.

In response to the August 23, 2000, corrective action order (discussed in more

detail below), EPNG identified 60 segments of pipeline where the risk of internal

corrosion was judged to be the greatest. These segments were inspected by in-line

inspection or other non-destructive means with the result that internal corrosion was

discovered in eight pipelines. In six of these lines, the company judged the corrosion to be

isolated instances. EPNG sent sections of the remaining two pipelines to the companyís

metallurgical laboratory for analysis and chemical testing. These tests found a portion of

one of these lines, line 1107, in which general internal corrosion and localized pitting had

reduced the pipe wall thickness by approximately 42 percent. Corrosion product samples

taken from this line were analyzed and found to contain high levels of acid-producing

bacteria. Remedial actions were completed before the affected pipelines were returned to

service. On December 4, 2002, the pressure restrictions imposed by the OPS corrective

action order for lines 1100, 1103, and 1110 were lifted.

After the accident, El Paso Corporation implemented an integrity management

program applicable to the companyís 46,000 miles of gas pipelines. An executive-level

committee was formed to provide program oversight, and a company-wide pipeline

integrity committee was created to directly supervise and administer the integrity

management program. The internal corrosion portion of this program includes a systemwide evaluation of flow velocities, low spots in pipelines, drips, vessels, gas quality

history, and liquid analysis and other operating and maintenance history and specifies

follow-up remedial action. Other components of the program include operational audits,

the implementation of continuous improvement processes focused on sharing best

practices, enhanced communication, and the incorporation of performance metrics. In

addition, the program includes in-line inspection, before 2011, of all onshore pipelines 6-

inch-diameter and larger (10,551 miles for EPNG and 42,083 miles total for all pipelines

operated by El Paso Corporation).

Federal Response

On August 23, 2000, RSPA issued a corrective action order (appendix B) to El

Paso Energy Pipeline Group requiring EPNG to take the necessary corrective actions to

protect the public and environment from potential hazards associated with its pipeline

operations. The corrective action order listed 25 required corrective action items.

On August 29, 2000, RSPA issued Advisory Bulletin ADB-00-02 (appendix C) to

all operators of natural gas transmission pipelines. This bulletin advised pipeline operators

to review their internal corrosion monitoring programs and operations and provided

guidance for doing so.

On June 20, 2001, the OPS issued to El Paso Energy Pipeline Group a notice of

probable violation, proposed civil penalty, and proposed compliance order. In the notice,
Factual Information 32 Pipeline Accident Report

the OPS stated that preliminary findings indicate that internal corrosion likely played a

major role in the accident. These findings also indicate that internal corrosion had

probably occurred, over a long period, where liquids had accumulated in a low point in the

pipeline.

The five violations alleged in the OPS notice are summarized as follows:

1. EPNG's corrosion control procedure No. 700 for pipelines 1100, 1103, and

1110 is not carried out by, or under the direction of, a person qualified in pipeline

corrosion control methods. This is because EPNG's corrosion personnel have not

received the informal or formal training necessary to perform the tasks required to

implement the corrosion control procedures.

2. EPNG did not take steps to investigate and to minimize internal corrosion, as

required by 49 CFR 192.475. EPNG failed to follow its procedures when it failed

to determine that the gas transported in its pipelines was corrosive. Includes 1ñ

Gas Control failed to recognize when water vapor levels of gas entering the

pipeline exceeded Company limits and failed to stop the flow of gas into lines

1110 and 1103, 2 ñ Operations personnel failed to communicate with Corrosion

personnel about excessive water vapor and liquid water in lines 1103 and 1110, 3

ñ Personnel failed to follow procedures to investigate and take corrective actions

when the water vapor limits were exceeded in line 1103 and 1110, and 4 ñ

Personnel failed to follow procedures and sound engineering practice by not

performing corrosiveness tests on the liquids and solids that were removed from

lines 1103 and 1110 after pigging operations.

3. EPNG did not follow its procedures for continuing surveillance by failing to

consider and take appropriate action on several unusual operating and

maintenance conditions on line 1103. EPNG failed to test pigging residue for

corrosivity and failed to evaluate line 1103 for low points where liquids could

accumulate and where corrosion could occur.

4. EPNG did not follow its Leak and Failure Reporting procedure by not

following up on the Company's recommendations developed after the Roswell

failure (caused by internal corrosion) and thus not minimizing the likelihood of a

recurrence.

5. EPNG did not have an updated drawing of line 1103 because it did not show

the elevation profile of the pipeline in the area of the accident. Having an accurate

profile would have allowed EPNG to determine where low points, and possible

liquid accumulation and internal corrosion, were located.

The notice proposed a civil penalty of $2.525 million for probable safety

violations. On October 12, 2001, EPNG submitted a detailed response to the notice that

addressed each alleged violation and requested a hearing as set forth in RSPA regulations.

As of January 3, 2003, a hearing date had not been set, and a final order had not been

issued.
Factual Information 33 Pipeline Accident Report

Pipeline Integrity ManagementFederal Regulations

In 1987, as the result of two gas pipeline accidents28 that killed five persons, the

Safety Board made the following safety recommendations to RSPA:

P-87-4

Require operators of both gas and liquid transmission pipelines to

periodically determine the adequacy of their pipelines to operate at

established maximum allowable pressures by performing inspections or

tests capable of identifying corrosion-caused and other time-dependent

damages that may be detrimental to the continued safe operation of these

pipelines and require necessary remedial action.

P-87-5

Establish criteria for use by operators of pipelines in determining the

frequency for performing inspections and tests conducted to determine the

appropriateness of established maximum allowable operating pressures.

RSPA most recently responded in April 2002, stating that RSPA now requires

integrity management programs for hazardous liquid pipelines in high-consequence areas,

and that it (1) published a notice in the Federal Register on June 27, 2001, requesting

comments on integrity management concepts for gas transmission pipelines, (2) published

a proposed definition of high-consequence areas for gas pipelines on January 9, 2002, and

(3) would propose a gas pipeline integrity management program later in 2002. On the

basis of this information, Safety Recommendations P-87-4 and -5 were classified

ìOpenAcceptable Responseî pending completion of these actions.

In 1987, as the result of a gasoline pipeline accident29 in which two persons were

killed and one person was seriously burned, the Safety Board made the following safety

recommendation to RSPA:

P-87-23

Revise 49 CFR parts 192 and 195 to include operational based criteria for

determining safe service intervals for pipelines between hydrostatic retests.

RSPA most recently responded in an October 11, 2002, letter summarizing the

actions the agency has taken regarding pipeline integrity since the recommendation was

issued. The agency told the Safety Board that over a number of years it had developed new

28 National Transportation Safety Board, Texas Eastern Gas Pipeline Company Ruptures and Fires at

Beaumont, Kentucky, on April 27, 1985, and Lancaster, Kentucky, on February 21, 1986. Pipeline Accident

Report NTSB/ PAR-87-01 (Washington, D.C.; NTSB, 1987).

29 National Transportation Safety Board, Williams Pipe Line Company Liquid Pipeline Rupture and

Fire, Mounds Views, Minnesota, July 8, 1986. Pipeline Accident Report NTSB/PAR-87/02 (Washington,

D.C.; NTSB, 1987).
Factual Information 34 Pipeline Accident Report

approaches and had studied a number of developing technologies that are helping industry

to better assess the operation of their pipelines. In addition, the letter stated that RSPA had

developed a series of rulemakings that will require every natural gas transmission and

hazardous liquid pipeline operator to implement an integrity management program to

protect high-consequence areas that could be affected by a pipeline failure. Based on this

information and information contained in an earlier (July 2002) response to this

recommendation, the Safety Board classified Safety Recommendation P-87-23

ìOpenAcceptable Response,î30 pending completion of the rulemaking.

Effective September 5, 2002, RSPA issued a final rule (ìPipeline Safety: High

Consequence Areas for Gas Transmission Pipelinesî) in which it defined ìhighconsequence areaî as an area within a certain distance of a gas transmission pipeline that

meet one or more specified criteria for the number of persons or types of property that

might be affected by an accident involving that pipeline.

On December 17, 2002, the President signed Public Law 107-355, the Pipeline

Safety Improvement Act of 2002. Section 14 of this act requires that within 12 months of

its enactment, RSPA is to issue a final rule prescribing integrity management standards for

operators of gas transmission pipelines in high-consequence areas. The act requires that

within 24 months of its enactment, gas pipeline operators implement integrity

management programs, even if RPSA has not issued a final rule. The act requires these

pipeline operators to complete integrity testing of 50 percent of the highest risk pipelines

within 5 years and the remainder within 10 years. Reassessment intervals are set at a

minimum of once every 7 years. Integrity testing must be done by in-line inspection,

pressure-testing, or an alternative method approved by RSPA as providing at least an

equal level of safety. Under certain conditions, RSPA may grant waivers. The act requires

the integrity programs to have clearly defined criteria for evaluating the results of the

testing in addition to a description of actions to be taken by operators to promptly address

any integrity issues raised by the evaluation.

On January 28, 2003, RSPA published in the Federal Register a notice of proposed

rulemaking (NPRM) to require operators of gas transmission pipelines to establish

integrity management programs to identify and evaluate the condition of and threats to

their pipelines in high-consequence areas and to take steps to protect against pipeline

failures. The proposed rule would require these pipeline operators to use periodic in-line

inspections, pressure-testing, direct assessment,31 or other means to identify weaknesses in

the pipe wall. Further, the rule would require operators to gather and evaluate data on the

performance trends resulting from their programs and to make improvements and

corrections based on this evaluation. The rule will not apply to gas gathering or to gas

distribution lines. The proposed rule would also incorporate the required elements for gas

30 Safety Recommendation P-87-23 had previously been classified ìOpenUnacceptable Response.î

31 Direct assessment is an integrity assessment method that uses a process to evaluate the threats to

pipeline integrity from external corrosion, internal corrosion, and stress corrosion cracking. The process

includes the gathering and integration of risk factor data, indirect examination or analysis to identify areas of

suspected corrosion, direct examination of the pipeline in these areas, and post-assessment evaluation.
Factual Information 35 Pipeline Accident Report

pipeline integrity management programs that are mandated in the Pipeline Safety

Improvement Act.

NACE Standards

NACE International, an organization concerned with corrosion issues, produces

consensus industry standards in the form of test methods, recommended practices, and

material requirements. In 1975, the organization issued a standard, RP0175-75, ìControl

of Internal Corrosion in Steel Pipelines and Piping Systems.î The purpose of this standard

was to describe procedures and recommended practices for achieving effective control of

internal corrosion in steel pipe and piping systems in crude oil, refined products, and gas

service. RP0175-75 addressed methods for detecting and controlling internal corrosion

and noted the importance of flow velocity analysis, periodic product sampling, and

chemical analysis of corrosive constituents in mitigating corrosion. It also identified the

beneficial effects of the use of cleaning pigs.

RP0175-75 was intended to serve as a guide for establishing minimum

requirements for control of internal corrosion in gas transmission, gas distribution, and

other steel piping systems. Because the document had not been reviewed and renewed by

NACE when it was due for periodic review, in 1995 the document was withdrawn and is

available from NACE only as a historical document. NACE does not consider RP0175-75

to be an official and current NACE document. The Safety Board has been told by NACE

representatives that the society is working on another standard similar to, and based on,

RP0175-75.

ASME Code for Gas Piping (B31.8)32

The American Society of Mechanical Engineers (ASME) code for gas piping

addresses the safety aspects of the design, construction, operation, and maintenance of gas

pipelines. Specific guidance for an internal corrosion control program for all existing

pipelines is included. For pipelines that transport corrosive gas, design and construction

considerations for new pipelines and modifications to existing pipelines are included. For

design and construction, the considerations include (1) running cleaning pigs (including

provisions for effective accumulation and handling of liquids and solids removed from the

pipeline by the pigging), (2) installing corrosion monitoring devices (coupons, probes) at

locations where the greatest potential for corrosion exists, (3) treating the gas to reduce its

corrosivity, (4) selecting corrosion resistant materials for construction of the pipeline, (5)

internally coating the pipeline, and (6) injecting corrosion inhibitors into the gas stream.

32 ASME B31.8-1999, Gas Transmission and Distribution Piping Systems, American Society of

Mechanical Engineers; Chapter VI, paragraph 863. (Essentially identical wording has been part of ASME

B31.8 since 1982.) On January 31, 2002, ASME issued a supplement to the B31.8 code entitled ìManaging

System Integrity of Gas Pipelines,î which includes guidance for determining whether internal corrosion

may be a threat to pipeline integrity and measures to assess the condition of the pipeline at those locations.
Factual Information 36 Pipeline Accident Report

For operations and maintenance, the considerations include (1) establishing a program for

the detection, prevention, or mitigation of internal corrosion (including reviewing leak and

repair records, inspecting the internal surface of the pipe whenever it becomes accessible,

analyzing gas from areas of known internal corrosion to determine the types and

concentrations of corrosive agents, analyzing liquids and solids removed from the pipeline

by pigging, and draining or cleanup to determine the presence of corrosive materials and

evidence of corrosion products), (2) controlling corrosion by modifying the pipeline to

facilitate the removal of water from low spots, and (3) measuring the wall thickness of

buried pipe when it is uncovered and of exposed pipe in areas where internal corrosion is

suspected.

Guide for Gas Transmission and Distribution Piping Systems33

The Gas Piping Technology Committeeís34 Guide for Gas Transmission and

Distribution Piping Systems includes material intended to assist the user in complying

with the Federal regulations.35 For internal corrosion, guidelines for design, detection,

monitoring, and corrective measures are included. The guide states that in the presence of

water, gases containing certain components such as CO2, H2S, and O2 can be corrosive to

steel pipelines and that pipeline liquids may contain constituents that may be detrimental

to pipeline integrity. The guide also states that if it is anticipated or has been determined

that the gas to be transported is corrosive, the following should be considered: selection of

special materials of construction, effect of flow velocities, fluid removal (pigging, drips

that include access ports for internal inspection, separators), control of water dew point

(by dehydration, separation, or temperature control), reduction of corrosive components in

the gas, internal coating, and chemical treatments. For the detection of internal corrosion,

considerations include sampling and analysis of gas, liquids, and solids; visual inspection

of pipe and drips; use of corrosion monitoring devices (coupons, probes); and in-line

inspection and other non-destructive inspection to determine wall thickness.

Other Information

Previous EPNG Internal Corrosion Accident

On September 10, 1996, line 1300 ruptured near Roswell, New Mexico. The

EPNG investigation determined that the pipe had failed from internal corrosion at a sag

bend in the pipe. The accident report stated that:

33 ANSI GPTC Z380.1, Guide for Gas Transmission and Distribution Piping Systems, Gas Piping

Technology Committee.

34 The Gas Piping Technology Committee is an independent consensus committee comprising

representatives from the pipeline industry, including manufacturers, operators, and consultants, as well as

from pipeline regulatory agencies.

35 The current guide is dated June 15, 1998, and includes Addendum No. 1, July 7, 1999; Addendum

No. 2, August 23, 2000; and Addendum No. 3, January 29, 2002. The guide material for internal corrosion

was most recently revised in Addendum 3.
Factual Information 37 Pipeline Accident Report

it is impossible to tell when in time most of the corrosion at the rupture point

occurred. However, it is certainly related to the settlement of liquids in a low spot,

possibly during the period of low flows in the line for several years prior to its

reversal in 1992. The source of liquids was probably one or more of the

production facilities that provide (or provided) gas directly to the transmission

line. Current analyses do not provide adequate information to determine the

presence of potentially corrosive liquids in gas received, so other measures should

be taken to prevent the introduction of liquids into the line.

The metallurgy report, which was an attachment to EPNGís final investigation

report of the rupture, recommended that the quality of gas being injected into line 1300

near the rupture location and at other locations of concern be monitored to avoid another

failure of this type. Also recommended were (1) that pigs be run near the failure location

to clean any remaining liquid from the system, (2) that a sample of the pigging residue be

analyzed to determine whether undesirable compounds were present, (3) that other areas

of possible pipeline deflection be examined, and (4) that previously untested areas in the

vicinity of the rupture be hydrostatically tested to ensure their structural integrity.

In a Safety Board interview, a member of the EPNG pipeline safety staff stated that

the company considered the failure of line 1300 to be an isolated event and that the

recommendations in the investigation report were therefore applicable only to line 1300

because of unique operating conditions in the ruptured pipeline. These conditions included

a producer that EPNG representatives said had been known to introduce water into the

pipeline at a receipt point near the rupture location, as well as periods of low-flow and

static conditions in line 1300, which resulted in gas flow rates insufficient to move or

dissipate the moisture.

Emergency Training and Simulations

Annual meetings of emergency responders were conducted in November 1997,

October 1998, October 1999, and October 2000 for the Carlsbad area, including Eddy

County, emergency response and law enforcement agencies. At these meetings, EPNG

personnel reiterated safety precautions at natural gas emergencies and, through written

tests, quizzed emergency responders on safety issues.

In November 1997, EPNG conducted an emergency response exercise for a leak

on line 3191 between South Carlsbad compressor station and Pecos River compressor

station. The Eddy County Sheriffís Office was involved, as well as the Eddy County

disaster coordinator. In August 1997, a leak was simulated at the Keystone compressor

station to test the readiness of the compressor station personnel.
38 Pipeline Accident Report

Analysis

EPNG pipeline 1103 was operating at about 80 percent of the maximum allowable

operating pressure when the pipeline ruptured. The rupture occurred at a place in the

pipeline where internal corrosion had thinned the pipe wall. The fact that the fracture faces

resulted from overstress separation with no evidence of fatigue cracking indicates that the

rupture occurred as one catastrophic event. The Safety Board therefore concludes that line

1103 ruptured as a result of severe internal corrosion that caused a reduction in pipe wall

thickness to the point that the remaining metal could no longer contain the pressure within

the pipe.

A number of factors were found to have contributed to the fact that the corrosion

that led to the rupture had not been detected and mitigated by EPNG before the accident,

and those factors are addressed in this analysis.

The major safety issues identified during the investigation of this accident are as

follows:

ï The design and construction of the pipeline,

ï The adequacy of EPNGís internal corrosion control program,

ï The adequacy of Federal safety regulations for gas pipelines, and

ï The adequacy of Federal oversight of the pipeline operator.

Exclusions

The investigation determined that the operating pressure (675 psig) in the pipeline

at the time of the rupture was below the maximum allowable operating pressure (837 psig)

established for that section of the pipeline. Operation of the pipeline system was

monitored by a SCADA system, and even though the gas controllerís understanding of the

rapidly unfolding situation at the Pecos River compressor station immediately after the

rupture was hampered by a brief interruption of data from the SCADA system and the

subsequent loss of SCADA communications as a result of the power outage at the Pecos

River compressor station, the controller accurately evaluated the available information

and promptly initiated an appropriate response. There was no evidence of third-party

damage to the pipeline at the rupture site, nor was there evidence of external corrosion at

the rupture location. The Safety Board therefore concludes that the following were neither

causal nor contributory to the accident or its aftermath: overpressure of the pipeline, the

interruption in or loss of SCADA communication, external damage to the pipeline through

excavation or other activities, and external corrosion of the pipeline.
39 Pipeline Accident Report

Emergency Response

EPNG employees, who were on the accident scene within 19 minutes of the

rupture, worked quickly and effectively to stop the flow of natural gas from the ruptured

pipeline and to extinguish the fire. Because they did not know which pipeline had

ruptured, they began closing valves upstream and downstream of the fireball in all four

EPNG natural gas pipelines. Emergency responders arrived on scene within 25 minutes of

the rupture and staged at the Pecos River compressor station. The emergency responders

anticipated a routine standby assignment that would terminate when the flow of natural

gas was stopped and the fire self-extinguished. Because the accident was in a rural area,

emergency responders did not expect to find any persons injured. However, approximately

40 minutes after the rupture and while attempting to reach valves to stop the flow of

natural gas, an EPNG employee thought that he saw vehicles in the area of the fire and

provided that information to another employee.

About 15 minutes later, when the flow of natural gas was stopped and the fire was

extinguished, the EPNG employee confirmed that he had seen vehicles in the area where

the fire had been burning. This information was then passed on to emergency responders,

who immediately initiated rescue efforts. Carlsbad Fire Departmentís medic units had

responded with the initial call and were staged at the compressor station. Paramedics and

emergency medical technicians worked diligently to treat the injuries of victims and to

hastily evacuate them to hospital burn centers in Texas.

The Safety Board notes that the EPNG employees who initially had information

that vehicles may be parked in the vicinity of the fire did not notify emergency responders

until the fire was extinguished and the presence of vehicles was confirmed. In order for

emergency responders to make informed decisions about rescue efforts, it is important that

they be given information, as quickly as it is available, that could indicate the possibility

of victims in the vicinity of an accident. In this case, because of the intensity of the fire in

the vicinity of the campsite, the radiant heat associated with the fire, and the difficulty that

response crews would have faced gaining access to the area while the fire was burning, the

Safety Board does not believe the outcome of the accident would have been different if

responders had been notified sooner, although the precise effect such notification would

have had on respondersí decision-making cannot be determined.

Internal Corrosion in Steel Gas Pipelines

Corrosion on the internal wall of a natural gas pipeline can occur when the pipe

wall is exposed to water and contaminants in the gas, such as O2, H2S, CO2, or chlorides.

The nature and extent of the corrosion damage that may occur are functions of the

concentration and particular combinations of these various corrosive constituents within

the pipe, as well as of the operating conditions of the pipeline. For example, gas velocity

and temperature in the pipeline play a significant role in determining if and where

corrosion damage may occur. In other words, a particular gas composition may cause

corrosion under some operating conditions but not others. Therefore, it would be difficult
Analysis 40 Pipeline Accident Report

to develop a precise definition of the term ìcorrosive gasî that would be universally

applicable under all operating conditions.

Corrosion may also be caused or facilitated by the activity of microorganisms

living on the pipe wall. Referred to as microbiologically influenced corrosion, or MIC,

this type of corrosion can occur when microbes and nutrients are available and where

water, corrosion products, deposits, etc., present on the pipe wall provide sites favorable

for the colonization of microbes. Microbial activity, in turn, may create concentration cells

or produce organic acids or acid-producing gases, making the environment aggressive for

carbon steel. The microbes can also metabolize sulfur or sulfur compounds to produce

products that are corrosive to steel or that otherwise accelerate the attack on steel.

Internal corrosion in a gas pipeline may be detected by any of several methods,

including visual examination of the inside of a pipeline when it is opened, external

measurement of the pipe wall thickness with instruments, evaluation of corrosion coupons

or probes placed inside the pipeline, or inspection of the pipe with an in-line inspection

tool to identify areas of pitting or metal loss.

Internal corrosion may be kept under control by establishing appropriate pipeline

operating conditions and by using corrosion-mitigation techniques. One method for

reducing the potential for internal corrosion to occur is to control the quality of gas

entering the pipeline. Also, by periodically sampling and analyzing the gas, liquids, and

solids removed from the pipeline to detect the presence and concentration of any corrosive

contaminants, including bacteria, as well as to detect evidence of corrosion products, a

pipeline operator can determine if detrimental corrosion may be occurring, identify the

cause(s) of the corrosion, and develop corrosion control measures.

Internal Corrosion in Line 1103

Interconnecting pits were observed on the inside of the pipe in the ruptured area of

line 1103. Typically, these pits showed the striations and undercutting features that are

often associated with microbial corrosion. A pit profile showed that chloride concentration

in the pits increased steadily from top to bottom. Increased chloride concentration can

result from certain types of microbial activity. All four types of microbes (sulfatereducing, acid-producing, general aerobic, and anaerobic) were observed in samples

collected from two pit areas in the piece of line 1103 where internal corrosion was

discovered after the accident about 2,080 feet downstream of the rupture site. Though the

individual contribution of various microbes in the corrosion process could not be

estimated, the damage morphology and the corrosion product analyses data suggest that

microbiological activity contributed to the corrosion process.

Dissolved O2 in an electrolyte could cause pitting by creating concentration cells.

CO2 is soluble in water and will form carbonic acid, which is corrosive to carbon steel.
Analysis 41 Pipeline Accident Report

When dissolved in water, H2S forms a weak acid that could corrode carbon steel.

In combination with dissolved O2, it could cause pitting. Though generally present in low

concentrations, these potentially corrosive constituents were present in the gas that was

being transported in line 1103. Also, upset conditions occasionally increased the

concentrations of these constituents in the transported gas.

Chlorides were observed in all corrosion product/deposit samples. Anions, such as

chloride, cause pitting and, typically, chloride concentration in a pit may be much higher

than the chloride concentration outside the pit (bulk concentration).

Chemical analyses showed that the pH (6.7-6.8) of the liquid collected at the Pecos

River compressor station plant inlet separator scrubber was more acidic than the pH (8.2)

of the liquid collected at Keystone compressor station inlet scrubber. Also, the material

collected at line 1100 and 1103 pig receivers (pH ~ 6.2-6.3) and the inside material

collected from a low spot on line 1103 west of the rupture (pH ~ 6.4) were more acidic

than the material collected near the siphon drain area of the line 1103 drip (pH ~ 8.9). The

observed low pH in the samples could be a result of dissolved CO2, and/or H2S in the

water, and/or intrusion of low-pH ground water into the gas supply. Typically, acidic

(pH<7) water is more corrosive to carbon steel than basic water (pH>7).

Thus, water and contaminants such as chlorides, O2, CO2, and H2S all likely

contributed to the observed corrosion damage. The Safety Board therefore concludes that

the corrosion that was found in line 1103 at the rupture site was likely caused by a

combination within the pipeline of microbes and such contaminants as moisture,

chlorides, O2, CO2, and H2S.

Physical Features of Line 1103

Examination of the pipe at the rupture location revealed five wrinkles in the pipe

wall at the top of the pipeline. Wrinkles in the wall of a pipe occur when a pipe is bent,

either to align pieces of pipe during construction or from external forces, such as earth

movement, after the pipeline is in service. When pipe is bent and wrinkles form on the top

of the pipe, a low point is created at the bottom of the pipe opposite the wrinkles. The

observed internal corrosion in the pipeline at the rupture location was at such a low point,

where liquids likely accumulated into a pool with a fluctuating liquid level. Because the

density of water is greater than that of hydrocarbon liquids present in the pipeline, water in

the pipeline would remain at the bottom of the pool with the liquid hydrocarbons on top,

creating an ideal environment for the development of internal corrosion.

The original construction of line 1103 by EPNG included a block valve and drip

approximately 1 mile east of the Pecos River. The block valve, designated No. 6, was on a

hill about 62 feet higher than the Pecos River. The valve may have been positioned thus so

that it would remain accessible and not be damaged if the river flooded. The underground

drip was placed downstream of the block valve and was 31 feet lower in elevation than the

pipeline at block valve No. 6. This configuration facilitated the trapping of liquids and
Analysis 42 Pipeline Accident Report

solids flowing in line 1103 toward the Pecos River compressor station by the drip, which

was upstream of the rupture location.

When pigging facilities were added to line 1103 about 25 years after initial

construction, a pig launcher was installed at block valve No. 2, and a pig receiver was

placed at block valve No. 6. A separate storage leg or tank to collect the pig liquids at

block valve No. 6 was not installed. Instead, during pigging operations, the pig and some

of the liquids and solids being pushed by the pig would be caught in the pig receiver at

block valve No. 6. Any material that passed the pig receiver, either during normal

operations or because of a pig run, would flow downstream and downhill to the drip.

Postaccident visual examination of the drip revealed that, at one point, about 70

percent of the drip cross-section was filled with the blackish oily-powdery/grainy material

that acted as a dam inside the drip, preventing some of the materials entering the drip from

continuing to the far end of the barrel to the siphon drain. This blockage also likely

contributed to movement of liquids and solids past the drip. Materials flowing past the

drip could then collect at low points in the downstream pipeline, such as the low point at

the rupture location, where they would remain until gas flow of sufficient velocity was

available to sweep the liquids farther downstream toward the inlet scrubbers at the Pecos

River compressor station. Velocity data provided by EPNG for the period 1991 to 2000

indicated numerous periods when the gas velocity was substantially below the preferred

sweeping velocity of 25 feet per second.

The Safety Board concludes that, as a likely result of the partial clogging of the

drip upstream of the rupture location, some liquids bypassed the drip, continued through

the pipeline, and accumulated and caused corrosion at the eventual rupture site where pipe

bending had created a low point in the pipeline.

Periodic use of cleaning pigs can remove water and other liquid and solid

contaminants from a pipeline. One of the considerations for the design and construction of

a cleaning pig system is to make provisions for effective collection and removal of the

accumulated materials from the pipeline after pigging. In line 1103, because of the

configuration of the piping and valves at block valve No. 6 and the geometry of the drip,

cleaning pigs could not be run in the section of pipeline that ruptured. Some of the liquids

and solids that accumulated in front of the cleaning pig were returned to the pipeline and

moved downstream by the flowing gas toward the drip. In conjunction with the partially

clogged drip, and the introduction of additional liquids into line 1103 from the crossover

from line 1100 (from which the drip had been removed) upstream of the line 1103 drip, it

is likely that there was incomplete removal of accumulated liquids and solids from line

1103.

Postaccident in-line inspection of the segment of line 1103 in which cleaning pigs

had been periodically run (from block valve No. 2 to block valve No. 6) found no areas of

internal corrosion that the company determined required repair. The Safety Board

therefore concludes that if the accident section of pipeline 1103 had been able to

accommodate cleaning pigs, and if cleaning pigs had been used regularly with the

resulting liquids and solids thoroughly removed from the pipeline after each pig run, the
Analysis 43 Pipeline Accident Report

internal corrosion that developed in this section of pipe would likely have been less

severe.

The ASME code for gas piping (ASME B31.8, Gas Transmission and Distribution

Piping Systems) and the Guide for Gas Transmission and Distribution Piping Systems

include design and construction considerations related to internal corrosion control for

new pipelines and modifications to existing pipelines. Although some operators may

incorporate these considerations or have their own engineering standards for the design

and construction of pipelines to minimize liquid accumulation and to remove liquids from

a pipeline, there are no Federal regulatory requirements applicable to all operators.

The Safety Board believes that RSPA should revise 49 CFR Part 192 to require

that new or replaced pipelines be designed and constructed with features to mitigate

internal corrosion. At a minimum, such pipelines should (1) be configured to minimize the

accumulation of liquids, (2) be equipped with effective liquid removal features, and (3) be

able to accommodate corrosion monitoring devices at locations with the greatest potential

for internal corrosion.

EPNG Internal Corrosion Control Program

At the time of the accident, EPNG was beginning the process of implementing an

internal corrosion control program based on the new procedures dated May 15, 2000, and

July 10, 2000. However, training of personnel in the new procedures began in August

2000, and the new corrosion control actions specified in these documents had yet to be

fully implemented at the time of the accident. As a result, the program actually in place

was the one specified in the September 20, 1999, operating and maintenance procedures

manual. This written program required (1) that the corrosion services department, after

being notified that corrosive gas was being transported or if internal corrosion was found,

recommend appropriate corrective actions and establish an internal corrosion monitoring

program to determine the effectiveness of the corrective actions, and (2) that a visual

inspection he made of the inside of a pipeline when opened.

These procedures did not address the specific operating conditions, such as water

in the pipeline, corrosive contaminants in the gas and liquid, and velocity of the gas, that

should be considered when evaluating a pipeline for possible internal corrosion. The

companyís gas quality standard addressed several contaminants, including water, CO2,

H2S, and O2, but the corrosion control procedures did not reference these contaminants or

their acceptable limits. Although gas quality standards were contained in EPNGís

contracts with gas suppliers, most of the interconnect locations with gas producers on line

1103 (between the Pecos River compressor station and the Keystone compressor station)

and line 1100 (between Eunice plant and the Keystone compressor station, from which gas

and liquids could enter line 1103 upstream of the drip) did not have alarms (which alarmed

in the gas control center if contaminant levels were exceeded), and other locations only

had periodic sampling and analysis of the gas entering the EPNG pipeline. Thus, despite

the fact that EPNG officials said they relied partially on maintaining the quality of gas to
Analysis 44 Pipeline Accident Report

help prevent corrosion, the company did not take the steps necessary to allow it to

adequately monitor and control the quality of gas entering the pipeline.

The 1999 procedures did not provide guidance regarding how internal corrosion

would be detected other than through visual inspection of a pipe segment after it had been

opened. Nor did the procedures require that, during normal operations, pigging, or

maintenance activities, liquids and solids be removed from the pipeline and tested for the

presence of corrosive materials or evidence of corrosion products. The ASME B31.8 code

identifies the importance of determining whether gas is corrosive by requiring that ìGas

containing free water under the conditions at which it will be transported shall be assumed

to be corrosive, unless proven to be non-corrosive by recognized tests or experience.î

Very little useful information concerning what was entering the pipeline, where it was

entering, and what materials were accumulating in the pipeline was available to corrosion

control personnel. As a result, EPNG corrosion control personnel stated that they were not

aware that corrosion could be occurring in the companyís pipeline or that corrosion

mitigation measures might be necessary.

In the event it was determined that corrosive gas was being transported or internal

corrosion was occurring, corrosion mitigation actions would be recommended by the

corrosion services department. However, there were no written requirements for corrosion

technicians to follow up on reports of out-of-specification gas being received or to identify

the effect, if any, of this gas on the pipeline, and there were no standards or criteria to be

used to determine if out-of-specification gas was potentially corrosive. The procedures did

not detail how the semi-annual monitoring to determine the effectiveness of the corrosion

mitigation measures would be carried out. Corrosion monitoring devices were not used in

line 1103 between the Keystone and Pecos River stations because the gas was not believed

to be corrosive.

In September 1996, EPNGís line 1300 ruptured as a result of internal corrosion.

The metallurgy report attached to EPNGís final investigation report of the rupture

recommended expanded gas quality monitoring and additional pigging, with collected

residue being analyzed for undesirable components. Because the company considered this

rupture to be an isolated event, it did not implement the recommendations for its other,

similar, gas transmission lines. Further, according to a senior safety staff employee at

EPNG, the companyís internal audit program was not revised after the September 1996

rupture of line 1300 from internal corrosion. Revising the companyís audit program to

include inquiries regarding operating conditions (gas velocity, gas producers connected to

a transmission pipeline, unpigged pipelines whose configuration could lead to

accumulation of liquids in low spots) would have helped EPNG to determine if similar

conditions existed in other pipelines, but the company did not do so.

In the years leading up to the accident, EPNG had access to industry standards and

guidelines, such as those contained in the NACE standards, the ASME code, and the

Guide for Gas Transmission and Distribution Piping Systems, regarding the detection and

control of internal pipeline corrosion. But the company did not incorporate that guidance

in its internal corrosion procedures. Nor did the company take the steps necessary to

ensure that the limited procedures that it did have in place were effective. For example,
Analysis 45 Pipeline Accident Report

while the procedures in place at the time of the accident stated that corrosion control

personnel were to be notified if corrosive gas was being transported, the company did not,

as noted above, carry out the gas quality monitoring or inspection activities necessary to

make an accurate determination of the corrosivity of the gas. Also, the procedures

required that corrosion control personnel be notified if corrosion was found, but the

company had no systematic program to detect possible internal corrosion. Internal

inspection devices or corrosion coupons that could have detected existing or potential

corrosion were not regularly employed. In the view of the Safety Board, the preaccident

approach of EPNG in regard to internal corrosion indicates that the company did not

believe internal corrosion to be a significant issue in the safety of its pipeline operations.

As a result, the company was inadequately attentive to the potential for severe internal

corrosion to occur, with the result that the corrosion that led to the rupture of line 1103 was

not detected and mitigated in time to prevent a serious accident. The Safety Board

therefore concludes that, before the accident, EPNG did not have in place an internal

corrosion control program that was adequate to identify or mitigate the internal corrosion

that was occurring in its pipelines.

After the acquisition of Sonat in January 2000, which had been preceded by the

acquisition of Tenneco Energy in December 1996, El Paso Energy organized teams of

representatives from each pipeline to determine best practices and produce a new

operating and maintenance manual. The resulting Operating and Maintenance Procedures

manual was issued on May 15, 2000, followed by a Corrosion Control Manual on July 10,

2000. These procedures were applicable to El Paso Energyís gas pipeline companies and

were the approved procedures at the time of the accident in August 2000.

For Tenneco Energy, the internal corrosion procedures in use at the time of the

December 1996 acquisition by EPNG were in the companyís Operating and Maintenance

Manual. The procedure for internal corrosion detection and control was dated December

1, 1993, and included a requirement to test gas and liquids being transported to determine

if they are corrosive. A Corrosion Control Manual dated February 1, 1997 supplemented

the internal corrosion control procedures in the Operating and Maintenance Manual with

additional, detailed internal corrosion control considerations and measures.

Even though EPNG had access to Tennecoís procedures after the acquisition, it

took an additional 41 months, from December 1996 to May 2000, for El Paso Energy to

develop and issue internal corrosion control procedures applicable to EPNG that included

requirements for testing pipeline gas and liquids to determine if they are corrosive. It was

an additional 2 months, from May 15 to July 10, 2000, before the supplemental, detailed

internal corrosion control procedures were issued describing what to test for, where to test,

and how often to test.

The program being implemented at the time of the accident was based on EPNGís

Corrosion Control Manual, Section 700, dated July 10, 2000 (subsequently revised

January 15, 2001, revised October 1, 2001, and redesignated Section 6 and revised

December 19, 2001). The program recognized that gas quality standards alone are

insufficient to determine whether a pipeline is transporting corrosive gas. These

procedures state that the first line of defense against internal corrosion is gas and liquid
Analysis 46 Pipeline Accident Report

quality standards but that whether a pipeline transports corrosive gas cannot be

determined from the standards themselves. Also noted in the documents is that industry

experience has shown that water and other corrosives may enter the pipeline by accident

or by operational upsets or that it may slowly accumulate in low spots despite gas quality

monitoring that shows adherence to quality standards. The procedures state that

ìidentification of corrosive gas in a pipeline is achieved by analysis of operating

conditions, gas impurity content, monitoring data, mitigation schemes, and/or other

considerationsî and that ìan effective internal corrosion-monitoring program includes

sampling and analysis of liquid, gas, and solid materials.î After the accident, the Safety

Boardís analysis of the liquids and solids from the pipeline determined that potentially

corrosive constituents such as water, chlorides, and bacteria were present in the pipeline.

The Safety Board concludes that had EPNG effectively monitored the quality of gas

entering the pipeline and the operating conditions in pipeline 1103 and periodically

sampled and analyzed the liquids and solids that were removed from the line, it would

likely have determined that the potential existed for significant corrosion to occur within

the pipeline.

Federal Safety Regulations

Federal regulations for gas pipelines include two sections that have requirements

for an internal corrosion control program and one section that requires that the procedures

for the program be included in the operatorís operating and maintenance manual. The

regulations do not define ìcorrosive gasî but do state that such gas may not be transported

by pipeline unless its effect on the pipeline has been investigated and steps have been

taken to minimize internal corrosion. For internal corrosion to occur, water must typically

be present in the pipeline, along with corrosive contaminants such as chlorides, H2S, CO2,

O2, or bacteria. The regulations do not specifically address microbiologically influenced

corrosion or the way that water and contaminants in the pipeline can combine to

contribute to the corrosion process. The regulations also do not specifically address the

importance of the following: minimizing liquids and liquid accumulation in the pipeline,

removing liquids from the pipeline, maintaining drips, and the role of gas velocity in

corrosion control.

Because the Federal regulations do not specifically address the above issues, the

Safety Board concludes that the current Federal pipeline safety regulations do not provide

adequate guidance to pipeline operators or enforcement personnel in mitigating pipeline

internal corrosion. The Safety Board therefore believes that RSPA should develop the

requirements necessary to ensure that pipeline operatorsí internal corrosion control

programs address the role of water and other contaminants in the corrosion process.

Federal Oversight of the Pipeline Operator

On May 15, 2000, EPNG issued revised operating and maintenance procedures for

internal corrosion control. For each of the six OPS safety inspections of EPNG conducted
Analysis 47 Pipeline Accident Report

between May 15 and September 25, 2000, compliance with the Federal regulations for

internal corrosion control was noted by the inspectors as ìsatisfactory.î After the accident,

however, the OPS cited EPNG for a number of probable violations related to its internal

corrosion program. For example, in its June 20, 2001, notice of probable violation, the

OPS stated that EPNGís internal corrosion control program was not carried out by, or

under the direction of, a person qualified in pipeline corrosion control methods. But in

each of the six inspections between May 15 and September 25, 2000, OPS inspectors had

noted that the companyís program was ìÖunder the direction of a qualified person, with

associated recordsÖ.î In several cases, the inspector included on the form a brief

description of the qualifications of EPNGís principal coordinator of corrosion services. At

no time did the OPS inspection process, even under the system integrity inspection pilot

program, indicate a personnel qualification issue with EPNGís corrosion program.

The postaccident notice of probable violation also cited EPNG for not following

its own procedures and sound engineering practice by not performing corrosiveness tests

on the liquids and solids that were removed from lines 1103 and 1110 after pigging

operations. But at no time during the inspections conducted before September 2000 did

the OPS indicate that such testing of liquids and solids was required or that it was sound

engineering practice.

In addition, the notice of probable violation stated that EPNGís elevation profile

drawings for its pipelines in the area of the Pecos River were incomplete. Specifically, the

notice stated that the drawings did not show any elevation profile for line 1103 between

block valve No. 6 and the Pecos River compressor station. Therefore, according to the

OPS, EPNG did not know the location of low points in the pipeline where liquids could

accumulate and thus could not take certain corrosion control steps that could possibly

have prevented the accident. However, during none of the six inspections between May

and September 2000 did the OPS indicate that profile drawings of pipelines were required

or that there were any other compliance or safety issues with the pipeline maps.

Further, in April 2000, the OPS conducted a team review of EPNGís operating and

maintenance procedures as part of the system integrity inspection pilot program. No

deficiencies in the procedures were identified in this inspection, and the OPS did not

require any follow-up actions by EPNG to correct compliance and safety problems. But

only four questions related to an internal corrosion control program (coupon monitoring

and records and corrosion remedial measures and records) were included on the inspection

form. The inspection form did not inquire into the four components of an effective internal

corrosion control program identified in the regulations (determining whether corrosive gas

is being transported, inspection of pipe removed from a pipeline, qualification of internal

corrosion control personnel, and qualification of the person directing the internal

corrosion control program). Thus, because its inspections did not seek information from

the operator in these four areas, the OPS did not have sufficient basis for evaluating

EPNGís compliance with the Federal regulations for internal corrosion control.

Throughout the inspections conducted by the OPS to qualify EPNG for the system

integrity inspection pilot program, OPS inspection reports documented that EPNGís

internal audit program was working as designed. However, the procedures and forms used
Analysis 48 Pipeline Accident Report

by EPNG for its internal audits only addressed actions to be taken after it had been

determined that corrosive gas was being transported. Not addressed in either the EPNG

procedures or forms reviewed by the OPS was how to determine if corrosive gas was

being transported. Thus, although the program was functioning, the internal audit program

was not adequate to uncover potential deficiencies in the companyís internal corrosion

control program.

Federal inspections of a pipeline operator should provide the operator with

accurate feedback and the opportunity for immediate, constructive dialog with the OPS. In

addition, the OPS uses data obtained during field inspections to assess the effectiveness of

its regulations and identify issues of operator noncompliance. But in this case, the OPS

postaccident investigation documented deficiencies in EPNG operations that it had not

previously identified. Had the preaccident inspections applied the enforcement criteria in

the same manner as they were interpreted after the accident, EPNG may have been

prompted to correct deficiencies in its programs. The Safety Board concludes that the OPS

did not make accurate preaccident assessments of EPNGís internal corrosion program and

therefore did not identify deficiencies in the program before the accident. The Safety

Board therefore believes that RSPA should evaluate the OPSís pipeline operator

inspection program to identify deficiencies that resulted in the failure of inspectors, before

the Carlsbad, New Mexico, accident, to identify the inadequacies in EPNGís internal

corrosion control program. The Safety Board further believes that RSPA should

implement the changes necessary to ensure adequate assessments of pipeline operator

safety programs.

Industry Standards

As shown by this accident, pipeline failure due to internal corrosion can have

serious consequences and, in the view of the Safety Board, industry standards and

recommended practices such as NACE RP0175-75, ìControl of Internal Corrosion In

Steel Pipelines and Piping Systems,î can be of significant benefit to pipeline operators.

The Safety Board is concerned that, because RP0175-75 is not considered current and may

contain outdated information, pipeline operators may not have easy access to information

that could contribute significantly to the establishment of an effective internal corrosion

control program. Even though the Safety Board has been told by NACE representatives

that the society is working on a new standard to replace RP0175-75, no timetable has been

given for the completion of this effort. The Safety Board believes that NACE International

should establish an accelerated schedule for completion of an industry standard for the

control of internal corrosion in steel pipelines that will replace or update NACE standard

RP0175-75.
49 Pipeline Accident Report

Conclusions

Findings

1. The following were neither causal nor contributory to the accident or its aftermath:

overpressure of the pipeline, the interruption in or loss of supervisory control and data

acquisition system communication, external damage to the pipeline through

excavation or other activities, and external corrosion of the pipeline.

2. Line 1103 ruptured as a result of severe internal corrosion that caused a reduction in

pipe wall thickness to the point that the remaining metal could no longer contain the

pressure within the pipe.

3. The corrosion that was found in line 1103 at the rupture site was likely caused by a

combination within the pipeline of microbes and such contaminants as moisture,

chlorides, oxygen, carbon dioxide, and hydrogen sulfide.

4. If the accident section of pipeline 1103 had been able to accommodate cleaning pigs,

and if cleaning pigs had been used regularly with the resulting liquids and solids

thoroughly removed from the pipeline after each pig run, the internal corrosion that

developed in this section of pipe would likely have been less severe.

5. As a likely result of the partial clogging of the ìdripî upstream of the rupture location,

some liquids bypassed the drip, continued through the pipeline, and accumulated and

caused corrosion at the eventual rupture site where pipe bending had created a low

point in the pipeline.

6. Had El Paso Natural Gas Company effectively monitored the quality of gas entering

the pipeline and the operating conditions in pipeline 1103 and periodically sampled

and analyzed the liquids and solids that were removed from the line, it would likely

have determined that the potential existed for significant corrosion to occur within the

pipeline.

7. Before the accident, El Paso Natural Gas Company did not have in place an internal

corrosion control program that was adequate to identify or mitigate the internal

corrosion that was occurring in its pipelines.

8. The current Federal pipeline safety regulations do not provide adequate guidance to

pipeline operators or enforcement personnel in mitigating pipeline internal corrosion.

9. The Office of Pipeline Safety did not make accurate preaccident assessments of El

Paso Natural Gas Companyís internal corrosion control program and therefore did not

identify deficiencies in the program before the accident.
Conclusions 50 Pipeline Accident Report

Probable Cause

The National Transportation Safety Board determines that the probable cause of

the August 19, 2000, natural gas pipeline rupture and subsequent fire near Carlsbad, New

Mexico, was a significant reduction in pipe wall thickness due to severe internal

corrosion. The severe corrosion had occurred because El Paso Natural Gas Companyís

corrosion control program failed to prevent, detect, or control internal corrosion within the

companyís pipeline. Contributing to the accident were ineffective Federal preaccident

inspections of El Paso Natural Gas Company that did not identify deficiencies in the

companyís internal corrosion control program.
51 Pipeline Accident Report

Recommendations

As a result of its investigation of the August 19, 2000, pipeline rupture and

subsequent fire near Carlsbad, New Mexico, the National Transportation Safety Board

makes the following safety recommendations:

To the Research and Special Programs Administration:

Revise 49 Code of Federal Regulations Part 192 to require that new or

replaced pipelines be designed and constructed with features to mitigate

internal corrosion. At a minimum, such pipelines should (1) be configured

to reduce the opportunity for liquids to accumulate, (2) be equipped with

effective liquid removal features, and (3) be able to accommodate

corrosion monitoring devices at locations with the greatest potential for

internal corrosion. (P-03-1)

Develop the requirements necessary to ensure that pipeline operatorsí

internal corrosion control programs address the role of water and other

contaminants in the corrosion process. (P-03-2)

Evaluate the Office of Pipeline Safetyís pipeline operator inspection

program to identify deficiencies that resulted in the failure of inspectors,

before the Carlsbad, New Mexico, accident, to identify the inadequacies in

El Paso Natural Gas Companyís internal corrosion control program.

Implement the changes necessary to ensure adequate assessments of

pipeline operator safety programs. (P-03-3)

To NACE International:

Establish an accelerated schedule for completion of an industry standard

for the control of internal corrosion in steel pipelines that will replace or

update NACE standard RP0175-75. (P-03-4)

BY THE NATIONAL TRANSPORTATION SAFETY BOARD 

JOHN A. HAMMERSCHMIDT JOHN J. GOGLIA

Acting Chairman Member

CAROL J. CARMODY

Member

Adopted: February 11, 2003

53 Pipeline Accident Report

Appendix A

Investigation

The National Transportation Safety Board was notified on August 19, 2000,

through the National Response Center, of a pipeline explosion and fire south of Carlsbad,

New Mexico. The Safety Board dispatched an investigative team from its Washington,

D.C., headquarters. The team comprised investigative groups in pipeline operations,

corrosion, survival factors, and family assistance. Board Members John Hammerschmidt

and Carol Carmody accompanied the investigative team. Then-Chairman Jim Hall was

also at the accident site during the on-scene portion of the investigation. No hearings or

depositions were held in conjunction with the investigation. Representatives from El Paso

Natural Gas Company and the Office of Pipeline Safety participated in the investigation.
54 Pipeline Accident Report

Appendix B

Summary of Office of Pipeline Safety Corrective Action Order

On August 23, 2000, the Office of Pipeline Safety issued a corrective action order

requiring EPNG to take the necessary corrective actions to protect the public and

environment from potential hazards associated with its pipeline operations.

The corrective action order listed 25 required corrective action items, summarized

as follows:

Line 1110 between block valve No. 6 and the Pecos River compressor station:

ï Utilizing x-ray and ultrasonic examination techniques, assess the integrity of

the pipeline at all locations that may have a no-flow condition or where liquids

may accumulate, and implement corrective actions;

ï Hydrostatically test the pipeline to at least 90 percent SMYS;

ï Prepare status reports and summary of findings and submit to RSPA;

ï After return to service plan is approved by RSPA, restrict the operating

pressure to 538 psig (80 percent of actual pressure at the time of the failure);

maintain pressure restriction until released by OPS.

Line 1103 between block valve No. 6 and the Pecos River compressor station:

ï Remain out of service until additional information about the rupture is

reviewed.

Line 1100 between station 2482+52 (6.1 miles upstream of block valve No. 6) and

the Pecos River compressor station:

ï Utilizing x-ray and ultrasonic examination techniques, assess the integrity of

the pipeline at all locations that may have a no-flow condition or where liquids

may accumulate, and implement corrective actions;

ï Obtain OPS approval for the design of the temporary crossing of the Pecos

River;

ï Hydrostatically test the pipeline to at least 90 percent SMYS;

ï Prepare status reports and summary of findings and submit to RSPA;

ï After return to service plan is approved by RSPA, restrict the operating

pressure to 538 psig (80 percent of actual pressure at the time of the failure);

maintain pressure restriction until released by OPS.
Appendix B 55 Pipeline Accident Report

Lines 1103 and 1110 between Keystone Compressor Station and Guadalupe

Compressor Station, and Line 1100 between Eunice plant and Gaudalupe

Compressor Station:

ï Restrict operating pressure to 668 psig (80 percent of MAOP) until released by

RSPA;

ï Develop a risk-based plan to inspect for indications of internal corrosion and

assess and correct (1) areas in the pipeline that cannot be inspected with an

internal inspection tool, (2) areas that may have a no-flow condition, and (3)

areas where liquids may accumulate;

ï Provide RSPA with an analysis of the continued safe operation of lines 1100,

1103, and 1110.

All pipelines operated by EPNG:

ï Obtain OPS approval of corrective action plans, which must describe the

criteria for evaluating corroded areas and the criteria used to select the

corrective action;

ï Complete the submission of EPNGís pipeline system information to the

National Pipeline Mapping System;

ï Obtain OPS approval for design of the permanent crossings of the Pecos River;

ï Develop a risk-based plan to inspect for indications of internal corrosion and

assess and correct (1) areas in the pipeline that cannot be inspected with an

internal inspection tool, (2) areas that may have a no-flow condition, and (3)

areas where liquids may accumulate.
56 Pipeline Accident Report

Appendix C

Research and Special Programs Administration Advisory 

Bulletin

On August 29, 2000, the Research and Special Programs Administration issued

Advisory Bulletin ADB-00-02 to all operators of natural gas transmission pipelines:

DEPARTMENT OF TRANSPORTATION

Research and Special Programs Administration

1. Pipeline Safety: Internal Corrosion in Gas Transmission Pipelines

AGENCY: Research and Special Programs Administration (RSPA), DOT

ACTION: Notice; issuance of advisory bulletin.

SUMMARY: The Office of Pipeline Safety (OPS) is issuing this bulletin to owners

and operators of natural gas transmission pipeline systems to advise them to review their

internal corrosion programs. Operators should consider factors that influence the

formation of internal corrosion, including gas quality and operating parameters. Operators

should give special attention to pipeline alignment features that may contribute to internal

corrosion by allowing condensates to settle out of the gas stream. This action follows a

review of incidents involving internal corrosion, some of which resulted in loss of life,

injuries, and significant property damage. OPSí preliminary investigation of a recent gas

transmission pipeline incident found wall thinning on damaged pipe associated with the

incident. The wall thinning is consistent with that caused by internal corrosion.

SUPPLEMENTARY INFORMATION:

I. Background

Internal corrosion control in gas transmission pipelines is addressed in the Federal

pipeline safety regulations at 49 CFR 192.475 and 192.477. Internal corrosion is most

often found in gas transmission pipelines and appurtenances in the vicinity of production

and gathering facilities or storage fields.

An OPS review of incident reports and inspections indicated that better industry

guidance is needed to determine the best practices for monitoring the potential for internal

corrosion in gas transmission pipelines. Some methods for monitoring internal corrosion

are weight loss coupons, radiography, water chemistry tests, in-line inspection tools, and

electrical, galvanic, resistance, and hydrogen probes. Operators should refer to available

recommended practices provided by national consensus standards organizations, such as

the American Petroleum Institute, the National Association of Corrosion Engineers, and
Appendix C 57 Pipeline Accident Report

the Gas Piping Technology Committee (GPTC) for guidance in addressing internal

corrosion issues.

OPS has worked with GPTC to revise the Guide for Gas Transmission and

Distribution Piping Systems (Guide) to better address the control of internal corrosion.

GPTC is considering modifying the Guide to address design considerations, corrective

measures and detection techniques for internal corrosion.

II. Advisory Bulletin August 29, 2000

To: Owners and Operators of Gas Transmission Pipelines.

Subject: Internal Corrosion in Gas Transmission Pipelines.

Purpose: To advise owners and operators of natural gas transmission pipelines of

the need to review their internal corrosion monitoring programs and operations.

Advisory: Owners and operators of natural gas transmission pipelines should

review their internal corrosion monitoring programs and consider factors that influence

the formation of internal corrosion, including gas quality and operating parameters.

Operators should give special attention to pipeline alignment features that may contribute

to internal corrosion by allowing condensates to settle out of the gas stream. This action

follows a review of incidents involving internal corrosion, some of which resulted in loss

of life, injuries, and significant property damage. OPSí preliminary investigation of a

recent gas transmission pipeline incident found internal wall thinning on damaged pipe

associated with the incident. The wall thinning is consistent with that caused by internal

corrosion.

Gas transmission owners and operators should thoroughly review their internal

corrosion management programs and operations:

Review procedures for testing to determine the existence or severity of internal

corrosion associated with their pipelines. Some methods for monitoring internal corrosion

are weight loss coupons, radiography, water chemistry tests, in-line inspection tools, and

electrical, galvanic, resistance and hydrogen probes.

Special attention should be given to specific conditions, including flow

characteristics, pipeline location (especially drips, deadlegs, and sags, which are on-line

segments that are not cleaned by pigging or other methods, fittings and/or ìstabbedî

connections which could affect gas flow), operating temperature and pressure, water

content, carbon dioxide and hydrogen sulfide content, carbon dioxide partial pressure,

presence of oxygen and/or bacteria, and sediment deposits.

Review conditions in pipeline segments downstream of gas production and storage

fields.

Review conditions in pipeline segments with low spots, sharp bends, sudden

diameter changes, and fittings that restrict flow or velocity. These features can contribute to

the formation of internal corrosion by allowing condensates to settle out of the gas stream.