F PB98-916503

NTSB/PAR-98/02/SUM

NATIONAL

TRANSPORTATION

SAFETY

BOARD

WASHINGTON, D.C. 20594

PIPELINE ACCIDENT SUMMARY REPORT

PIPELINE RUPTURE, LIQUID BUTANE RELEASE,

AND FIRE

LIVELY, TEXAS

AUGUST 24, 1996

7081
Abstract: This report explains the August 24, 1996, rupture of a steel pipeline operated

by Koch Pipeline Company, LP (Koch), which sent a butane vapor cloud into the

surrounding residential area. The butane vapor ignited as two residents in a pickup truck

drove into the cloud. The occupants of the truck died from thermal injuries. About 25

families were evacuated from the area. Damages related to the accident exceeded

$217,000.

From its investigation of this accident, the Safety Board identified safety issues in the

following areas: the adequacy of Koch’s corrosion inspection and mitigation actions, and

the effectiveness of Koch’s public education program, particularly with respect to educating residents near the pipeline about recognizing hazards and responding appropriately

during a pipeline leak.

As a result of its investigation of this accident, the Safety Board issued recommendations

to the Research and Special Programs Administration, Koch, 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 cause

of 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 may be obtained by contacting:

National Transportation Safety Board

Public Inquiries section, RE-51

490 L'Enfant Plaza East, S.W.

Washington, D.C. 20594

(202) 314-6551

Safety Board publications may be purchased, by individual copy or by subscription, from:

National Technical Information Service

5285 Port Royal Road

Springfield, Virginia 22161

(703) 605-6000
PIPELINE ACCIDENT SUMMARY

REPORT

Pipeline Rupture, Liquid Butane Release, and Fire

Lively, Texas

August 24, 1996

NTSB/PAR-98/02/SUM

E P L U R I B U S U N U M

NAT I ONA L TR A S PO R TATIO N

B O A R D

SA F E T Y

N

PB98-916503 National Transportation Safety Board

Notation 7081 490 L’Enfant Plaza, S.W.

Adopted: November 6, 1998 Washington, D.C. 20594

iii

Executive Summary

On Saturday, August 24, 1996, about 3:26 p.m., an 8-inch-diameter steel LPG

(liquefied petroleum gas) pipeline transporting liquid butane, operated by Koch Pipeline

Company, LP (Koch), ruptured near Lively, Texas, sending a butane vapor cloud into a

surrounding residential area. The rupture occurred under a roadway in the Oak Circle

Estates subdivision.

The butane vapor ignited as two residents in a pickup truck drove into the vapor

cloud. According to the sheriff’s report, they were on their way to a neighbor’s house to

report the release to 911. The two people died at the accident site from thermal injuries.

No other injuries were reported at that time; however, about 25 families were evacuated

from Oak Circle Estates.

Koch estimated its direct pipeline losses, including the loss of product from the

line, to be about $217,000. Other property losses included damage to the roadway under

which the rupture occurred and damage to a pickup truck, a mobile home, several

outbuildings, and adjacent woodlands.

The National Transportation Safety Board determines that the probable cause of

this accident was the failure of Koch to adequately protect its pipeline from corrosion.

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

• Adequacy of Koch’s corrosion inspection and mitigation actions, and

• Effectiveness of Koch’s public education program, particularly with respect to

educating residents near the pipeline about recognizing hazards and

responding appropriately during a pipeline leak.

As a result of its investigation of this accident, the Safety Board issued recommendations to the Research and Special Programs Administration, Koch, and NACE

International.

1

Factual Information

Accident Narrative

On Saturday, August 24, 1996, about 3:26 p.m.,1 an 8-inch-diameter steel LPG

(liquefied petroleum gas) pipeline transporting liquid butane,2

 operated by Koch Pipeline

Company, LP (Koch),3 ruptured near Lively, Texas, sending a butane vapor cloud into a

surrounding residential area. The rupture occurred under a roadway in the Oak Circle

Estates subdivision (figure 1).

The butane vapor ignited (figure 2) as two residents in a pickup truck drove into

the vapor cloud. According to the sheriff’s report, they were on their way to a neighbor’s

house to report the release to 911. The two people died at the accident site from thermal

injuries. No other injuries were reported at that time; however, about 25 families were

evacuated from Oak Circle Estates.

Koch estimated its direct pipeline losses, including the loss of product from the

line, to be about $217,000. Other property losses included damage to the roadway under

which the rupture occurred and damage to a pickup truck, a mobile home, several

outbuildings, and adjacent woodlands.

Preaccident Events

At 2:05 p.m. on the day of the accident, Koch’s Cleveland pump station (see

figure 3 for station locations) experienced an automated shutdown due to the activation of

a hydrocarbon vapor detection alarm in the station. A technician who was called out to

check the station found no vapor or evidence of a leak at the station. Cleveland pump

station is about 200 pipeline miles downstream of the accident site, and this shutdown

reduced flow through the pipeline. Corsicana station, the first pump station upstream of

Cleveland station, automatically shut down at 3:05 p.m. because the rising pipeline pressure activated a high-discharge pressure alarm.4

 The Corsicana pump shutdown created a

 

1

 Times given in this report are central daylight time.

2

 Liquid butane is a highly volatile liquid (HVL) petroleum product that vaporizes at atmospheric

pressure and room temperature. Upon release, the liquid vaporizes into a highly flammable white or nearly

transparent fog-like cloud. Because the vapor is heavier than air, it stays close to the ground and settles into

low-lying areas. While the liquid is not odorized, it has a faint but noticeable petroleum-like smell. Observation of a vapor or a fog-like cloud is typically how butane is detected in the atmosphere near a release.

3

 Koch Pipeline Company, LP (Limited Partnership), is owned by Koch Industries, Inc.

4

 A high-discharge pressure alarm is triggered when the station discharge pressure to the pipeline rises

above the set-point limit; the instrument’s switch will shut down the station.
Factual Information 2

Figure 1. Sketch showing area of butane vapor dispersement and corresponding fire

Figure 2. Accident site before the butane fire was extinguished

A

B

Pipe Rupture Site

Location of Fatalities

Fire Damage Area 

(Approximate)

Koch Pipeline

Oak Circle

County Rd 4129

A

B

Drawing not to scale

N
Factual Information 3

Figure 3. Koch Pipeline Company—

Medford, Oklahoma, to Mont Belvieu, Texas
Factual Information 4

pressure surge5 in the pipeline that traveled upstream to the previous station, Nevada

pump station. The rupture occurred between Nevada and Corsicana pump stations.

The maximum operating pressure (MOP) established by Koch for this pipeline

was 1,440 pounds per square inch, gauge (psig).6

 After the accident, Koch calculated the

highest surge pressure at Nevada pump station to be 1,448 psig based on pipeline pressure

and flow conditions before the rupture. The pipeline discharge pressure was throttled to

1,438 psig by the pump station control valve, and the pump continued to operate. The

highest surge pressure at the pipeline rupture location after the Corsicana station pump

shut down was calculated by Koch to be 1,273 psig at 3:14 p.m.

Postaccident Events

At 3:29 p.m., Koch’s supervisory control and data acquisition (SCADA) system

generated a discharge pressure rate-of-change alarm7 at Nevada pump station. At 3:36

p.m., another rate-of-change alarm was generated at Nevada pump station, and the

pipeline controller shut down the pump because of the unexplained pressure loss. At 3:39

p.m., Koch received a telephone call from an Oak Circle Estates resident reporting a

pipeline leak near his home. Koch immediately began shutdown procedures for the entire

pipeline, dispatched an employee to the accident site, and called the Kaufman County

sheriff’s department. During its call to the sheriff’s department, Koch learned that the

butane had ignited. The sheriff’s department and 911 each received a call about the

release at about the same time that Koch received its call.

Following the shutdown of its pump stations, Koch began to isolate the ruptured

section of the pipeline by closing the manual block valves upstream (4:20 p.m.) and

downstream (4:37 p.m.) of the rupture. At 5:25 p.m., Koch reported the release to the

National Response Center. By 6:00 p.m. the next day, line-plugging equipment8

 had been

installed and used to isolate a section of pipeline about 100 yards on either side of the

rupture. With the closing of the line-plugging equipment, the fuel was cut off and the fire

extinguished within minutes. The pipeline remained shut down until March 1997.

 

5

 A pressure surge is a transient or temporary increase in pressure caused by a change in flow

conditions on a pipeline such as a valve closing or a pump shutting down.

6

 The Federal pipeline safety regulation in 49 Code of Federal Regulations (CFR) Part 195.406(b)

requires that the pressure in a pipeline during surges not exceed 110 percent of the MOP.

7

 A rate-of-change alarm is generated when station discharge pressure decreases a preset amount within

a specific time as previously determined by the pipeline operator.

8

 Line-plugging equipment can be installed even when the pipeline contains product without exposing

that product to the atmosphere.
Factual Information 5

 Investigation

The National Transportation Safety Board was notified of the accident on August

24, 1996, by the National Response Center. The Office of Pipeline Safety, Research and

Special Programs Administration, conducted the on-scene investigation. Segments of the

pipeline, including the ruptured pipe, were shipped to the Safety Board Materials

Laboratory in Washington, D.C., for metallurgical examination.

Personnel and Toxicological Information

The pipeline controller, who had been on duty for about 8 1/2 hours when the

accident occurred, had been employed with Koch for 6 1/2 years. About 2 hours after the

accident, the controller was tested for drugs and alcohol; both test results were negative.

Pipeline Information

When the accident occurred, Koch’s Sterling I pipeline system was transporting

liquid butane from Medford, Oklahoma, to Mont Belvieu, Texas (about 570 miles). This

pipeline system contains sections of 8- and 10-inch-diameter pipe.

The 10-inch-diameter portion of the pipeline between Corsicana and Cleveland

pump stations (see figure 3 pipeline map) was constructed in 1929 and later purchased by

Koch. In April 1995, Koch completed replacement of the original 1929 section with new

10-inch-diameter epoxy-coated pipe to improve this section’s integrity.

The pipeline rupture occurred in the 70-mile section of 8-inch-diameter pipeline

between Nevada and Corsicana pump stations. The ruptured line, originally constructed

in 1981, was a nominal 8-inch outside diameter, American Petroleum Institute (API)

Specification 5L, Grade X-46, 0.188-inch wall thickness, Electric Resistance Weld steel

pipe. The pipe was externally field coated with spiral wrapped polyolefin tape to protect it

from corrosion. In the early 1990s, the road for the housing development was constructed

over the 8-inch-diameter pipeline at the accident site.

During construction of the 10-inch-diameter pipe in 1995, Koch shut down the

pipeline from Farmersville Junction (north of Nevada pump station) to Cleveland pump

station. Before moving LPG products again, the 8-inch-diameter section from

Farmersville Junction to Corsicana pump station was hydrostatically pressure tested in

two segments to confirm its integrity. Three failures were documented during the pressure

testing. The northern segment failed two times: the first time due to external corrosion at

1,941 psig and the second time due to a longitudinal weld seam failure at 1,938 psig. The

failure in the southern test segment, about 1.5 miles north of the accident site, occurred

because of external corrosion. The pipeline pressure when the southern segment failed

was 1,400 psig, which was less than the previously established maximum operating

pressure of 1,440 psig.
Factual Information 6

Internal Pipeline Inspection

May 1995 Internal Inspection

In May 1995, after the three hydrostatic pressure test failures, Koch had an

internal inspection performed to determine the pipeline’s condition. An internal

inspection tool (also known as a “smart pig”) was run through the 8-inch-diameter

pipeline to determine the condition of 46 miles of pipeline in the southern section. A

metal-wall-loss inspection was performed using a low-resolution magnetic-flux-leakage

(MFL) internal inspection tool. This inspection identified numerous sites of external

corrosion for possible repair.

Actual corrosion pit depths were measured on pipe excavated for correlation digs

and then compared with the log of corrosion indications from the May 1995 internal

inspection. All of the pipe-wall-thickness loss indications were graded by the internal

inspection tool company as being light (15 to 30 percent loss), moderate (> 30 and < 50

percent loss), or severe (≥ 50 percent loss). The log results were reported by individual

pipe length9

 and the grade of the maximum corrosion anomaly.

The May 1995 internal inspection log identified 62 moderately and 18 severely

corroded pipe lengths. According to Koch, the company excavated all pipe lengths graded

as having moderate or severe wall-thickness loss. Excavated pipe was either recoated,

repaired, or replaced. Koch took action based on its determination of the effect of corrosion on remaining pipe strength and allowable operating pressure using ASME/ANSI

B31G.10 The pipe that ruptured in 1996 was not excavated in 1995 because the associated

pipe length was identified by the internal inspection tool as having light corrosion.

Comparisons of the wall-thickness measurements of the pipe lengths excavated

during the repair digs with the inspection log results revealed few discrepancies. Koch’s

records from the repair digs indicate only three instances of a discrepancy between the

inspection log and actual dig report measurement. In each case, the internal inspection

tool predicted a pipe-wall-thickness loss greater than was actually measured.

The minimum hydrostatic test pressure required by pipeline safety regulations is

125 percent of the MOP. In this case, the MOP was 1,440 psig, making the minimum test

pressure for the line 1,800 psig. After pipeline repairs based on data from the internal

inspection had been completed, the line was hydrostatically tested without failure to

1,855 psig on August 18, 1995, and subsequently returned to service.

 

9

 In this pipeline, the individual 8-inch-diameter pipe lengths were about 59 feet.

10 Manual: Determining Remaining Strength of Corroded Pipelines: Supplement to B31 Code-Pressure Piping (B31G). American Society of Mechanical Engineers/American National Standards Institute,

Inc., New York, August 30, 1991.
Factual Information 7

Postaccident Internal Inspection

On September 23, 1996, about 1 month after the accident, a 10-mile section of

Koch’s pipeline around the rupture site was inspected using a high-resolution MFL

internal inspection tool. (The inspected section did not include that segment of pipe

around the rupture that was removed after the accident.) The internal inspection was

required by Hazardous Facility Order (HFO) CPF No. 46510-H that was formally issued

on October 7, 1996, by the Office of Pipeline Safety (OPS), Research and Special

Programs Administration (RSPA). The inspection identified numerous areas that were

graded by the internal inspection company as having moderate and severe corrosion.

Indications of severe corrosion were identified in about 15 lengths of pipe. These areas

were not identified during the May 1995 inspection as having either moderate or severe

corrosion.

External Corrosion Control

Koch uses an impressed current cathodic protection11 system to mitigate corrosion

on this pipeline. The Koch Procedure Manual (section 4.8.1) for this pipeline defined the

minimum acceptable pipe-to-soil potential12 level for adequate cathodic protection as at

least -0.85 volts (V).13 To comply with 49 CFR 195.416(a), pipeline operators must

perform annual testing to determine whether cathodic protection is adequate to control

external corrosion. The regulation does not provide criteria for “adequate cathodic

protection.” Company corrosion technicians performed annual surveys14 of the cathodic

protection system. Koch personnel also recorded cathodic protection readings on its field

reports.15

 

11 Cathodic protection is a corrosion mitigation method used by the pipeline industry to protect

underground metal pipes using rectifier stations along the pipeline that supply protective electrical current.

Cathodic protection current is forced to flow in the opposite direction of currents produced by corrosion

cells. A rectifier converts alternating current from the utility service to direct current and supplies it to a

ground bed that typically contains a string of suitable anodes, with soil as an electrolyte, to provide a path

for the current from the rectifier to the pipeline. A cable connected to the pipeline provides the return path

to the circuit.

12 Defined as “the voltage difference between a buried metallic structure [pipe] and the electrolyte

[soil], measured with a reference electrode in contact with the electrolyte [soil].” From Gordon, H. L.,

Cathodic Protection, Power Plant Electrical Reference Series, Project 2334, Electric Power Research

Institute, Palo Alto, California, 1991, vol. 11, p. 11.2.

13 One of the cathodic protection criteria for pipelines transporting gas listed in 49 CFR 192,

appendix D, is maintaining cathodic protection of at least -0.85 V pipe-to-soil potential to a saturated

copper-copper sulfate half cell.

14 Pipeline companies perform pipe-to-soil potential surveys by measuring and recording the voltages

and currents at test stations along the pipeline and at rectifiers. Measurement intervals vary widely from less

than 100 feet to miles apart.

15 Koch refers to the company form used for field reporting of aerial, foreign crossing, exposed pipe,

and pipeline revisions as a “4-in-1” report.
Factual Information 8

Preaccident Inspections and Action

Before the accident, six rectifiers were used in the pipeline cathodic protection

system from Nevada to Corsicana pump stations. In the first quarters of 1994 and 1995,

Koch personnel conducted an annual corrosion control survey that indicated the pipeline

met the company standard for cathodic protection (pipe-to-soil potentials at least as

negative as -0.85 V). During the annual

survey in February 1996, potentials below the company’s accepted protection

level were recorded between rectifiers

M-7 and M-10. The pipeline rupture

occurred between rectifiers M-9 and

M-9.5, which were the existing units on

either side of the rupture location.

(Figure 4 shows the location of the

rectifiers and the rupture.)

In field reports completed after

the May 1995 internal pipeline inspection, some readings indicated potential

levels that did not meet the company

standard. For example, records show that

on August 28, 1995, an area about 1/4

mile south of the rupture had an

approximate pipe-to-soil potential of

-0.59 V and on August 24, 1995, an area

7/8 mile north of the rupture had a

potential of -0.59 V. Similar low

potentials were recorded up to 50 miles

north of the rupture site to an area

upstream of Nevada station.

On February 6, 1996, during

Koch’s 1996 annual survey, the output

of rectifier M-8 was increased to

improve pipe-to-soil potentials. On

February 13, 1996, potentials as low as

-0.68 V were recorded between rectifiers

M-7 and M-8. Additionally, seven of

nine readings taken on that date between

rectifiers M-8 and M-9 were less

negative than -0.85 V. These low

potential measurements were in the -0.62

to -0.72 range.

Figure 4. Koch pipeline

rectifier sites M-7 through M-10
Factual Information 9

Potential measurements taken between rectifiers M-9 and M-10 on February 13,

1996, were -0.815 V about 1.3 miles north of the rupture location and -0.827 V about 1.5

miles south. In addition to these readings, the lowest potential recorded on that date

between rectifiers M-9 and M-10 was -0.78 V.

In a memorandum dated February 19, 1996, the corrosion supervisor

recommended that a new rectifier be installed north of the eventual rupture site between

M-8 and M-9. The area from rectifiers M-9 to M-10 was reported by the corrosion

supervisor as having “good” readings. On February 26, 1996, Koch division personnel

authorized installation of a new rectifier, which was initially labeled M-8.5 but was

subsequently redesignated M-8.6.

On March 29, 1996, rectifier M-9 was not operating at its designated level and its

ground bed needed replacement. No recorded pipe-to-soil readings are available for that

date. Koch Division personnel discussed whether M-9 should be moved or the ground

bed replaced. They decided to wait until the new rectifier was installed to verify its

cathodic protection coverage and to determine how M-9 would be repaired.

Postaccident Inspections and Action

According to Koch, pipe-to-soil potentials were measured but not recorded for the

accident site after the rupture on August 24, 1996. However, potential readings recorded

500 feet north and south of the rupture site on August 27 ranged from -0.49 V to -0.52 V.

Shortly after the accident, on September 4, 1996, Koch replaced the ground bed for

rectifier M-9. Koch installed the new rectifier (M-8.6) and activated it on September 11,

1996. Pipe-to-soil potentials taken during the close-interval survey16 in the rupture area

remained low, about -0.65 V, after these rectifiers were activated.

After the rectifiers were activated, pipe-to-soil potentials were obtained during

repair digs made following the September 23, 1996, internal inspection. Readings

recorded on the field reports at several dig locations up to 1 1/4 miles north of the rupture

ranged from -0.70 to -0.75 V and up to 1/4 mile south of the rupture ranged from -0.59 to

-0.73 V. These areas were reported on the 1995 internal inspection survey as having

either light (15 to 30 percent) or no reportable corrosion (< 15 percent). When the pipe

was excavated after the accident, corrosion pinholes (very small-diameter holes through

the pipe wall) were found, and corrosion pits greater than 0.180-inch deep were measured

at several locations along the pipeline. These reports also noted that the pipeline coating

 

16 In a close-interval survey, pipe-to-soil potential is measured every few feet (typically every 2.5 feet).

This survey is useful for identifying cathodic protection problems such as low potentials between

established test points, the presence of stray currents, and areas of gross coating loss.
Factual Information 10

had some “holidays” (breaks or bare spots), stress cracking, wrinkles, and disbonded

areas.17 Tree roots were also observed in the backfill next to the pipe in one of these areas.

In October 1996, Koch completed a close-interval survey of the 10-mile section

around the rupture site. Potentials less negative than -0.85 V were recorded in many areas

during this survey. In addition, some areas of missing coating were noted. No indications

of stray currents were found.

Additional rectifier installations were proposed for five new locations between

Nevada and Corsicana pump stations as well as for other locations in the pipeline system.

The last rectifier of this group was activated on February 17, 1997.

After the accident, the soil resistivity near the accident area was measured. Soil

resistivity data are useful for determining corrosive characteristics of the soil and

estimating their impact on cathodic protection. Low soil resistivity readings of

507 ohm-cm at the rupture site, 862 ohm-cm 50 feet north of the rupture site, and 1,149

ohm-cm 50 feet south of the rupture site were recorded. Soil resistivity values at these

levels generally indicate highly corrosive soil.18

Pipe Examination

After the fire was extinguished, the accident site was excavated and the ruptured

pipe exposed. The backfill contained partially decomposed organic material including

tree roots and had a sewer-like odor. Shortly after the accident, about 95 feet of pipe was

removed from the pipeline. A 46-inch section containing the rupture (figure 5) and three

nearby sections (6 to 7 feet long) were examined at the Safety Board’s Materials

Laboratory in Washington, D.C.

The pipe rupture was longitudinal, approximately 12.5 inches long (figure 5, right

to left). The rupture occurred at the 4 o’clock circumferential position relative to the

pipe’s position in the ground, with 12 o’clock being the top of the pipe. Significant

corrosion was found at the center of the pipe rupture. Most of the tape coating on the

ruptured segment was destroyed in the fire, thus the coating condition before the rupture

could not be determined.

 

17 Cathodic protection current requirements are significantly reduced when buried pipeline is properly

coated using an effective barrier coating. However, factors such as overprotection (potentials significantly

more negative than -0.85 V), inadequate coating selection, improper surface preparation or application of

the primer or coating, or soil stresses may result in coating disbondment. If soil or moisture is present on the

pipe surface underneath the disbonded coating, the pipe could corrode even in a cathodically protected

system. Because the disbonded coating acts as an electrical shield, the amount of current reaching the metal

underneath the disbonded coating depends upon the resistance of the soil or water present in the gap created

by the disbonded coating. Though some current may flow to the pipe surface in this space, more current

goes to other, more easily accessible, areas (low resistance path). Typically, the current density underneath

the disbonded coating is insufficient to provide adequate corrosion protection.

18 Corrosion Control/Systems Protection. Volume VI—Technical Services, Book TS-1, American Gas

Association, Arlington, Virginia, 1986, p. 79.
Factual Information 11

The center of the rupture contained an area of corrosion about 5 inches long by 3

inches wide. In the rupture area, corrosion pits appeared to have substantially penetrated

the pipe wall indicating nearly 100-percent wall-thickness loss. No other pitting was

observed on the remainder of the 46-inch section of pipe containing the rupture. No

evidence of a material flaw or of mechanical damage (dents, gouges, or scrapes) to the

pipe was observed. Figure 6 is a composite of two photographs, one of each side of the

rupture, constructed to show the two sides of the corroded area in proximity. The arrows

in the photo indicate where corrosion pitting had substantially penetrated the pipe wall.

Figure 5. Pipe section containing 12.5-inch rupture

Figure 6. Composite photograph showing corroded area at center of

rupture
Factual Information 12

Coating damage as observed in the field is shown in figures 7 and 8. The three pipe

sections (both upstream and downstream of the rupture) brought to the Materials

Laboratory for testing had disbonded and cracked spiral wrapped tape coating at several

locations. Mechanical damage to the tape coating similar to damage caused by a pipelocating probe was also observed. Scratches were found on the pipe at several of the

coating tears. Corrosion was observed on the exposed pipe surfaces at the damaged areas.

All of the nearby pipe segments examined by the Materials Laboratory displayed

corrosion damage, from 30- to 64-percent wall-thickness loss. Five principal areas of

corrosion damage correlated with five corrosion areas on the 1995 inspection log;

however, these areas had been graded as having less than 30-percent pipe-wall-thickness

loss in 1995.

A consultant for Koch performed testing and analysis for bacteria19 on the pipe

using a procedure similar to NACE International Standard TM 0194-94.20 An area

selected for bacteria testing included one of the corrosion areas containing rust tubercles21

 

19 Microorganisms, such as bacteria and fungi, can cause underground corrosion.

20 NACE International Standard TM 0194-94, Field monitoring of bacterial growth in oil field

systems. NACE International (formerly National Association of Corrosion Engineers—NACE), Houston,

Texas, 1994.

21 Knob-like mounds formed on the pipe as the result of localized corrosion.

Figure 7. Disbonded tape coating on 8-inch pipe extracted at accident site

(Arrows show disbonded area under tape coating.)
Factual Information 13

within 20 feet of the rupture. The consultant’s report provided the following laboratory

analysis results:

• Pipe surface samples were acidic with a pH of 5 to 6,

• Sulfides were present in small amounts,

• Sulfate-reducing bacteria were present in insignificant amounts,

• Anaerobic acid-producing bacteria were present in small amounts (100

bacteria/ml), and

• Aerobic acid-producing bacteria were “strongly present” (10,000 bacteria/ml).

The consultant’s report concluded, “The results of the testing performed here

indicate that Aerobic Acid Producing bacteria are the main contributor to the corrosion

found on this pipe.”

Concerning the testing, the consultant’s report said the results “may not be

representative of bacteria activity” because of the inadequate sampling techniques and

handling time. The report further noted, “Bacteria typically have a life of 30 to 40 hours

and can change their populations significantly in 2 days if their environment is changed.”

In this instance, Koch had cleaned the pipe when it was removed from the ground, and

laboratory tests were not performed until about 48 hours later. The consultant used tap

water for sample preparation instead of the phosphate-buffered saline solution

recommended in NACE International Standard TM 0194-94.

Figure 8. Cracks in the tape coating on 8-inch pipe excavated at accident site
Factual Information 14

Public Education

Preaccident Public Education Mailings

In 1991, Koch conducted a public education program for people living within 1/4

mile of the pipeline. In 1991 and 1992, public education materials were hand-distributed

door to door by company representatives. In 1992, Koch produced a report that included

tabulations of the total number of material packets issued and the response cards returned

to the company.

From 1993 through early 1996, Koch distributed its public education materials by

annual mailings, using addresses compiled from returned response cards, from lists

developed by company representatives canvassing the area, and from property right-ofway records. Koch solicited and received public education information from other

pipeline companies for comparison with its program. Koch representatives also attended

industry meetings where public education information was reviewed.

An “Information Bulletin” was provided as part of the 1996 public education

materials mailed to residents before the accident. (See appendix A.) The bulletin

highlighted telephone numbers for notifying Koch before performing excavation near the

pipeline or during a pipeline emergency. The bulletin discussed the propane-butane

family of products transported by the pipeline, how to recognize a product release, and

the importance of keeping “sources of ignition” away from liquid spill areas. In addition,

the 1996 mailing included a calendar bearing a warning not to perform excavation near

the pipeline until Koch is notified. Recipients also received response cards for providing

their addresses and address corrections or for requesting additional information.

In 1996, about 45 families lived on two roads in the area of the accident, Oak Park

Circle and County Road 4129 (figure 1). Of the 45 residences listed on the two roads,

only 5 addresses appeared on Koch’s 1996 preaccident mailing list. The two families that

suffered fatalities were not on the mailing list. The person who called Koch to report the

release was on the mailing list.

Koch’s public education program provided educational materials to public offices

and emergency response organizations serving the areas in which the pipeline was

operated. The head of the Kaufman County Emergency Management Office indicated that

Koch had provided information and communicated with the office. The Kaufman County

Sheriff’s Department was on Koch’s mailing list and had been invited to yearly governmental liaison meetings in 1995 and 1996.
Factual Information 15

Industry Public Education Program Standard

American Petroleum Institute (API) Recommended Practice 1123, Development

of Public Awareness Programs by Hazardous Liquid Pipeline Operators,

22 provides

information on reaching the public, safety message content, communications methods,

and program evaluation. API Recommended Practice 1123 provides some information on

resources available to companies for developing and distributing their own safety

materials and on other methods of providing information. Section 6.8 of the publication

states that “Operators that use their own mailing lists when they mail public awareness

materials to the public should maintain up-to-date lists” and that response cards “permit

the recipients to notify the operators of any changes of address and could measure the

effectiveness of the safety message.” Section 9 provides information that a pipeline

operator can use to evaluate the effectiveness of its public awareness program, including

scientifically based evaluation techniques available to ensure that program objectives are

being met (section 9.4).

Postaccident Public Education Mailing

As a result of an HFO issued after the accident by the OPS, Koch revised and

reformatted its public education materials (appendix B). Some of the changes Koch made

to its public education program include:

• Replacing its previous mailing list for residents along the pipeline right-ofway with a mailing list developed using mapping grid databases.

• Revising safety information to include pertinent information on detecting a

pipeline leak and actions to take when a leak is suspected.

• Prominently highlighting material in the new safety brochure on:

1. how to identify Koch’s pipelines,

2. precautions to take around Koch’s pipelines during excavation activity,

3. how to identify a pipeline leak and a highly flammable vapor cloud,

and

4. actions to take in addition to notifying Koch, when a leak is suspected

or a vapor cloud is detected.

 

22 Recommended Practice 1123, Development of Public Awareness Programs by Hazardous Liquid

Pipeline Operators, American Petroleum Institute, Washington, D.C., August 1996.
Factual Information 16

Regulations and Orders Governing Pipeline Operation

External Corrosion Control Safety Regulation

Title 49 CFR 195.416 contains a number of requirements concerning safe pipeline

operations:

(a): Each operator shall, at intervals not exceeding 15 months, but at least

once each calendar year, conduct tests on each buried, in contact with the

ground, or submerged pipeline facility in its pipeline system that is under

cathodic protection to determine whether the protection is adequate.

(e): Whenever any buried pipe is exposed for any reason, the operator shall

examine the pipe for evidence of external corrosion. If the operator finds

that there is active corrosion, that the surface of the pipe is generally

pitted, or that corrosion has caused a leak, it shall investigate further to

determine the extent of the corrosion.

(g): If localized corrosion pitting is found to exist to a degree where

leakage might result, the pipe must be replaced or repaired, or the

operating pressure must be reduced commensurate with the strength of the

pipe based on the actual remaining wall thickness of the pits.

This regulation does not provide specific criteria for “adequate cathodic protection” for liquid pipelines. Specific criteria for cathodic protection can be found in

appendix D of the gas pipeline safety regulations, 49 CFR 192.

Public Education Safety Regulation

Title 49 CFR 195.440 requires that pipeline operators establish a continuing

education program to enable the public, appropriate Government organizations, and

persons engaged in excavation-related activities to recognize a hazardous liquid or a

carbon dioxide pipeline emergency and report it to the operator or to fire, police, or other

appropriate officials. The regulation does not specifically identify the information that

must be provided or require that the pipeline operator periodically evaluate the

effectiveness of its public education program. The OPS inspection of Koch’s public

education program before the accident in May 1993 identified no deficiencies.

Office of Pipeline Safety Hazardous Facility Order

On October 7, 1996, about 6 weeks after the accident, the OPS issued an HFO that

directed Koch to submit written plans, to include performing corrective actions

concerning pipeline operation and public education. The HFO’s requirements include but

are not limited to the following provisions:
Factual Information 17

Submit for approval by the Regional Director, within 30 days after an

Order is issued, a written plan addressing a program of tests or studies that

will identify the extent of and propose a solution to the external corrosion

problem on the HVL line and allow for verification and maintenance of

the HVL line. The plan is to include, at minimum, provisions and time

frames for identifying the extent of corrosion and correcting the external

corrosion problems on the HVL line. The plan should address, at

minimum—

The 8-inch [diameter] pipeline section [containing the accident location]

between block valves at stations 17316+16 to 17849+48 (approximately

10 miles).

i. Run an ultrasonic “smart” pig or high resolution magnetic flux

“smart” pig [internal inspection instrument] to determine pipe wall

condition.

ii. Complete installation of new ground bed and test, and activate

rectifier.

iii. Perform a close interval survey.

iv. Retain any exposed pipe removed from the line during preparation for

the “smart” pig run [internal inspection] for OPS examination.

Provide a detailed pipe and coating condition report.

v. Notify the appropriate public officials of Henderson and Kaufman

Counties whenever tests are performed involving the movement of

HVLs through the pipeline.

vi. Expose anomalies indicating 20 percent or greater wall loss, and

repair or replace areas of 20 percent or greater wall loss, or as may be

agreed upon with the Regional Director.

vii. Determine MOP subject to final approval by the Regional Director.

viii. The Corrosion mitigation measures must conform with approved

industry standards such as NACE Standard RP-0169-92,

Recommended Practices for Control of External Corrosion on

Underground or Submerged Metallic Piping Systems.

ix. Results of test and metallurgical and chemical analysis of pipe now

underway.

Except for items ii, iii, and ix, the above requirements also apply to the remainder

of the 8-inch and 10-inch-diameter sections of Koch’s HVL pipeline. In addition, the

HFO modifies item v for those pipeline sections as follows: “Notify the appropriate

public officials in affected counties whenever tests [are performed] involving the

movement of HVLs through the pipeline.”

The HFO also addresses Koch’s public education program. The HFO specifies

that Koch—
Factual Information 18

Submit for approval by the Regional Director, within 30 days after an

Order is issued, a written plan to provide a public awareness program for

residents located along the pipeline right-of-way. The program, at

minimum, should include the following information—

a. Identification of pipeline location.

b. Recognizing an HVL pipeline leak and action to be taken.

c. Reporting to Koch any right-of-way encroachments or other activity

which could damage the pipeline.

d. Information about the danger of operating motorized vehicles and

equipment in or near a vapor cloud caused by HVLs escaping from a

ruptured pipeline.

Provide verification to the Regional Director that this program is being

carried out.

Koch submitted the plan required by the HFO to the OPS.
19

Safety Issues

This analysis is divided into two general sections. The first section reviews the

accident itself, highlighting the actions and events that resulted in problem conditions.

The balance of the analysis discusses the safety issues identified as a result of this

accident:

• Adequacy of Koch’s corrosion inspection and mitigation actions, and

• Effectiveness of Koch’s public education program, particularly with respect to

educating residents near the pipeline about recognizing hazards and

responding appropriately during a pipeline leak.

Accident Discussion

At 2:05 p.m. on the day of the accident, the pump at Cleveland pump station (see

figure 3) experienced an automated shutdown due to a hydrocarbon vapor detection alarm

in the station. As a result of the shutdown, pressure increased on the pipeline upstream of

Cleveland pump station. At 3:05 p.m., Corsicana pump station automatically shut down

due to a high-discharge pressure alarm being activated. When the Corsicana pumps shut

down, a pressure surge traveled from Corsicana upstream toward Nevada pump station.

Based on an analysis of SCADA data, the pipeline ruptured between the two stations

about 3:26 p.m.

No indications of excavation damage, such as dents or gouges on the pipe, were

observed at the rupture site. The rupture occurred at a location where the pipe wall had

been reduced due to corrosion. However, when the internal inspection tool was run about

15 months earlier, the wall-thickness loss in this area of the pipeline was identified as

being significantly less than at the time of the accident. Therefore, this analysis examines

the adequacy of Koch’s corrosion inspection and mitigation actions.

When the pipe ruptured, it sent a butane vapor cloud into the surrounding

residential area. The butane vapor ignited (figure 2) as two residents in a pickup truck

drove into the vapor cloud on their way to a neighbor’s house to report the release to 911.

Therefore, the analysis also examines the effectiveness of Koch’s public education program, particularly with respect to educating residents near the pipeline about recognizing

hazards and responding appropriately during a pipeline leak.
Safety Issues 20

Internal Pipeline Inspection

A possible explanation for the pipeline’s rapid corrosion and failure in 15 months

was that the 1995 internal inspection significantly underreported pipe-wall-thickness loss

at the rupture site. Defect geometry related to size and orientation, such as dents, gouges,

or narrow cracks in the longitudinal direction may create corrosion-feature-reporting

problems. However, the Safety Board Materials Laboratory examination of pipe

excavated near the rupture site identified no such defects. Also, comparison of actual

wall-thickness-loss data with the internal inspection logs for the pipe locations excavated

for repair by Koch showed good correlation. In the three instances where discrepancies

between the 1995 log and the actual dig reports were observed, the internal inspection

instrument predicted a wall-thickness loss that was greater than actually measured.

The Safety Board recognizes that the possibility of underreporting of corrosion

damage at the accident site during the 1995 internal pipe inspection cannot be totally

eliminated. However, the good correlation between the 1995 inspection log and actual dig

reports and the absence of problematic defect geometry indicate that underreporting of

corrosion damage probably did not occur. Therefore, the Safety Board concludes that it is

unlikely that the pipeline corrosion damage near the rupture location was underreported

by the 1995 internal inspection.

In addition, about 15 lengths of pipe in a 10-mile section around the rupture site

were graded as exhibiting severe corrosion by the September 1996 internal inspection

performed a month after the accident. However, none of the pipe lengths examined in the

1996 inspection had been identified as being either moderately or severely corroded by

the May 1995 inspection. Therefore, the Safety Board concludes that corrosion damage

found during the 1996 postaccident inspection indicated that rapid corrosion had occurred

on the pipeline since the 1995 internal inspection.

Microbial Testing

A procedure similar to NACE International’s TM 0194-94 oil field standard was

used by Koch’s consultant to obtain corrosion samples and test them for bacteria. The

consultant’s analysis of corrosion products from a pipe location within about 20 feet of

the accident site indicated low levels of anaerobic bacteria and sulfides and an even

smaller number of sulfate-reducing bacteria. The consultant noted that aerobic acidproducing bacteria were primarily present in the corrosion products. The consultant

concluded that aerobic acid-producing bacteria mainly contributed to the pipe’s corrosion.

However, the report provided no information about the corrosion rate or time frame in

which corrosion may have occurred.

The consultant’s analysis could be inaccurate because Koch personnel cleaned the

pipe after it was removed from the ditch and before the samples were collected. Another

inaccuracy may have been introduced because laboratory tests were performed about
Safety Issues 21

2 days after the pipe was removed from the ground. The consultant’s report suggested

that the adverse effect of the cleaning and delay in sampling might have been offset by the

fact that samples were taken from tubercles on the pipe. However, these factors are

important because of their significant impact on the aerobic and anaerobic bacteria

populations. As noted in the consultant’s report, bacteria typically have a life of 30 to 40

hours, and their populations can change significantly within 2 days of a change to their

environment.

More importantly, and not specifically stated in the report, is the sensitivity of

anaerobic and sulfate-reducing bacteria to an oxygen environment. The relevant factor in

sample preparation was the use of tap water, which most likely contaminated the sample

with oxygen and thus created a bias for aerobic microbes. No additional microbial testing

was done, and the accuracy of the testing performed remains questionable. Therefore, the

Safety Board concludes that the contribution of microbes to the corrosion damage cannot

be accurately determined because of inadequate sampling and testing techniques.

Furthermore, as noted earlier, Koch’s consultant used a procedure similar to the one in

the NACE International Standard (TM 0194-94), which describes field testing methods

for estimating bacteria populations commonly found inside oil field piping systems and is

not directly applicable to sampling and testing for microbes from an external pipeline

surface. The Safety Board believes that NACE International should develop a standard for

microbial sampling and testing of external surfaces on an underground pipeline.

External Corrosion Control

The cause of pipeline corrosion can be difficult to determine because different

corrosion phenomena could operate simultaneously in the same general area, resulting in

multiple damage sites with corrosion progressing at widely varying rates.

Stray currents constitute one phenomenon that can contribute to corrosion.

However, the annual cathodic protection system surveys that Koch performed before the

accident gave no indication that stray currents were present. Close-interval surveys

performed after the accident in 1996 also indicated that the system did not have stray

current problems. The Safety Board concludes that stray currents did not contribute to the

corrosion observed on the pipeline.

Another factor that can contribute to corrosion is the failure to maintain adequate

cathodic protection. After the internal inspection in 1995, the pipe-to-soil potentials

recorded on field reports during repairs were below the acceptable cathodic protection

level established by the company. Koch did not correct this observed low potential

problem. The Safety Board therefore concludes that inadequate corrosion protection at the

rupture site and at numerous other locations on the pipeline allowed active corrosion to

occur before the accident.

Coating condition also affects the ability to adequately protect pipe from

corrosion. Stress-cracked and disbonded coating was observed after the accident near the
Safety Issues 22

rupture location. In the case of the pipe near the accident site, the stress-cracked and

disbonded coating created areas where soil and moisture could come in contact with the

pipe surface.

In addition to exposing pipe to microbial corrosion, stress-cracked and disbonded

coating may have interfered with Koch’s ability to provide adequate cathodic protection

by exposing more bare pipe surface and consequently increasing the pipe’s demand for

protective current. The disbonded coating may have further decreased the effectiveness of

cathodic protection by creating a barrier or shield to the protective current. The low

potentials observed at a number of excavations before the accident indicated that the pipe

was not receiving the necessary protective current. The Safety Board concludes that

because cathodic protection levels were inadequate, the stress cracks that existed in the

coating created areas in which rapid corrosion could occur. The Safety Board further

concludes that the disbonded tape coating most likely created locally shielded areas on

the pipe that prevented adequate cathodic protection current from reaching its surface,

creating other areas where rapid corrosion could occur. In addition, the Safety Board

concludes that stress cracks and disbonded tape coating on the pipe created areas where

microbial corrosion could potentially occur.

Since the accident, Koch has taken action to improve corrosion protection on its

pipeline. After the accident, pipe-to-soil potentials were still low in the vicinity of the

rupture. Therefore, in the 2 weeks following the accident, Koch replaced an anode ground

bed to repair one rectifier and installed the previously proposed new rectifier. By

February 1997, the company had installed five additional rectifiers between rectifiers M-7

and M-10 because potentials were still below the company standard.

Koch also advised the Safety Board that it has been evaluating two alternatives to

ensure the integrity of its line. One is to repair and re-coat a 70-mile section of its pipeline

between Nevada and Corsicana pump stations; the other is to replace this 70-mile section

of the pipeline. Koch has communicated these proposals to the OPS. The Board

recognizes that the OPS has included a number of requirements in the HFO to specifically

address identifying the extent of the external corrosion problem on the HVL pipeline.

However, the HFO does not contain a specific requirement to evaluate coating condition,

and Koch’s field reports indicate that the corrosion problem extends beyond the 70-mile

section proposed for repair or replacement. The Safety Board concludes that the tape

coating on Koch’s entire 8-inch pipeline may have stress cracking and disbondment.

Therefore, the Safety Board believes that RSPA should require that Koch evaluate the

integrity of the remainder of its HVL pipeline, including the condition of the coating, and

rehabilitate the pipeline as necessary. Further, the Safety Board concludes because no

overall requirement exists for operators to evaluate pipeline coating condition, problems

similar to those that occurred on Koch’s pipeline could occur on other pipelines. The

Safety Board believes that RSPA should revise 49 CFR Part 195 to require pipeline

operators to determine the condition of pipeline coating whenever pipe is exposed and, if

degradation is found, evaluate the coating condition of the pipeline.
Safety Issues 23

The OPS requires that pipeline operators conduct tests annually (not to exceed 15

months between tests) for pipelines under cathodic protection to determine that the

protection is adequate (49 CFR 195.416). However, the regulation does not provide performance measures for “adequate cathodic protection” for liquid pipelines. Performance

measures for cathodic protection can be found in appendix D of the gas pipeline safety

regulations, 49 CFR 192. The Safety Board, as a result of its investigation of a 1986

accident23 involving a liquid pipeline, recommended that RSPA provide cathodic

protection criteria for liquid pipelines:

P-87-24

Revise 49 CFR Part 195 to include criteria, similar to those found in

Part 192, against which liquid pipeline operators can evaluate their

cathodic protection systems.

Because RSPA failed to take meaningful action to address this recommendation,

the Safety Board classified Safety Recommendation P-87-24 “Closed—Unacceptable

Action” on January 23, 1996. The Safety Board concludes that this accident illustrates the

continuing need for performance measures for adequate cathodic protection on liquid

pipelines and believes that RSPA should revise 49 CFR 195 to include performance

measures for the adequate cathodic protection of liquid pipelines.

In addition to having appropriate cathodic protection performance measures, an

operator should promptly evaluate all available corrosion-related data, such as potential

measurements, internal inspection results, and coating condition to maintain adequate

corrosion protection levels throughout a pipeline.

The need for a timely evaluation of corrosion-related data is evident in this

accident. Catastrophic failure occurred in an area of the pipeline where significantly less

corrosion had been identified by an internal inspection tool about 15 months earlier.

Corrosion found on the pipe excavated as a result of the 1995 internal inspection

confirms that active corrosion was occurring at various locations on the pipeline system.

When buried pipe was exposed in 1995 after this internal inspection, Koch recorded low

pipe-to-soil potentials on its field reports. Even though the recorded pipe-to-soil

potentials in many cases were below the company standard for cathodic protection, Koch

did not ensure that cathodic protection levels were restored to the company standard. In

addition, stress cracking and disbonded coating were observed at numerous locations and

recorded in the exposure reports. Excavations made as a result of the accident and during

the 1996 internal inspection done after the accident indicate that active corrosion was

continuing on the pipeline. The Safety Board concludes that although Koch’s records

contained information that cathodic protection levels were inadequate and that active

corrosion was occurring on its pipeline system before the accident, the conditions went

uncorrected.

 

23 For more detailed information, read Pipeline Accident Report—Williams Pipe Line Company Liquid

Pipeline Rupture and Fire, Mounds View, Minnesota, July 8, 1986 (NTSB/PAR-87/02).
Safety Issues 24

Koch informed the Safety Board that as of September 1998, the company was

expanding the distribution of its field reports and notifying corrosion technicians when

specific conditions are detected so that a field inspection can be made. However, Koch

needs to take more comprehensive action to evaluate data so that it can promptly provide

adequate corrosion protection to its pipeline. The Safety Board believes that Koch should

establish a procedure to promptly evaluate all data related to pipeline corrosion, such as

annual cathodic protection surveys, field reports, internal inspection results, and coating

condition data, to determine whether the pipeline’s corrosion protection is adequate, and

take necessary corrective action.

Public Education

The content of the 1996 bulletin sent by Koch (appendix A) as part of its public

education package before the accident had two important shortcomings. The bulletin’s

first shortcoming was that key information on recognizing a leak and taking appropriate

action lacked clarity and was not formatted to alert readers of its importance. In addition,

the complex language used in the bulletin diluted the warning. For example, while the

bulletin stated that vapors are extremely flammable, it also provided technical

information on vapor ignition temperature and atmospheric concentration that distracted

readers’ attention from the message that such vapors pose a major hazard and require

caution if their presence is suspected.

The bulletin’s second shortcoming was that the warning was not specific enough.

It omitted crucial information such as warning people not to operate switches, equipment,

machinery, or motor vehicles in or near a vapor cloud; not to light a match or smoke; and

not to drive into or go back into the vapor cloud. Furthermore, the bulletin failed to urge

readers to inform others in the household of the warning, which is a way to disseminate

crucial safety information beyond the initial reader. The Safety Board concludes that the

format and content of the public education bulletin mailed by Koch before the accident

did not effectively convey important safety information to the public.

Another significant issue involved the distribution of Koch’s public education

materials. Before the accident, Koch developed its mailing list through door-to-door

canvassing and then used response card returns to verify the accuracy of coverage in the

accident area. However, during the 1996 mailing, only 5 of the 45 residences near the

accident site were sent Koch’s educational materials. Significantly, Koch’s 1996 mailing

list did not include the two families that suffered fatalities in the accident. In all, Koch’s

mailing on the dangers of a pipeline release and actions to take during a pipeline

emergency reached only a limited number of people living near the accident location.

Therefore, the Safety Board concludes that Koch’s distribution program for its public

education materials before the accident was inadequate. Since the accident, Koch has

improved the information presented in its educational bulletin and its method for

distributing public education materials.
Safety Issues 25

The pipeline safety regulations do not provide clear and specific requirements for

the content and distribution of a pipeline operator’s public education program. The lack

of such requirements contributed to the failure, before the accident, to identify deficiencies in Koch’s public education program. After the accident, the OPS issued an HFO

that included requirements for Koch to improve its mailing list and revise its safety

brochure to prominently feature information on recognizing a pipeline leak and on actions

people should take in response to a leak.

Further, existing safety regulations do not require pipeline companies to evaluate

the effectiveness of their public education programs. Without such evaluations, operators

may not realize that a program is not achieving its objectives. One source for developing

a scientific means to evaluate the effectiveness of public education programs is API

Recommended Practice 1123, which contains information on evaluation methods. The

Safety Board concludes that requirements for the content, format, and periodic evaluation

of public education programs can help pipeline operators ensure that their programs are

effective. The Safety Board believes that RSPA should revise 49 CFR Part 195 to include

requirements for the content and distribution of liquid pipeline operators’ public

education programs. The Safety Board also believes that RSPA should revise 49 CFR

Part 195 to require that pipeline operators periodically evaluate the effectiveness of their

public education programs using scientific techniques.

The Safety Board has long been concerned about the issue of pipeline public

education programs, including the content, distribution and the effectiveness of pipeline

operators’ safety materials for both hazardous liquid and natural gas pipelines. As a result

its investigation of a series of 5 natural gas accidents24 in Kansas, from September 16,

1988, to March 29, 1989, the Safety Board recommended on April 20, 1990, that RSPA:

P-90-21

Assess existing gas industry programs for educating the public on the

dangers of gas leaks and on reporting gas leaks to determine the

appropriateness of information provided, the effectiveness of educational

techniques used, and those techniques used in other public education

programs, and based on its findings, amend the public education

provisions of the Federal regulations.

On April 5, 1993, RSPA published Advisory Bulletin ADB-93-02, which directed

“gas pipeline facility owners and operators to review and assess their continuing

education programs as applied to customers and the public.” The Safety Board did not

consider that action responsive because RSPA failed to assess the existing industry

programs or amend the public education regulations. Therefore, the Board classified

Safety Recommendation P-90-21 “Open—Unacceptable Action.”

 

24 For more detailed information, read Pipeline Accident Report—Kansas Power and Light Company

Natural Gas Pipeline Accidents, September 16, 1988 to March 29, 1989 (NTSB/PAR-90/03).
Safety Issues 26

As a result of its investigation of a natural gas explosion and fire in Edison, New

Jersey, on March 23, 1994,25 the Safety Board reiterated Safety Recommendation P-90-21

to RSPA on February 7, 1995. The Board found that the Edison accident illustrated the

need for RSPA to take an active role in ensuring that pipeline operator public education

programs effectively provide the information the public needs to recognize the location of

pipelines, recognize potential hazards, report a pipeline emergency condition, and safely

evacuate an area.

Another recent accident investigated by the Safety Board in which public education was a major safety issue was the propane gas explosion in San Juan, Puerto Rico,26

which resulted in 33 fatalities and 69 injuries. At the June 1997 public hearing, OPS’s

Director of the Enforcement, Compliance, and State Operations Division stated that the

OPS had received $800,000 in funding to develop a national public education program

format to be used by pipeline operators. The OPS planned to work closely with industry

to determine the most effective way to educate the public about gas pipeline safety. The

Safety Board noted that although past actions on this issue had not been timely, it was

pleased that the development of a national public education format was on RSPA’s

agenda and encouraged the OPS to expedite work on this project. Because of RSPA’s

renewed activity, the Board reclassified Safety Recommendation P-90-21 “Open—

Acceptable Response” on December 21, 1997. 

 

25 For more detailed information, read Pipeline Accident Report—Texas Eastern Transmission

Corporation Natural Gas Pipeline Explosion and Fire, Edison, New Jersey, March 23, 1994

(NTSB/PAR-95/01).

26 For more detailed information, read Pipeline Accident Report—San Juan Gas Company, Inc./Enron

Corp., Propane Gas Explosion in San Juan, Puerto Rico, on November 21, 1996 (NTSB/PAR-97/01).
27

Conclusions

Findings

1. The corrosion damage found during the 1996 postaccident inspection indicated that

rapid corrosion had occurred on the pipeline since the 1995 internal inspection.

2. It is unlikely that the pipeline corrosion damage near the rupture location was

underreported by the 1995 internal inspection.

3. Stray currents did not contribute to the corrosion observed on the pipeline.

4. Inadequate corrosion protection at the rupture site and at numerous other locations on

the pipeline allowed active corrosion to occur before the accident.

5. Because cathodic protection levels were inadequate, the stress cracks that existed in

the coating created areas in which rapid corrosion could occur.

6. Disbonded tape coating most likely created locally shielded areas on the pipe that

prevented adequate cathodic protection current from reaching its surface, creating

other areas in which rapid corrosion could occur.

7. Although Koch’s records contained information that cathodic protection levels were

inadequate and that active corrosion was occurring on its pipeline system before the

accident, the conditions went uncorrected.

8. The tape coating on Koch’s entire pipeline may have tape cracking and disbondment.

9. Because no overall requirement exists for operators to evaluate pipeline coating

condition, problems similar to those that occurred on Koch’s pipeline could occur on

other pipelines.

10. This accident illustrates the continuing need for performance measures for adequate

cathodic protection on liquid pipelines.

11. Stress cracks and disbonded tape coating on the pipe created areas where microbial

corrosion could potentially occur.

12. The contribution of microbes to the corrosion damage cannot be accurately determined because of inadequate sampling and testing techniques.

13. The format and content of the public education bulletin mailed by Koch before the

accident did not effectively convey important safety information to the public.
Conclusions 28

14. Koch’s distribution program for its public education materials before the accident was

inadequate.

15. Requirements for the content, format, and periodic evaluation of public education

programs can help pipeline operators ensure that their programs are effective.

Probable Cause

The National Transportation Safety Board determines that the probable cause of

this accident was the failure of Koch Pipeline Company, LP, to adequately protect its

pipeline from corrosion.
29

Recommendations

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

Board makes the following safety recommendations:

to the Research and Special Programs Administration:

Require that Koch Pipeline Company, LP, evaluate the integrity of the

remainder of its HVL (highly volatile liquid) pipeline, including the

condition of the coating, and rehabilitate the pipeline as necessary.

(P-98-34)

Revise 49 Code of Federal Regulations Part 195 to require pipeline

operators to determine the condition of pipeline coating whenever pipe is

exposed and, if degradation is found, to evaluate the coating condition of

the pipeline. (P-98-35)

Revise 49 Code of Federal Regulations Part 195 to include performance

measures for the adequate cathodic protection of liquid pipelines.

(P-98-36)

Revise 49 Code of Federal Regulations Part 195 to include requirements

for the content and distribution of liquid pipeline operators’ public

education programs. (P-98-37)

Revise 49 Code of Federal Regulations Part 195 to require that pipeline

operators periodically evaluate the effectiveness of their public education

programs using scientific techniques. (P-98-38)

to Koch Pipeline Company, LP:

Establish a procedure to promptly evaluate all data related to pipeline

corrosion, such as annual cathodic protection surveys, field reports,

internal inspection results, and coating condition data, to determine

whether the pipeline’s corrosion protection is adequate, and take necessary

corrective action. (P-98-39)

to NACE International:

Develop a standard for microbial sampling and testing of external surfaces

on an underground pipeline. (P-98-40)
Recommendations 30

BY THE NATIONAL TRANSPORTATION SAFETY BOARD

JAMES E. HALL

Chairman

JOHN A. HAMMERSCHMIDT

Member

ROBERT T. FRANCIS II

Vice Chairman

JOHN J. GOGLIA

Member

GEORGE W. BLACK, JR.

Member

November 6, 1998
31

Appendix A

Public Education Information Bulletin

(issued before 1996 accident)

33

Appendix B

Revised Pipeline Safety Brochure

(issued since 1996 accident)
Appendix B 34