-----

PB96-917004

NTSB/SIR-96/04

NATIONAL

TRANSPORTATION

SAFETY

BOARD

WASHINGTON, D.C. 20594

PIPELINE

REPORT

SPECIAL INVESTIGATION

EVALUATION OF PIPELINE FAILURES DURING FLOODING

AND OF SPILL RESPONSE ACTIONS, SAN JACINTO RIVER

NEAR HOUSTON, TEXAS, OCTOBER 1994

/

6734
Abstract: In mid-October 1994, major flooding occurred in the San Jacinto River flood plain

near Houston, Texas. Due to the flooding, eight pipelines ruptured and many others were

undermined. Ignition of petroleum and petroleum products released into the river resulted in 547

people receiving (mostly minor) burn and inhalation injuries. The Safety Board undertook a

special investigation that focused on the following safety issues: (1) the adequacy of Federal and

industry standards on designing pipelines in flood plains, (2) the preparedness of pipeline

operators to respond to threats to their pipelines from flooding and to minimize the potential for

product releases, and (3) the preparedness of the Nation to minimize the consequences of

petroleum releases. The report also addresses the need for effective operational monitoring of

pipelines and for the use of remote- or automatic-operated valves to allow for prompt detection

of product releases and rapid shutdown of failed pipe segments. The Safety Board made nine

safety recommendations: one to the Research and Special Programs Administration, five to the

National Response Team, and one each to the American Petroleum Institute, the Association of

Oil Pipe Lines, and the Interstate Natural Gas Association of America.

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.

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) 487-4600
EVALUATION OF PIPELINE FAILURES DURING

FLOODING AND OF SPILL RESPONSE

ACTIONS, SAN JACINTO RIVER NEAR

HOUSTON, TEXAS, OCTOBER 1994

PIPELINE SPECIAL INVESTIGATION REPORT

Adopted: September 6, 1996

Notation 6734

National

Transportation

Safety Board

Washington, DC 20594

iii

CONTENTS

EXECUTIVE SUMMARY...................................................................................................... v

INTRODUCTION ................................................................................................................... 1

PIPELINE FAILURES AND RESPONSE ACTIONS......................................................... 2

Flooding ......................................................................................................................... 2

Evacuations .................................................................................................................... 4

Initial Pipeline Failures .................................................................................................. 4

Exxon Rupture ................................................................................................... 4

First Colonial Rupture........................................................................................ 5

Fire on the River............................................................................................................. 6

Harris County Emergency Response.............................................................................. 6

Second Colonial Rupture ............................................................................................... 7

Texaco and Valero Ruptures .......................................................................................... 8

Federal Management of the Spill Response................................................................... 8

National Response System Structure ................................................................. 8

Lead Agency and Management Structure........................................................... 9

Operations ........................................................................................................ 10

General ................................................................................................. 10

Planning Section Activities .................................................................. 12

Operations Section Activities............................................................... 13

In-Situ Burn Plan...................................................................... 13

Plan Approval........................................................................... 14

Plan Implementation ................................................................ 14

In-Situ Burn.............................................................................. 17

Injuries.......................................................................................................................... 18

Medical and Pathological ............................................................................................. 18

Damages ....................................................................................................................... 18

Emergency Organization and Participation.................................................................. 19

Disaster Preparedness................................................................................................... 20

In-Situ Controlled Burning Approvals......................................................................... 21

Spill Response Overview ............................................................................................. 21

SUPPLEMENTARY INFORMATION ............................................................................... 24

The River Basin............................................................................................................ 24

Stream Behavior............................................................................................... 24

Stream Stability................................................................................................ 25

Pipeline Operator Survey ............................................................................................. 25

Damages ........................................................................................................... 25

Spill Prevention................................................................................................ 25

Factors Influencing Failures............................................................................. 27

Federal Requirements................................................................................................... 28
iv

Administration.................................................................................................. 28

Natural Gas Pipelines....................................................................................... 28

Design................................................................................................... 32

Liquid Pipelines................................................................................................ 32

Design................................................................................................... 32

Response Plans for Onshore Pipelines............................................................. 32

Plan Requirements................................................................................ 32

Plan Approval....................................................................................... 32

Plan Content ......................................................................................... 33

Industry Design Standards and Guidance..................................................................... 33

Gas Pipelines.................................................................................................... 33

B31.8 Code........................................................................................... 33

Gas Pipe Design Manuals .................................................................... 34

Guide for Gas Transmission and Distribution Piping Systems............ 34

Liquid Pipelines................................................................................................ 35

API Bulletin 1105................................................................................. 35

B31.4 Code........................................................................................... 35

Pipe Failures During Floods......................................................................................... 35

Tests and Research ....................................................................................................... 37

Metallurgy ........................................................................................................ 37

Riverbed Examinations .................................................................................... 38

ANALYSIS.............................................................................................................................. 39

Pipeline Ruptures ......................................................................................................... 39

Design of Pipelines in Flood Plains ............................................................................. 39

Pipeline Operator Responses and Oil Spill Response Plans ........................................ 41

Emergency Response to Pipeline Releases .................................................................. 42

Environmental Spill Response Oversight .................................................................... 43

Communication ................................................................................................ 43

In-Situ Controlled Burn Decision..................................................................... 43

Fatigue.............................................................................................................. 44

Training ............................................................................................................ 44

After-Action Critique ....................................................................................... 45

CONCLUSIONS .................................................................................................................... 47

RECOMMENDATIONS....................................................................................................... 48

APPENDIXES ........................................................................................................................ 51

APPENDIX A - Selected “Lessons Learned” Developed by the FOSC ...................... 51

APPENDIX B - Pipeline Safety Advisory Bulletin ADB-94-05 ................................. 59

APPENDIX C - Safety Recommendations P-87-22, P-91-1, and P-95-1.................... 63

GLOSSARY OF ACRONYMS............................................................................................. 66
v

Between October 14 and October 21, 1994,

some 15 to 20 inches of rain fell on the San

Jacinto River flood plain near Houston, Texas,

resulting in dangerous flooding that far

surpassed past flooding experience in the

region. The floods forced over 14,000 people to

evacuate their homes and resulted in 20 deaths.

Due to the flooding, 8 pipelines ruptured and

29 others were undermined both at river

crossings and new channels created in the flood

plain. More than 35,000 barrels (1.47 million

gallons) of petroleum and petroleum products

were released into the river. Ignition of the

released products within flooded residential

areas resulted in 547 people receiving (mostly

minor) burn and inhalation injuries. The spill

response costs were in excess of $7 million and

estimated property damage losses were about

$16 million.

With respect to this accident, the Safety

Board undertook a special investigation that

focused on the following safety issues: (1) the

adequacy of Federal and industry standards on

designing pipelines in flood plains, (2) the

preparedness of pipeline operators to respond to

threats to their pipelines from flooding and to

minimize the potential for product releases, and

(3) the preparedness of the Nation to minimize

the consequences of petroleum releases. The

report also addresses the need for effective

operational monitoring of pipelines and for the

use of remote- or automatic-operated valves to

allow for prompt detection of product releases

and rapid shutdown of failed pipe segments.

As a result of its investigation, the Safety

Board makes nine safety recommendations: one

to the Research and Special Programs

Administration, five to the National Response

Team, and one each to the American Petroleum

Institute, the Association of Oil Pipe Lines, and

the Interstate Natural Gas Association of

America.

EXECUTIVE SUMMARY

1

Serious flooding in the San Jacinto River

flood plain near Houston, Texas, in October

1994 caused 8 pipelines to rupture and 29 others

to be undermined both at river crossings and

new channels created in the flood plain.

The high number of pipelines ruptured and

damaged during this incident, and the magnitude

of the petroleum releases and spill response

efforts emphasized the threats posed to public

safety and the environment by petroleum

transportation by pipeline. Although pipeline

transportation is one of the safest means for

transporting petroleum, it poses great risk

potential to the environment because of the large

volumes of hazardous liquids that can be

released when a rupture occurs.

In a pipeline transport situation, as opposed

to other transport options, there is greater

likelihood of releasing petroleum into

environmentally sensitive areas. Concerns about

the environmental consequences of releases

from pipelines have been expressed by the

Congress, the States, and local interests.

Because so many pipelines were damaged

during this flood and such large volumes of

petroleum and petroleum products were

released — requiring a massive environmental

response in terms of personnel and equipment

— the Safety Board undertook this special

investigation to assess the adequacy of Federal

and industry standards on designing pipelines in

flood plains, the preparedness of pipeline

operators to respond to threats to their pipelines

from flooding and to minimize the potential for

product releases, and the preparedness of the

Nation to minimize the consequences of

petroleum releases.

In the course of the investigation, the Safety

Board also discovered evidence reinforcing the

need for effective operational monitoring of

pipelines and for the use of remote- or

automatic-operated valves to allow for prompt

detection of product releases and rapid

shutdown of failed pipe segments.

INTRODUCTION
2

Flooding

Between October 14 and October 21, 1994,

the remnants of Hurricane Rosa caused heavy

rainfall in a 38-county area of southeast Texas.

On October 18, the President issued a disaster

declaration covering 26 counties (later extended

to include 38 counties). The San Jacinto River

basin in eastern Harris County received 15 to 20

inches of rain during this week-long period. (See

figure 1.)

The United States Geological Survey

(USGS)1

 made numerous measurements of

stream stage2

 and stream flow during flood

conditions at 43 stations in 29 Texas counties. A

USGS official observed that:

By any measure, the flooding of October

1994 was an extreme and dangerous

event. Historical peak stream flows were

exceeded at 23 of the 43 stations

monitored in the area. The 100-yearflood, which is defined as the peak stream

flow having a 1 percent chance of being

equaled or exceeded in any given year,

was equaled at 1 and exceeded at 18 of 43

stations. For those stations where the 100-

year-flood was exceeded, the flood was

from 1.1 to 2.9 times the 100-year-flood.

 

 1The U.S. Geological Survey, U.S. Department of the

Interior, develops and disseminates relevant, policy-neutral

water data and information to support water-resource

planning and management needs nationwide. Part of the

USGS mission is to operate the country's stream flowgauging network, in cooperation with other Federal, State,

and local agencies.

2

Water-surface elevation of a stream with respect to a

reference elevation.

The flooding caused major soil erosion in the

flood plain and river channel, including the

creation of water channels outside the San

Jacinto River bed. The flood waters scoured3

 the

riverbed and banks, destabilized roads and

bridges, and inundated area homes. The largest

new channel (approximately 510 feet wide and

15 feet deep) was created when the river cut

through the Banana Bend oxbow4

 just west of

the Rio Villa Park subdivision. A second major

channel cut through Banana Bend just north of

the channel through the oxbow. Both these

channels cut through areas where sand mining

had been performed previously.

Beginning on October 16, 1994, weather

forecasters began issuing flash flood warnings

for the Houston area, and, on October 17, river

flood warnings were issued for the San Jacinto

and other area rivers. Heavy rainfall was

expected to continue for several days.

The San Jacinto River, which normally flows

at about 2.5 feet above sea level, crested at 28

feet above mean sea level on October 21. The

peak discharge was more than 350,000 cubic

feet per second, about 58 percent greater than

the 100-year-flood. The highest velocity

measured was 16.6 feet per second—

approximately 11 miles per hour.

 

3

To wash or clear a riverbed by a swift current of water.

4

A U-shaped bend in a river.

PIPELINE FAILURES AND RESPONSE ACTIONS
3

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1 2 3 Miles

1

I Rio Villa

Subdivision

Figure 1 – San Jacinto flood plain

5

Remote-operated valves on both sides of the

river crossing were closed to isolate the leak to

within an 11-mile segment of the pipeline. By

7:30 p.m., Exxon personnel had closed a manual

valve on the river’s east bank and isolated the

leak to an 8-mile pipeline segment. By 7:45

p.m., Exxon personnel observed that the rate of

product bubbling within the water had

decreased, indicating to them that Exxon’s

pipeline was the source of the LPG release.

 Exxon crews worked through the night

installing equipment to enable the company to

release and burn the LPG in the isolated pipeline

segment. They could not close the west bank

manual valve because it was under water;

however, in the evening of October 19, they

closed a manual valve farther west of the

crossing to isolate the leak to a 4-mile segment.

Exxon crews visually inspected areas adjacent

to its other pipeline crossings south of the

Interstate 10 bridge and decided that they too

could be threatened by the flood waters. At 8:15

p.m. on October 19, Exxon shut down pumps on

its three additional operating pipelines—20-

inch, crude oil; 10-inch, refined petroleum

products; and 8-inch, turbine fuel. Products in

the pipeline segments crossing the river were

then removed and the lines were purged using

nitrogen. Once the lines had been purged, the

manual valves nearest the river were closed,

isolating those segments.

On October 20, Exxon notified the

appropriate Federal, State, and local government

agencies of the LPG pipeline failure, provided

information on the actions it was taking to shut

down and isolate all its pipeline crossings, and

established a repair command center on the east

bank of the river. Also on October 20, Exxon

USA provided a spill response command center

at its Baytown refinery for the use of the unified

response team. (See upcoming section on

Federal Management of the Spill Response.)

First Colonial Rupture -- Colonial Pipeline

Company (Colonial) operates two pipelines—

40-inch and 36-inch—that cross the flood plain

and the river at the oxbow just south of Banana

Bend. Colonial shares a right-of-way in this area

with pipelines operated by Texaco Pipeline,

Inc., (Texaco) and Valero Transmission L. P.

(Valero). The pipeline right-of-way crosses the

river about 4 miles north of the Interstate 10

bridge. The Rio Villa Park subdivision is

located within the oxbow. Shallow sand pits,

where a sand mining operation had been

conducted several years earlier, lie to the west

of the subdivision.

About 8:31 a.m. on October 20, the operator

of Colonial’s Houston, Texas, pump station,

(located about 12 miles west of the San Jacinto

River) telephoned the controller at Colonial’s

Atlanta, Georgia, control center. He advised the

controller that the rate of flow in the 40-inch

pipeline, which was transporting gasoline, had

increased significantly. At 8:32 a.m., while the

controller and the Houston operator were

discussing the increased flow rate, an alarm

came from the Shiloh pump station, located

about 29 miles east of the San Jacinto River.

The alarm told the controller that suction

pressure in the line had fallen from normal

pressures of about 40-50 psig6

 to 23 psig.

The controller told the Houston operator to

shut the 40-inch pipeline down. About 8:33

a.m., the operator did so. The operator also

closed the Houston mainline pump station valve

and valves to shipper locations. (Later, the

mainline valve at the Shiloh pump station was

closed.)

At this time, a shift supervisor who had been

observing the activities of the controller for the

40-inch line initiated Colonial’s emergency

response procedures. The shift supervisor

advised the controller for Colonial’s 36-inch

pipeline of the problems being experienced on

the 40-inch line and cautioned the controller of

the 36-inch pipeline to watch indications on that

line closely. (The 36-inch pipeline segment

between the Houston and Beaumont stations had

been shut down at 11:06 p.m. on October 19, in

 

6

Pounds per square inch, gauge.
6

the course of normal pipeline operations, but the

pipeline segment still contained low-sulfur

diesel fuel under pressure.) The Houston

operator dispatched Colonial personnel from

Houston to the suspected rupture area to search

for the site of any product release.

 Gasoline flowed from the ruptured 40-inch

Colonial pipeline into the swift-flowing flood

waters and pooled in areas of slower water flow.

Residents evacuating the Rio Villa Park

subdivision reported that they detected the odor

of gasoline about 9:00 a.m. on October 20 and

observed oil and vapors south of Wallisville

Road. A River Road resident on the south side

of White’s Lake near Interstate 10 observed that

gasoline fumes had collected near boathouses.

At 9:37 a.m. (about 1 hour after the rupture), a

Colonial employee performing an aerial patrol

observed gasoline in a new channel that had

been cut through the sand pit area of the oxbow.

About 9:40 a.m., a Colonial employee

notified Harris County Sheriff’s Department

officers located at the Interstate 10 San Jacinto

bridge that Colonial’s pipeline had ruptured in

the San Jacinto River. (The Interstate 10 San

Jacinto bridge had been closed in both

directions at 11:30 a.m. on October 18, when

flood waters rose to the elevation of the

approaches to the bridge.)

The Harris County Communications Center

first learned of the gasoline release at 9:41 a.m.,

when a resident called 911 reporting an odor of

gasoline from White's Lake in the River Road

area. That call was transferred to the

Channelview Fire Department, which advised

the Communications Center that personnel at a

chemical plant on the west bank of the river

were checking for a possible leak at or near the

plant. At 9:51 a.m., the Harris County Office of

Emergency Management ordered the evacuation

of Wallisville Road west of the river due to the

strong fumes in the area.

Fire on the River

About 9:51 a.m., explosions and fires

erupted on the river and began moving slowly

southward towards the Interstate 10 bridge.

Witnesses reported hearing a series of five

distinct explosions and observing balls of fire

and smoke rising just north of Interstate 10.

After the first explosion, fire and smoke rose

about 300–400 feet into the air. A second

explosion, located about 200–300 feet to the

west of the first, occurred about 10 seconds

later, and a third explosion occurred about 600–

700 feet to the west of the second. Minutes later,

two more explosions were heard as the fire

advanced across the lake and the stream flow

carried the petroleum toward the Interstate 10

bridge.

A Colonial supervisor conducting an aerial

survey from a helicopter observed the ignition

of the fire. He stated that he could see product

spewing up from the ruptured pipeline and being

carried downriver as far as the Interstate 10

bridge. He saw the fire flash above the product

floating on the water. The fire appeared to him

to have begun along the river’s eastern bank.

Harris County Emergency Response

The Harris County Sheriff’s Department

District Commander stated that he observed a

large black cloud and fireball to the northeast

while he was crossing the (closed) Interstate 10

bridge about 10:15 a.m. He could not identify

what was burning. He advised his dispatcher

that a major event was underway, and he

requested assistance.

In accordance with the Harris County

Disaster Plan, the predesignated Sheriff’s

Department Incident Commander was

dispatched immediately to the scene, as were

additional patrol units. Upon his arrival at 10:30

a.m., the Incident Commander requested county
7

mobile command vans7 to be dispatched, and he

established a temporary command post about 1⁄4

mile west of the bridge on the south side of

Interstate 10. Several minutes later, a

representative of Colonial identified himself to

the Incident Commander and advised him that

Colonial’s 40-inch pipeline had ruptured and

was releasing gasoline. The Incident

Commander requested that the Colonial

representative stay at the command post to

provide information.

About 10:50 a.m., Colonial advised the

Harris County Command Center that it had

closed valves at each side of the river on its 40-

inch pipeline to isolate the rupture. It advised

that the isolated pipeline segment contained

65,338 bbls8

 (2.74 million gallons) of gasoline.

Colonial employees had closed the manual

valves nearest each side of the river; the west

valve was closed at 9:59 a.m., and the east valve

was closed at 10:13 a.m.

Second Colonial Rupture

About 11:30 a.m., Colonial’s shift supervisor

told the controller of its 36-inch pipeline to

close the remote-operated mainline valves

between the Houston and Shiloh pump stations

and all remote-operated valves on lines to

shippers. (The controller later stated that he did

not close the valves on either side of the San

Jacinto River, as such action would have

isolated the pipe segment crossing the river from

the rest of the system and prevented him from

monitoring the pressure in the pipe beneath the

river, since pressure monitors were located only

at the pump stations.)

About 1:00 p.m. on October 20, the Incident

Commander extended the evacuation to all

persons within 9 miles of the failed 40-inch

Colonial pipeline.

 

7

Harris County provided 2 mobile command vans, 69

patrol units, and 2 boats.

8

Barrels. Barrel capacity is 42 U.S. gallons.

Colonial's 36-inch petroleum pipeline

ruptured about 2:00 p.m. The Colonial shift

supervisor directed that personnel travel to and

close the manual valves at the river crossing and

that the failure be reported to local officials.

About 2:30 p.m., the line failure was reported to

the Incident Commander by Colonial.

About 2:45 p.m., the Incident Commander

requested the Channelview Fire Department to

call DIGTESS, a local pipeline one-call

notification system,9

 to obtain a listing of

companies that operated pipelines adjacent to

the river that might be affected by the flooding.

He learned from the Colonial representative that

the mainline valves on Colonial’s failed 36-inch

pipeline had been closed at Pasadena and

Trinity, Texas, isolating the failure to a 30-milelong segment of the pipeline (containing about

196,000 bbls or 8.2 million gallons of

petroleum). By 3:00 p.m., representatives of

many local and State agencies arrived at the

Interstate 10 command post.

At 6:30 p.m., the Texas Railroad

Commission, the agency responsible for safety

oversight of intrastate pipeline operations,

reported to the Incident Commander that 25

operators of pipelines north of the Interstate 10

bridge had shut down operations and secured

their pipelines under pressure. At 8:00 p.m., in

the belief that the situation was safe, the Harris

County Office of Emergency Management

advised flood evacuees that they could return to

their homes. However, a health advisory was

issued for all persons to stay indoors until

further notice due to the air quality. During the

night, the Texas Department of Public Safety

monitored U.S. Route 90 for driver visibility

and placed lighted caution signs on both of the

U.S. Route 90 bridges. Throughout the night,

the Harris County Sheriff's Department

 

9

There are three one-call systems in the State of Texas:

DIGTESS, LONESTAR, and TEXAS. Pipeline operators

must register with at least one of these systems so that the

utility companies can be notified of planned excavations

and mark the location of buried pipelines prior to

excavation.
8

monitored a barge burning on the river, the size

of the spill, and the highway traffic. In addition,

it maintained security for residences in the

flooded and evacuated areas.

Texaco and Valero Ruptures

About 10:30 a.m. on October 20, the

operators of the Texaco and Valero pipelines

had learned through news media reports that a

Colonial pipeline had apparently ruptured at the

river. At 3:45 p.m., Valero’s 12-inch natural gas

pipeline ruptured.

Texaco had shut its 20-inch pipeline down

the previous August, leaving crude oil in the

pipe under no pressure. Consequently, Texaco

was unable to monitor this pipeline to detect a

leak or rupture. Texaco considered

repressurizing the pipeline, but eventually

rejected this idea because if a leak existed,

repressurizing the line would cause the release

of more oil. Texaco also considered the options

of using nitrogen or water to displace the crude

oil from the pipe segment, and cutting into its

pipe (tapping) to draw oil from the pipe segment

in the flooded area. Of all available options,

Texaco determined that the latter action

provided the least uncertainty.

Texaco employees were dispatched to close

manual valves east of the river. After the valves

were closed, Texaco operated pumps at its East

Houston Station to draw as much product as

possible from the pipeline crossing the river.

Texaco could remove only 260 bbls of crude oil

at that time. About 6:30 p.m. on October 20, a

Texaco representative conducted an aerial patrol

of the pipeline and observed crude oil leaking.

During a second aerial survey on October 21, a

Texaco representative observed what he

believed was crude oil on the water near

Texaco’s pipeline right-of-way. Texaco

assumed that the leaking crude oil came from its

own pipeline. Texaco activated a district

emergency response team to begin its spill

recovery response.

About 2:00 p.m., Texaco dispatched

employees to both sides of the San Jacinto River

to cut into the pipe and remove as much product

as possible. About 3:00 p.m., Texaco notified

local, State, and Federal agencies that its

pipeline had likely ruptured at an undetermined

time and that it was taking response actions,

which it detailed.

By 1:20 a.m. on October 22, the pipe on both

sides of the river was tapped. Using vacuum

trucks, Texaco personnel applied suction to the

line at both ends of the crossing, resulting in the

recovery of 40 bbls and 370 bbls of crude oil

from the west and east ends of the line,

respectively.

Federal Management of the Spill

Response

National Response System Structure -- The

National Response System (NRS) is a national

mechanism for coordinating response actions by

all levels of government in support of an OnScene Coordinator (OSC) when discharges of

oil and releases of hazardous substances,

pollutants, and contaminants occur. The

National Response Team (NRT) of the NRS is

responsible for providing national planning and

coordination for responding to such

emergencies.

The NRT consists of representatives from

the Environmental Protection Agency (EPA)—

which serves as its chairman, the Coast Guard—

which serves as its vice chairman, the Federal

Emergency Management Administration

(FEMA), the Nuclear Regulatory Commission,

the General Services Administration, the U.S.

Public Health Service, and the U.S. Departments

of Defense (through the U.S. Corps of Engineers

and U.S. Navy Supervisor of Salvage), Energy,

Commerce (through the National Oceanic and

Atmospheric Administration), Interior, Justice,

Labor, and Transportation.
9

Among its other responsibilities, the NRT

must evaluate methods of responding to

discharges or releases; recommend to the EPA

Administrator changes needed in response

organizations and the National Contingency

Plan (which appears in Section 105 of the

Comprehensive Environmental Response

Compensation and Liability Act of 1980, 42

United States Code 9605, as amended); provide

policy and program direction to Regional

Response Teams; make recommendations to

appropriate agencies as to training, equipping,

and protecting response teams; and direct

organization planning and preparedness.

As the functional arms of the NRS structure,

the Regional Response Teams (RRTs) are

responsible for the planning and coordination of

preparedness and response actions. RRT

membership parallels the NRT’s, but also

includes State and local representation. Each

RRT provides appropriate regional mechanisms

for developing and coordinating preparedness

activities before a response is undertaken,

coordinating assistance and advice to the OSC

during responses, and providing advice to area

committees to ensure consistency of area

contingency plans with the National

Contingency Plan. An RRT may be activated, at

the request of the OSC, during any discharge

situation. Texas is within the jurisdiction of

Federal RRT Region VI.

Lead Agency and Management Structure – In

the case of the San Jacinto product release

situation, the liquid products being released

north of the Interstate 10 bridge were in an area

for which the EPA has spill response

management responsibility. However, the

products flowed south and contaminated the

coastal zone south of the Interstate 10 bridge, an

area for which the Coast Guard has spill

response management responsibility.

About 10:00 p.m. on October 20,

representatives of the Coast Guard, the EPA,

and other concerned agencies met to discuss the

management of the oil spill recovery actions.

While both the Coast Guard and the EPA had

personnel qualified to serve as a Federal OnScene Coordinator (FOSC), the agencies

decided that the Coast Guard would be the lead

agency in a unified Federal response10 to manage

the spill cleanup. This decision was made

primarily because the Coast Guard had a

significantly larger presence in the area and had

already established effective communications

with local and State authorities during its

response to the flood emergency.

The Coast Guard FOSC stated that he

established a unified command/incident

command system to ensure that his

decisionmaking included the knowledge,

experience, and concerns of the Texas General

Land Office (TGLO), as the representative for

State and local agencies, and of the two pipeline

companies whose products were the focus of the

cleanup. (See figure 3.)

The unified command’s Planning Section,

managed by a Coast Guard officer, was

responsible for researching issues and

developing plans on activities that might later be

implemented. The Operations Section, managed

by a Coast Guard Reserve officer, was

responsible for handling current activities, such

as the placement of booms and product recovery

equipment.

The Operations Section had five divisions

within its Cleanup Branch, each managed by

Coast Guard personnel. Division I included

Banana Bend and the adjacent oxbow meander.

 

10See Incident Command Technical Assistance

Document: Managing Responses to Oil Discharges and

Hazardous Substance Releases Under the National

Contingency Plan.
10

(See figure 4 for areas under Divisions I

through III authority.)

The FOSC held meetings each morning and

evening, at which time he and others were

briefed on the activities taken, planned, or under

consideration.

Operations – General. One of the first

actions of the FOSC on October 20 was to ask

the Texas Railroad Commission to identify and

secure all pipelines along the San Jacinto River

as far north as Lake Houston. The FOSC also

requested all operators of water systems south

of the Lake Houston Dam to close and secure

their water intakes. He directed the Vessel

Traffic Control System to close the Houston

Ship Channel to all but emergency vessels. In

addition, the Texas Railroad Commission

suspended all railroad traffic crossing the San

Jacinto River. Throughout the morning of

October 21, petroleum products from several

pipelines, as well as a barge, were on fire on the

river. (See figure 5.)

About 9:00 a.m. on October 22, the Coast

Guard’s unified command center advised the

Harris County Sheriff’s Department that high

levels of jet fuel vapors were being detected in

the River Bend area near Wallisville Road, and

directed evacuation of the area. The

Channelview Fire Department began to evacuate

the affected area, but about 1:00 p.m., the Coast

Guard advised the Sheriff that the earlier

readings had been in error, so the evacuation

order was lifted.

Several isolated small fires were burning on

October 23 where Colonial’s and Texaco’s

pipes on the east bank of the new channel were

releasing crude oil and diesel fuel, and where

Colonial’s and Texaco’s ruptured pipes at the

west channel bank were releasing diesel fuel,

crude oil, and some gasoline.

Figure 3 – Unified command management structure

Texas General Land Office Colonial PL

Safety Liaison

Information

Emergency Ops Branch

OPS/NOAA/TGLO/

NRC/Pipelines

Division I Division II Division III Division IV Division V

Cleanup Branch

Operations Planning Logistics Finance

Coast Guard FOSC Texaco PL
11

San Jacinto River Spill

Waste Tracking Map (1) Date/Time: 24 OCT 94,2100

Platform prepared by NOAA Observers:

USE ONLY ASA GENERALREFERENCE Graphic does not show precise locations or amounts ofwaste

I Al /. ,., ::.:<:

w“ 50’ I

“R’?> ‘

29’48’ I

o

L

95’ 06’ 95”04’ 95" 02'

Figure 4 – Areas of responsibility for Coast Guard operations divisions

13

of pollution, although some fuel

escaping the fire was contaminating

the beaches; and

• Means were being considered to

minimize further environmental

damage by enhancing ongoing

burning or initiating in-situ burning of

oil currently escaping or that might

escape from future ruptures.

The draft listed items to consider based on

the approved in-situ controlled checklist

developed by RRT VI and RRT Alaska, and

included a discussion on the pros and cons of

conducting an in-situ controlled burn.12

That draft document concluded that

enhancing ongoing in-situ burning or initiating

in-situ burning of the products released would

be more desirable than using mechanical

recovery or dispersant techniques. The draft

stated that the purpose of in-situ controlled

burning is to:

Reduce the overall duration and effort

invested in the cleanup operation.

It stated that an in-situ controlled burn might

pose risks to personnel and cautioned that:

In-situ controlled burning operations

should not commence until an operation

safety plan is prepared. It should address

personal safety, firefighting, ignition

hazard, evacuation, and other aspects

needed in order to protect personnel

conducting the burn. The possible impact

of the smoke plume should be assessed. If

needed, the public should be notified and

the possibility of evacuation should be

considered.

 

12The RRT VI In-situ Burn Plan stated that near-shore,

inshore, or onshore burns are not addressed within the

response plan. The RRT VI In-situ Burn Plan also

emphasized the requirement to monitor air pollution as a

means by which to gauge and control the boom

effectiveness, and the importance of being able to

extinguish the fire at any time by releasing the boom.

The paper listed pros and cons of in-situ

burning of oil as:

Pro

• In-situ burning should minimize the

environmental damage of the spilled

oil by burning the oil at the source of

the spill;

• In-situ burning should reduce the

amount of toxic, volatile compounds

emitted from the oil by burning them

at the source;

• In-situ burning should reduce the

overall duration and effort invested in

the cleanup operation and minimize

the risk of personnel injury associated

with this effort.

Con

• In-situ burning may temporarily

increase the level of air pollution,

especially the concentration of PM-10

(small soot particulates that can be

inhaled);

• In-situ burning may pose risks to

personnel conducting the burning;

• In-situ burning requires specialized

equipment not readily available.

Operations Section Activities. In-Situ

Burn Plan. A short time after the FOSC

completed his October 23 morning status

meeting, the TGLO representative developed

and presented to the Operations Section chief a

handwritten proposal not discussed in the

meeting. The proposal, dated October 23, 1994,

was entitled Burn Enhancement Proposal and

called for deployment of 500 feet of fire boom13

just south of (Texaco’s) 20-inch ruptured

 

13A fire boom is a floating containment device

constructed of fire-resistant materials and used to capture

and contain petroleum (or other flammable materials to be

burned) on the water surface.
14

pipeline at the east channel bank “...as close/far

as safety considerations allow.” (See figure 6.)

The fire boom was to be anchored to the east

channel bank and have an opening of about 100

to 150 feet. The proposal stated that the

objective was to:

...contain and remove, by the burning

process, additional unburned crude/oil at

the pipe (20”) rupture site. Operation to

be conducted as outlined and sketched

below with Coast Guard on-site oversight.

The schedule called for the action to be taken

between 10:00 a.m. and noon of that day

(October 23). The TGLO was to supply the fire

boom, Oil Mop, Inc., was to be the contractor to

carry out the work, and the Coast Guard was to

have oversight responsibility. No provisions

were included to provide air monitoring, notice

to local response agencies, alternate action

(should the planned timeframe not be met), or a

site safety plan covering the safety of fire boom

crews.

Plan Approval. The FOSC and the TGLO

representative reviewed and, by affixing their

signatures to the draft, approved implementation

of the in-situ burn plan. Next, the Operations

Section chief and a second TGLO representative

performed an aerial evaluation of the new

channel to determine if the proposed position of

the fire boom was practical. Based on their

aerial observations, they agreed that the

approved plan was feasible. Among other

information, Colonial’s noon status report to the

unified command center stated:

Colonial crews working on west side of

the river will be using a National

Response Center barge (currently being

assembled at Lyondell [Petrochemical

Company]) for the purpose of ferrying

equipment across the new channel to the

island. The barge will be available for

service at 2:00 p.m.

Our surveillance info indicates that a

single fire remains on the east side of the

new channel. It also indicates that all four

lines crossing the channel are completely

severed.

Our local personnel have the

understanding that the Coast Guard will

be deploying a boom for the purpose of

containing and recovering crude oil and

fuel oil leaching from the Texaco and

Colonial line on the west side.

Plan Implementation. The Coast Guard’s

Operations Division I supervisor was told that

the EPA OSC would visit the equipment staging

area to pick up 500 feet of fire boom. He was

not told of any plan or proposal for using the

fire boom. While he was aware that the EPA

OSC was on the scene to handle the recovery of

hazardous materials containers, he was not

aware that the EPA OSC was conducting

petroleum product recovery activities in

Division I.

Instead of the EPA OSC picking up the fire

boom, the TGLO arranged for the boom to be

picked up and transported to an area near the

channel. When the fire boom was delivered, the

EPA OSC, his EPA contract assistance team,

and the two Coast Guard personnel with them

completed the placement of conventional booms

in the new channel, several hundred feet

downstream of the ruptured pipelines, to divert

petroleum products for future collection. About

2:00 p.m., after deploying the conventional

booms, the EPA OSC and his workcrew

returned to their equipment staging area, where

the EPA OSC was told that a fire boom had

been delivered and that he was to call the

unified command center for instructions.
15

Figure 6 – Burn enhancement proposal approved by the FOSC and the TGLO
16

The EPA OSC telephoned the unified

command center as directed. His call was

answered by the Planning Section chief, who

was in the Command Room. The EPA OSC

asked if a plan had been approved for deploying

the fire boom. Without consulting anyone in the

Operations Section, the Planning Section chief

went to the Operations Section, found a copy of

the plan approved by the FOSC and the TGLO,

and read the plan notations to the EPA OSC. He

instructed the EPA OSC to call the unified

command center again when the boom had been

deployed.

The EPA OSC and his EPA contract team

supervisor discussed the plan for the in-situ

burn. Both stated that they were concerned

about carrying out an in-situ burn in the channel

because of the quantity and volatility of

petroleum products in the area, and because they

had not had the usual opportunity to discuss

plan details and safety precautions with those

who had developed and approved the plan.

They, with the two Coast Guard strike team

personnel accompanying them, discussed how

and where to best deploy the fire boom. The

southern end of the new channel had two outlets

into the main river, forming an island between

them. They decided to place a conventional

boom near Wallisville Road across the west

channel outlet, as this channel was not flowing

as rapidly as the east outlet. The fire boom was

then to be placed across the east outlet, about

500 yards south of the pipeline breaks, where

they believed it would be safe to operate their

boat engine.

Meanwhile, after noon on October 23, the

Operations Section chief and the second TGLO

representative made a second aerial observation

of the channel. During that trip, the Operations

Section chief observed that the water level in the

channel had dropped drastically and that the

west outlet no longer appeared to be flowing.

Based on this observation, the Operations

Section chief advised the TGLO representative

that the petroleum products could be removed

by mechanical means and that the Burn

Enhancement Plan should be canceled. When

the Operations Section chief returned to the

command center, however, he did not inform

either the FOSC or the Division I supervisor of

the decision to cancel the in-situ burn, nor did

he determine what, if any, action had been

initiated to implement the plan.

About 3:00 p.m., the EPA OSC and the EPA

contract crew began deploying additional booms

in the channel outlets. Highly volatile products

were in the area where they were installing the

fire boom. Some areas reportedly contained up

to 10 inches of petroleum products on top of the

water. The EPA OSC estimated that, when fully

deployed, the fire boom was holding back more

than 2,800 bbls of a low flashpoint mixture of

oil, gasoline, and diesel fuel.

After placing the fire booms, the EPA OSC

sent most of the contract workers back to the

staging area. Two EPA contract employees and

one Coast Guard strike team member were left

on the east bank of the channel outlet to anchor

the end of the fire boom. The EPA OSC told

them to await his radio instructions. The EPA

OSC, the EPA contract supervisor, and the other

Coast Guard strike team member then flew by

helicopter to the west bank of the new channel

to warn Colonial and Texaco workcrews about

the pending in-situ controlled burn. The threeperson joint Coast Guard and contractor crew

that remained on the east channel outlet bank

checked nearby areas for people in potentially

dangerous sites. They found several persons in

the Rio Villa Park subdivision and told them to

leave the area.

From the west bank of the new channel,

Colonial’s on-site safety coordinator watched

the helicopter land and the EPA OSC get out.

The EPA OSC told him that the Coast Guard

had approved in-situ controlled burning of the

accumulated product at the pipeline openings.

The EPA OSC advised that this type of burning

was a routine procedure for the disposition of

accumulated product. The Colonial safety

coordinator told the EPA OSC that ignition of

the product should be delayed until the Texaco

crews finished closing the end of their pipeline,
17

the Colonial work crews in the area could be

alerted, and the operator of a small boat (later

identified as a Coast Guard patrol boat) on the

river could be alerted and evacuated.

In-Situ Burn. One of the EPA contract

employees left on the east side of the fire boom

stated that while the EPA OSC and the Colonial

safety coordinator were on the west bank of the

new channel discussing the proposed in-situ

controlled burn, he and the others heard the

question “What are you waiting for?,” over the

EPA contractor’s mobile radio. The EPA

contract employee stated that the east bank team

believed that the question signaled them to

ignite the accumulated petroleum products. He

stated that he tried three times unsuccessfully to

make radio contact to confirm that the product

should be ignited. Then, the three employees on

the east bank agreed that they had been signaled

to ignite the accumulated products. Flares were

lit, placed on a trashcan lid, and floated into the

area of accumulated petroleum products

adjacent to the fire boom.

The EPA contract supervisor who went to

the west side of the channel later stated that he

heard no radio transmissions from any of the

three personnel left on the east bank. The

Colonial representative stated that as he and the

EPA OSC were talking, the EPA OSC made no

radio communications until the flames were

seen coming from the east bank towards them.

At 6:03 p.m., the products ignited and

rapidly flashed across the channel and shoreline

south of the channel. One of the three persons

on the east side of the boom announced over the

radio that the products had been lit.

The EPA OSC recounted that, about 6:00

p.m., after warning the Colonial representative

of the planned in-situ burn, he heard a

transmission on his EPA contractor radio

reporting that the fire had been lit. He looked to

the southeast and saw the flames traveling

towards him. The EPA OSC and others who had

gotten out of the helicopter on the west bank ran

from the oncoming flames while the pilot flew

the helicopter to safety and announced over its

public address speaker that all persons in the

area should evacuate. All of the people at the

work site ran from the oncoming flames. The

resulting fire sent flames about 100 feet into the

air. The smoke plume rose about 1,500 feet

vertically and, when it came into contact with an

inversion layer, the smoke traveled horizontally.

According to the Colonial representative, the

fire never approached any of the site workers,

and the Texaco employees returned to complete

their work about 15 minutes later. Afterwards,

all pipeline employees left the area. No injuries

resulted from this in-situ burn.

Minutes after 6:00 p.m., the Coast Guard

operations center received a report of the

eruption of a large fire on the river from

unknown causes. More than an hour afterwards,

the unified command center learned that the fire

had been the result of a deliberately initiated insitu burn. The FOSC stated that he had not been

aware of any approval given to ignite the

accumulated product, and that he had

understood that he was to have been consulted

before the product was ignited. He stated that it

had been his intent, once he had been advised

that everything was ready and atmospheric

conditions were favorable, to alert both local

government and private interests of the intended

burn. He expressed no knowledge of his

Operations Section chief deciding against

implementing the Burn Enhancement Plan.

By 9:00 p.m. on October 23, the height of the

flames from the in-situ fire had reduced to 60

feet. By 6:00 a.m. the next day, the fire was

moving south, away from the new channel. The

Coast Guard monitored the progress of the fire,

and the EPA assessed the airborne pollution

threat until the fire self-extinguished about

10:00 p.m. on October 24.
18

Injuries

Residents Employees Others Total

Fatal 0 0 0 0

Serious 1 1 0 2

Minor 544 1 0 545

Total 545 2 0 547

Medical and Pathological

On its Office of Pipeline Safety (OPS)14

incident report for the gasoline release, Colonial

recorded that 925 persons had been injured. On

its report for the diesel fuel release, Colonial

reported that 926 persons had been injured.

However, the Safety Board’s investigation

indicated that a total of 547 persons were treated

at 4 local hospitals, primarily for smoke and

vapor inhalation complaints.

Two of the injured were residents of River

Road, who sustained burn injuries while

returning to their residences. A 64-year-old

woman sustained serious second- and thirddegree burns over 18 percent of her body; face,

arms, ankles, and legs. A 65-year-old man

sustained minor first-degree burns to his arms.

Two pipeline workers were injured on October

27, during the removal of the damaged Valero

pipe. One sustained a contusion to his right leg

and the other sustained a serious injury, a

fractured left jaw.

Damages

In addition to the damage to buildings and

equipment caused by flooding, the Harris

County Fire Marshal estimated that the

petroleum fire heavily damaged at least four

houses, six mobile homes, one commercial

building, nine automobiles, eight boats, and four

 

14The OPS is a part of the Research and Special

Programs Administration of the U.S. Department of

Transportation. The OPS is responsible for administering

the Federal pipeline safety program.

houseboats. Colonial reported that it had

received about 3,000 reimbursement claims for

fire damages, soot deposits, and temporary

housing. Spill response costs were in excess of

$7 million. In addition, pipeline operators

reported product losses of more than 35,000

bbls and property damage losses of about $16

million.

Although a total of 37 pipelines were

ruptured or undermined during the flood, the

incident reports filed with the OPS covered only

5 of the 8 ruptured pipelines; those operated by

Colonial (2), Exxon, Texaco, and Valero.15 Of

the other three pipelines that ruptured, one had

been taken out of service and purged of crude

oil by Citgo Pipeline Company in August 1994.

The other two pipelines had been taken out of

service and purged of crude oil and turbine fuel

by Exxon during the evening of October 19.

Colonial reported property damage losses of

$10 million and product losses of 20,000 bbls of

gasoline resulting from its 40-inch pipeline

failure. Colonial reported property damage

losses of $0 and product losses of 10,000 bbls of

gasoline from its 36-inch pipeline failure. Exxon

reported property damage losses of $610,000

and product losses of 492 bbls of LPG. Valero

reported property damage losses of $800,000

and product losses of 7,000 million cubic feet of

natural gas. Texaco estimated that it suffered

about $4.5 million in property damages and lost

5,350 bbls of crude oil.

 

15While the failure of at least three pipeline operators to

file reports with the OPS raises some questions as to the

seriousness with which pipeline operators view this filing

responsibility, it should be noted that a number of factors,

including the operators’ differing means of gauging the

value of their losses, may have persuaded some operators

that they were not legally obligated to file in this instance.
19

Emergency Organization and

Participation

The Oil Pollution Act of 1990 (OPA 90;

Public Law 101-380) and the National Oil and

Hazardous Substances Pollution Contingency

Plan require establishment of RRTs to plan and

coordinate regional preparedness and response

actions, including procedures and techniques to

be employed in identifying, containing,

dispersing, and removing oil. In this incident,

RRT VI’s involvement was limited to approval

of the in-situ burn plan.

The primary mechanism or plan governing

the environmental response activities in the

region of this accident is the Galveston Bay Area

Contingency Plan. The plan was approved in

1994 by the Captains of the Ports for the

Galveston and Houston Coast Guard commands.

The contingency plan is designed to handle

emergency responses to releases of petroleum

products and to establish the Coast Guard’s

Captain of the Port as the FOSC for managing the

activities of Federal, State, and local emergency

response agencies.

The local fire and medical responses were

coordinated by the Channelview and Highland

Fire Departments. Approximately 12 mobile

intensive care units and advanced life support

ambulances were used to transport injured

patients to local hospitals. The fire departments

responded to structural fire alarms but made no

attempt to extinguish on-river petroleum fires.

 Local area response organizations and

officers included the Houston Fire Department

Hazardous Materials Team and Fire Marshal,

the Channelview Volunteer Fire Department,

the Highland Fire Department, and the Harris

County Pollution Control and Office of

Emergency Management. Medical command

posts were established near Interstate 10, and

the Sheldon and Redbud Roads.

The following agencies were involved in the

unified command center response:

ORGANIZATION RESPONSIBILITY

U.S. Coast Guard Oil spill cleanup and environmental

restoration

Texas General Land Office Oil spill cleanup and environmental

restoration

U.S. Army Corps of Engineers Channel and river obstructions

Texas Natural Resource Conservation Commission Oil spill and hazardous material response

National Oceanic and Atmospheric Administration Scientific support and shoreline assessment

U.S. Environmental Protection Agency Inland oil spill and environmental

restoration/air and water sampling

U.S. Department of Transportation,

Office of Pipeline Safety

Federal pipeline safety

Railroad Commission of Texas State pipeline safety

Texaco Pipeline, Inc. Information and assistance

Colonial Pipeline, Inc. Information and assistance
20

The Coast Guard managed the cleanup

efforts, which involved laying booms

downstream of the area where the pipelines

ruptured to protect sensitive areas and deflect

and collect the liquids released from the

pipelines. Oil deflected to narrow areas in the

river and gathered within booms was retrieved

from the water surface using skimmers or

vacuum trucks.

The EPA managed air quality monitoring

through October 26 and obtained and analyzed

numerous water and soil samples. The EPA

found that the contaminants released during the

event did not pose a health risk to the public.

Disaster Preparedness

The Coast Guard’s Houston command last

held a drill to test the area’s emergency

organization capabilities and preparedness for

responding to a major spill with fire during

severe weather on February 10, 1994.16 Many of

the scenarios (including in-situ burning) tested

during that exercise occurred during the

response to the October 1994 flood. The

February exercise included use of an in-situ

controlled burn protocol. The April 29, 1994,

critique on the February exercise reported:

Performance

Planning section personnel were slow in

advancing the in-situ burn application.

This was caused by considerable internal

debate over “required” information for

RRT in-situ burn application submission

and by diverting technical resources to

evaluate the dispersant option.

The Area Contingency Plan should

recognize the possibility that FOSC may

want to consider processing simultaneous

response tool applications to RRT for

approval (in-situ, dispersants, etc.).

 

16A similar table-top exercise was planned to be

conducted in the Houston area on November 5, 1994, and

would have included most of the agencies that responded to

the October 1994 emergency.

Guidance should be included to the Area

Contingency Plan to handle

simultaneous/multiple response tool

applications to RRT (that is, division of

labor, two review teams, etc.).

Enhancements

The in-situ burn checklist needs to be

incorporated into the Area Contingency

Plan. It’s essential that the RRT identify

what information to be provided in the

checklist is “required” or “supplemental”

to support a decision by the RRT. Use the

Area Contingency Plan to prioritize

application work based on acceptable

response techniques within a specific

geographic area. Encourage area

committee members to explore

preapproval response options.

The Harris County Disaster Plan was

approved by the Texas Department of Public

Safety on August 10, 1994, as meeting all

applicable State and Federal requirements. The

last Harris County disaster drill was conducted

in May 1994. It simulated a natural disaster. The

disaster plan was activated on October 17, in

response to the flooding, and stayed in effect

until the fires were extinguished on October 24.

Hazardous materials training simulations had

been conducted by the Harris County Office of

Emergency Management in September and

November 1993 and in April 1994.

One of the problems that the Harris County

public safety officials identified during this

accident was the need for improved emergency

communication links between Harris County,

the Coast Guard, and the TGLO. They

recommended that a universal emergency radio

band frequency be used on-scene to improve

communications.
21

In-Situ Controlled Burning Approvals

As already stated, Texas is within the

jurisdiction of RRT VI. Policies governing

Region VI operations grant preapprovals for insitu controlled burning of spills that are 3 miles

or farther offshore and require that specific

approval be obtained for all other proposed insitu controlled burning. To obtain approval for

an in-situ controlled burn, the Galveston Bay

Area Contingency Plan (which was the plan

controlling the response actions of the unified

command during the October 1994 cleanup

activities in Texas) requires that the FOSC

consult with the Texas Air Control Board on all

requests regarding in-situ controlled burns. The

purpose of consultation is to provide the Air

Control Board opportunity to consider potential

hazards of a proposed burn based on its location

relative to populated areas and on the likely

harm it might do to air quality, given the

expected wind speed and direction, atmospheric

conditions, and other factors at the time of the

proposed burn.

The in-situ controlled burn plan developed

by the Region VI RRT preapproves the use of

in-situ burning in offshore Gulf Coast areas by a

FOSC under specified conditions, but it does not

address in-situ controlled burning for nearshore, inshore, or onshore areas. However, it

cautions that if :

A deliberate burn were planned for nearshore areas, along a shoreline or

riverbank, in a marsh, or onshore, the

potential for secondary fires would have

to be considered very carefully. The

proximity of ignitable vegetation, trees,

docks, and other facilities would need to

be examined with respect to the initial

movement of vapors (prior to ignition)

and the potential movement of burning

oil.

Although the plan was not applicable to insitu controlled burns in near-shore areas, it

contained (in its appendix) a checklist of

information that should be considered before

carrying out an in-situ controlled burn. The

eight-page list included numerous weather and

other factors that should be considered before

performing an in-situ controlled burn, and

recommended product-specific safety equipment

and procedures. The last item in the list (page

A-8) was a note stating that:

If the FOSC approves of in-situ burning,

local media and residents in areas within

the potential smoke plume trajectory must

be notified prior to initiating the burn.

Spill Response Overview

After the emergency, when the FOSC was

reflecting on the events of October 23, he stated

that it had become apparent to him that the

policy of enhancing ongoing fires had drifted

into an in-situ burn procedure without the

emergency managers recognizing the transition

and its ramifications. Consequently, they did not

follow established in-situ controlled burn

procedures. They did not develop a safety plan,

put required safety controls in place, evaluate

the need to evacuate adjacent residents (even

though residents had been allowed to return to

their homes on the morning of the burn), or give

notice about the in-situ burn to local

governments and private companies taking part

in the response.

Immediately following this incident, neither

the Coast Guard nor the EPA conducted an indepth, comprehensive critique of the response

operations to learn why established procedures

were not followed relative to the in-situ burn, or

to review other problems experienced. The

Coast Guard and several other organizations

conducted individual assessments of their

activities, but no overall critique was carried out

to obtain the collective feedback of the EPA,

local governments, private companies,

contractor groups, etc.

The FOSC stated that, because no one was

injured and the burn was technically effective

and the “right thing to do,” he did not

aggressively pursue the matter. His only
22

explanation for the errors made relative to the

in-situ burn was that all emergency personnel

had been working 18-22 hour shifts since the

flood began and that mistakes are far more

likely to be made under such conditions.

Overall, he believed that operations had been

effective, and that few mistakes had been made

during the response.

In his March 9, 1995, memorandum to the

Coast Guard Commandant on lessons learned

from the San Jacinto River response, the FOSC

characterized the response effort as

“extraordinarily successful” and provided the

“lessons learned” based on comments from the

various Coast Guard groups17 that participated in

the response. Among the recommendations

made in response to the lessons learned, he

included:

The Commandant should specify use of a

standard skeletal incident command

organization nationwide to facilitate

transitions from local to larger response

organizations when organizational

personnel are brought in from outside the

area and from industry. It was found that

some personnel brought in were familiar

with the Incident Command System as

defined in the Area Contingency Plan

while others were not and the differences

in command system knowledge create a

degree of confusion.

 

17The Coast Guard commands that participated in the

response critique were the Marine Safety Office Houston;

the Marine Safety Office Galveston; the Vessel Traffic

Service Houston-Galveston, Group Galveston; the U.S.

Coast Guard Cutter CLAMP; and the U.S. Coast Guard

Cutter HATCHET.

(See appendix A for additional material

regarding the lessons learned.)

Although the Coast Guard brought many of

its commands together to critique the events of

October 1994, it did not include all that

participated in the response, nor all personnel

who had served in management response

positions. Specifically, the Pacific, Gulf, and

Atlantic Strike Teams, and the Operations

Section chief and Operations Division I

supervisor did not participate.

On August 1, 1995, the EPA’s contracted

Technical Assistance Team issued its report on

the “controlled burn” of October 24 (the actual

date was October 23). The report stated that the

burn was performed to eliminate a large pool of

oil wastes and flood debris near the burned

pipelines and the Rio Villa Park subdivision that

was not accessible except by using a small boat.

It stated that the EPA OSC requested and

received permission from the FOSC to conduct

an in-situ burn, and that about 7:00 p.m. (actual

time was about 6:00 p.m.), the in-situ burn was

initiated. The EPA reported that the burn lasted

about 2 hours (actual duration was about 28

hours), was monitored throughout, selfextinguished, and affected about 0.25 acre

(actually more than 15 acres). The report

repeated that the event was an approved in-situ

burn and acknowledged that it had not been

publicly announced.
23

The Coast Guard, in conjunction with the

Research and Special Programs Administration

(RSPA), conducted an Incident Specific

Preparedness Review of the response to the

October 1994 petroleum spills in the San Jacinto

River. The report of the review was issued on

July 30, 1996. It identified many aspects of the

response that had been successful, such as

making effective use of the unified command

management process, and other features that

required improvement, such as the need for the

Coast Guard to have a common response

management system. However, the Coast Guard

review, like those conducted by the FOSC and

the EPA Technical Assistance Team, did not

include among those persons interviewed all

who had served in key response management

positions. For example, the Operations and

Planning Section Chiefs—two of the Coast

Guard personnel who knew most about the

October 23 in-situ burn—were not interviewed.

Also not interviewed were the Division I leader,

the TGLO representative who had initiated the

in-situ burn proposal, the EPA OSC, and

management personnel from the companies that

had been contracted to assist in conducting the

burn.
24

The River Basin18

Stream Behavior -- The San Jacinto River,

located just east of Houston, Texas, is a

meandering, alluvial stream with a flood plain

extending from the river eastward

approximately 2 miles and westward

approximately 3⁄4 mile. With time, alluvial

stream system banks will erode, sediments will

be deposited, and flood plains, islands, and side

channels will undergo modification. Alluvial

channels continually change position and shape

due to the water flow exerted on the streambed

and banks. These changes may be gradual or

rapid, and may result from natural causes or

human activities.

The behavior of a stream at a specific

location depends not only on the stability of the

stream at that location, but on the stream system

of which it is a part. Upstream and downstream

changes may affect the future stability of a site.

Natural disturbances, such as floods, droughts,

earthquakes, forest fires, etc., may result in large

changes in the quantity of sediment moved by a

stream and thereby cause major changes in the

stream channel. Such changes can be reflected

in the buildup or reduction of a streambed due

to sediment disposition or scouring,

respectively. They also can be reflected in the

lateral migration of the stream channel.

Human-made changes in the drainage basin

and the stream channel, such as alteration of

vegetation cover and construction of bridges and

 

18Information on stream characteristics, behavior, and

stability was compiled from Stream Stability at Highway

Structures, U.S. Department of Transportation, Federal

Highway Administration Publication No. FHWA-IP-90-

014, Hydraulic Engineering Circular No. 20, February

1991.

other structures, can alter the hydrology of a

stream, its transportation of sediment, and its

channel geometry. Such changes will affect the

magnitude, frequency, and other characteristics

of future floods.

Changes in channel geometry over time are

particularly significant during periods when

alluvial channels are subjected to high water.

Erosive forces during periods of high water flow

may have a capacity as much as 100 times

greater than those acting during periods of

intermediate or low flow. The full-channel flow

rate in many natural channels generally occurs

about every 1.5 years, during which about 90

percent of all changes in channel geometry

occur.

Alluvial channels deviate from a straight

alignment, causing the deepest portion of the

channel to oscillate transversely. This behavior

forms bends in the stream. When the current is

directed toward a bank, the bank is eroded in

that area, and the current is deflected and

impinges on the opposite bank farther

downstream. Scour in the bend causes the bank

to migrate farther downstream and sometimes

laterally.

As a meandering stream system moves

laterally and longitudinally, meander loops

move at unequal rates because the differing

compositions of the banks result in differing

erosion rates. Channel sections appear as slowly

developing bulb forms. On highly meandering

streams, elongated, bulb-shaped loops are likely

to form with the narrowest land area (neck)

gradually eroding until the stream cuts directly

across it. The cutoff meander loop, no longer a

part of the active stream channel, becomes an

oxbow lake. Oxbow lakes are indicative of

meandering streams but are not necessarily

SUPPLEMENTARY INFORMATION
25

indicative of the channel migration rate. The

cutoff of a meander loop causes a local increase

in the channel slope and a more rapid growth

rate of adjoining meanders. When engineers are

designing structures across streams, information

about the probable way the loop will migrate or

develop, as well as its likely growth rate, would

be useful.

Stream Stability -- The stability of a stream is

dependent on a number of interrelated variables,

including natural or imposed changes in a

stream system, evolution of stream channel

patterns, channel geometry, and watershed

hydrology. Human activities can produce major

changes in stream characteristics locally and

throughout the stream system. All too

frequently, the net result of stream

“improvement” is departure from stream

equilibrium. Human activities are a major cause

of changes to streambeds. The most common

human-caused activities that result in streambed

changes are channel alteration, streambed

mining, construction of dams and reservoirs, and

land-use changes.

Table 1 (see next page) lists the effects of

some common activities, as well as activities in

the San Jacinto flood plain, that might have

altered the streambed.

Pipeline Operator Survey

After the flood, the Texas Railroad

Commission and the OPS surveyed operators of

pipelines that cross the San Jacinto River and

gathered information on the pipelines and the

actions that operators took during and after the

flood. Safety Board staff analyzed the surveys to

learn about pipeline designs and installations

within the flood plain, and actions taken by

operators at the onset of and during the flood to

prevent failures and product releases. Thirty

pipeline operators provided information on 69

pipelines that they operated across the flood

plain.

Damages --Thirty-seven of the 69 pipelines

that cross the flood plain were either ruptured or

undermined during the flood; 13 at river

crossings only, 18 at locations within the flood

plain not at crossings, and 6 in both locations.

Eight of the 69 pipelines ruptured during the

flood; 4 at river crossings and 4 in the flood

plain.

Only 12 of the 25 operators that provided

information on the design bases of their

pipelines indicated that they had performed

some type of study of the river crossing to

augment their design decisions. (Survey

responses did not include details on the types of

studies performed.)

The other 13 operators cited industry codes,

Federal regulations, or both as the bases of their

pipeline designs. No operator indicated that it

had used the American Petroleum Institute’s

Bulletin 1105, Bulletin on Construction for Oil

and Products Pipe Lines (first edition, 1955) or

performed a comprehensive study of the flood

plain.

Spill Prevention -- Fifty of the 69 pipelines

were regularly patrolled during the flood by

employees in aircraft, walking the pipeline

route, or stationed on either side of the flood.

While the operators’ efforts to patrol the flooded

pipelines were reasonably uniform, their actions

to minimize the potential consequences of a pipe

rupture were not.
26

Table 1 - Effects on stream stability

Modification General Action Impact on San Jacinto Flood Plain

Channel Alterations Include constrictions to maintain a

navigation channel and highway

crossings, both of which increase

water velocities and the rate of

sediment transport.

In 1940, the San Jacinto was a lazy

meandering river unspoiled by

development. The Lake Houston

Dam was completed in 1954. The

eastbound Interstate 10 bridge span

was constructed in 1951–55 and the

westbound bridge was built in 1971.

The new U.S. Route 90 was

constructed in the 1980s, and other

road crossings were also constructed

across the San Jacinto flood plain.

Streambed Mining

for Sand and Gravel

Usual result is streambed degradation.

Dam and reservoir effects on

downstream stability depend on stream

flow characteristics caused by stream

flow regulation. Postconstruction

flows during floods tend to be of lesser

magnitude but longer duration. Can be

beneficial or detrimental, depending

on the balance between sediment

supply and transport capacity.

The Corps of Engineers issued

several permits over the years for

streambed mining, both upstream

and downstream of Banana Bend.

Sand mining began in 1944 and

continued up to 1989. The result was

formation of lagoons along and

adjacent to the streambed.

Land-Use Changes Such changes include agricultural

activities, urbanization, commercial

development, and road construction,

which can accelerate erosion, causing

streams to overload with sediment and

lowering the ground water table,

resulting in subsidence. However, once

an area is fully developed, the

watershed becomes a low sediment

producer due to the higher number of

lawns and other rain-impervious areas

that increase rain runoff. This reduces

the time needed for runoff to reach the

stream, resulting in larger quantities of

water massing at a point in the

watershed. The downstream effect

generally is channel widening and

increased stream meandering.

The change in the flood plain from

rural to suburban land use began

occurring gradually in the 1950s,

with substantial changes occurring in

the 1960s and 1970s. Open-pit sand

mining in the flood plain flourished

in the 1960s and 1970s, with large

open-pit mining taking place in

historic riverbeds and oxbows in the

Banana Bend area and the oxbow

that encompassed the Rio Villa Park

subdivision.
27

On October 18, as a precaution, one operator

shut down five pipelines. On October 19, an

operator shut down four operating pipelines and

purged them after another of its pipelines failed.

A different operator shut down its pipeline

because no deliveries were scheduled.

Eleven operators reported shutting down a

total of 14 pipelines on October 20 for widely

varying reasons; 1 shutdown was ordered after a

pipeline failure, 1 after the flood damaged the

operator’s control system, 2 because no

deliveries were scheduled, 5 as a safety

precaution (with 1 operator stationing personnel

at its river valves to close them should the pipe

fail), and 5 in response to the Texas Railroad

Commission’s request to discontinue operations

and purge products. Six pipelines shut down on

October 20 were purged of product, and the

internal pressure of a seventh was reduced

substantially.

On October 21, two operators shut down

seven pipelines, purged the pipelines after

shutdown using nitrogen, and notified the Texas

Railroad Commission of the shutdowns. On

October 22, an operator shut down his pipeline

after experiencing an electrical problem caused

by the flood. On October 24, an operator shut

down his pipeline, purged it, and installed a

closure cap at the crossing, after learning that

the pipeline had been undermined.

No special measures were taken during the

flood for 36 of the 69 pipelines. Twenty-nine

were operated throughout the flood, three

contained products under pressure with no

transportation being performed because no

deliveries were scheduled, and three were empty

of products and maintained as extra lines.

Pipeline operators reported that 24 mainline

valves near the river were inaccessible because

they had been flooded, and 1 operator reported

the loss of its SCADA19 system because of

 

19A computerized supervisory control and data

acquisition (SCADA) system. SCADA screens continually

display operational data, such as product pressure and flow

rates for pump stations and other locations throughout the

pipeline system.

flooding. Operators reporting the least difficulty

were those whose pipelines had been

“directional drilled”20 beneath the river crossing,

at elevations significantly lower than the

riverbed. Even so, some operators of

directionally drilled pipelines experienced

erosion of the pipeline segments in the flood

plain.

Factors Influencing Failures -- Safety Board

staff identified each pipeline’s location across

the flood plain, defined six areas along the river

where pipelines were likely subjected to similar

forces and conditions, and looked at the pipes’

construction dates; sizes, wall thicknesses, and

specifications; crossing anchorages; operating

and design pressures; design bases; and

performance in each area. This process helped

to identify common factors that might have

contributed to the damages during the flood.

The six areas were as follows:

Area 1 – Lake Houston Dam to Banana

Bend, containing 13 pipelines: reasonably

straight alluvial stream segment having

banks steeper than average for this

stream;

Area 2 – Banana Bend, containing 17

pipelines: meandering alluvial stream

segment having lower than average banks

with adjacent areas being oxbow lakes or

streams likely created by previous

changes in the river channel and

significant areas where sand had been

mined;

 

20Directional drilling involves the use of auger-type

boring machines to drill an opening beneath a stream or

road and placing either the pipe or a casing in the opening

as it is being bored. Some equipment used can be guided

remotely to achieve a specified depth and curvature beneath

an object.
28

Area 3 – Banana Bend Oxbow,

containing 4 pipelines: meandering

alluvial stream segment having lower than

average banks with adjacent areas being

oxbow lakes or streams likely created by

previous changes in the river channel and

significant areas where sand had been

mined;

Area 4 – South of oxbow to Interstate 10

bridge, containing 4 pipelines: a

significant widening of the river with

steeper than average banks with adjacent

areas more densely populated or

industrialized;

Area 5 – Near Interstate 10 bridge

substructure, containing 6 pipelines: an

area subject to scour as a result of the

substantial reduction in effective stream

width due to the Interstate 10 bridge and

its substructure; and

Area 6 – Downstream of Interstate 10

bridge, containing 25 pipelines: a

substantially widened stream segment

with no significant downstream

reductions in effective stream width.

(See figure 7 for specific siting of the six

areas.)

The damage to pipes and their supports

occurred all along the river south of the Lake

Houston Dam; however, the major damages

occurred in areas that included maximum stream

meandering (Areas 2 and 3) or contained

significant narrowing of the stream by a humanmade obstruction (Area 5). Substantial sand

mining had also been done in Areas 2 and 3.

Table 2 (see pages 30-31) reflects the

findings of the Safety Board staff with respect to

information obtained from pipeline operators

through the pipeline survey conducted by the

Texas Railroad Commission and the OPS

following the 1994 San Jacinto flood.

Federal Requirements

Administration -- RSPA, through the OPS, is

responsible for developing and enforcing

minimum Federal safety standards for the

transportation of natural gas and hazardous

liquids by pipeline. Title 49 Code of Federal

Regulations (CFR) Parts 192 and 195 contain

the primary requirements for natural gas and

hazardous liquids transportation, respectively.

Title 49 CFR Part 194 establishes spill

prevention and response requirements

applicable to operators of liquid pipelines.

Natural Gas Pipelines -- The first Federal

natural gas pipeline regulations were issued as

Title 49 CFR Part 192 on November 7, 1968.

The OPS adopted as Federal standards the

requirements of an industry code—the B31.8

Code for Gas Transmission and Distribution

Piping Systems. Today, many provisions of the

1968 edition of the B31.8 Code remain in the

Federal minimum pipeline safety requirements.
29

./.

:’$)

:;... .... .. ,. ...’..

j,

;4A, ,<

\<

1 2 3 Miles

Area 1

---- L“

-.. . -1

l----b --=”-’

Area 3 ,.~ Wallisville . . . . . . .

Roa

. . . . --- - - - - ..--- .---.. -------- .-=

I

~T

T

~ ChemicalPlant ..-------.---------- - !

Area 4 j . .,

g -- am..o . . . . - Area 5 % - - -

I

4-. A”

Area 6 m A

Figure 7- Six areas identified along the San Jacinto River
30

Table 2 – Pipeline survey findings

AREA PIPE FAILURES *PIPE UNDERMININGS STUDY OF

CROSSING

YEAR

INSTALLED LINE OPERATOR

Flood

Plain

Crossing Flood

Plain

Crossing

1 1982 Midcon

1 YES 1970 Mobil

1 X (35ft.) X (60ft.) YES 1957 Texas Eastern

1 X X NO 1954 Citgo

1 X (200ft.) NO 1958 Tejas Gas

1 YES 1947/1979 Mobil

1 YES 1982 Midcon

1 NO 1985 Midcon

1 X (110ft.) NO 1948 Houston Pipe Line

1 YES 1979 Mobil

1 YES 1952 Midcon

1 X (85ft.) NO 1931 Shell

1 X (25ft.) NO 1964 Tejas Gas

2 X (240ft.) NO 1985 Enerfin

2 X (219ft.) X (18ft.) NO 1957 Chevron

2 NO 1992 Enterprise

2 X (173ft.) X (22ft.) NO 1975 Chevron

2 X (313ft.) YES 1971 Explorer

2 NO 1992 Enterprise

2 X (233ft.) YES 1977 Chevron

2 X (160ft.) NO 1977 Arco

2 X (160ft.) YES 1975 Air Liquide

2 X (160ft.) YES 1975 Air Liquide

2 X (134ft.) NO 1980 Seminole

2 X (160ft.) NO 1975 Arco

2 X (160ft.) NO 1966 Arco

2 X (182ft.) YES 1977 Phillips

2 X (160ft.) NO 1966 Arco

2 X (160ft.) NO 1975 Arco

2 X (160ft.) NO 1975 Arco

3 X X NO 1952 Valero

3 X X NO 1948 Texaco

3 X X YES 1962 Colonial

3 X X (587ft.) YES 1979 Colonial

4 1990 Old River

4 X (20ft.) NO 1956 Lyondell
31

AREA PIPE FAILURES *PIPE UNDERMININGS STUDY OF

CROSSING

YEAR

INSTALLED LINE OPERATOR

Flood

Plain

Crossing Flood

Plain

Crossing

4 X (20ft.) NO 1956 Lyondell

4 1990 Cowboy

5 X X X 1946 Exxon

5 X X X YES 1947 Exxon

5 X (25ft.) YES Exxon

5 X YES 1960 Exxon

5 X (120ft.) YES 1960 Exxon

5 X X X YES 1937 Exxon

6 NO 1987 Amoco

6 YES 1992 Praxair

6 1957 EGP Fuels

6 X (120ft.) 1948 Houston

6 X (390ft.) NO 1952 Chevron

6 NO 1993 Chevron

6 X (120ft.) NO 1968 Chevron

6 NO 1954 Chevron

6 X (120ft.) NO 1970 Chevron

6 NO 1982 Midcon

6 NO 1952 Midcon

6 NO 1952 Midcon

6 NO 1952 Midcon

6 1959 EGP Fuels

6 YES 1980 Praxair

6 1952 Midcon

6 YES 1955 Channel

6 1955 ATTCO NGL

6 YES 1975 Houston L&P

6 NO 1971 Air Products

6 NO 1971 Air Products

6 1971 Air Products

6 YES Praxair

6 1959/1980 EGP Fuels

6 1959 EGP Fuels

TOTAL 4 4 24 19 23 --- ---

∗ The number in parenthesis is the length of the pipe undermining as provided by operators. For some pipes, the length of

undermining approached or exceeded the maximum unsupported length of pipe for continued safe operation.
32

Design. The Federal regulations concerning

pipe design include general requirements that

pipelines be able to withstand anticipated

external pressures and loads that will be

imposed on the pipe after installation (CFR Part

192.103); mainline valves be installed at

intervals ranging from 5 to 20 miles, depending

on the population density along the route of the

pipeline (CFR Part 192.179); pipelines be

protected from washouts, floods, and other

hazards that may cause them to move or to

sustain abnormal loads (CFR Part 192.317); and

pipe installed in a navigable river, stream, or

harbor have a minimum cover of 48 inches in

soil or 24 inches in consolidated rock (CFR Part

192.327). No requirement specifically addresses

design of pipelines in flood plains.

Liquid Pipelines -- The first Federal liquid

pipeline regulations were issued by the Federal

Railroad Administration and became effective

on December 31, 1967. The authority for liquid

pipeline safety was later transferred to the OPS.

Title 49 CFR Part 195, which now contains the

minimum pipeline safety requirements

governing liquid pipelines, was and continues to

be based on an industry standard—the B31.4

Code for Liquid Transportation Piping.

Design. The regulations concerning liquid

pipeline design require that pipelines be capable

of withstanding anticipated external loads, such

as earthquake, vibration, and thermal expansion

and contraction (CFR Part 195.110); have 48

inches (18 inches in rock excavations) of cover

when crossing water bodies that are 100 feet or

more across (CFR Part 195.248); and have

mainline valves at locations where they will

minimize damage or pollution from accidental

discharges, including at each side of water

crossings that are more than 100 feet wide and

on each side of reservoirs holding water for

human consumption (CFR Part 195.260). No

requirement specifically addresses the design of

pipelines in flood plains.

Response Plans for Onshore Oil Pipelines --

Among other provisions, Section 4202 of Public

Law 101-380 (OPA 90), states:

The President shall issue regulations

which require an owner or operator of a

tank vessel or facility21 ...to prepare and

submit [for review and approval] to the

President a plan for responding, to the

maximum extent practicable, to a worstcase discharge, and to a substantial threat

of such a discharge, of oil or hazardous

substance.

On October 18, 1991, by Executive Order

12777, the President delegated to the Secretary

of Transportation the responsibility for

complying with OPA 90 provisions as they

relate to operators of onshore pipelines. Acting

on behalf of the Secretary, on January 5, 1993,

RSPA issued 49 CFR Part 194, Response Plans

for Onshore Oil Pipelines.

Plan Requirements. Plan requirements

apply to operators of onshore oil (natural gas,

highly volatile liquids, and carbon dioxide

pipelines are not included) pipelines that,

because of their locations, could reasonably be

expected to cause significant and substantial

harm to the environment by discharging oil into

or on any navigable waters or adjoining

shorelines. Among other requirements, and with

few exceptions, Part 194 requires operators of

affected pipelines to submit to RSPA a response

plan that defines the operator’s planned

resources for responding, to the maximum

extent practicable, to a (1) worst-case discharge

and (2) substantial threat of such a discharge.

Plan Approval. To assist operators in

complying with the planning requirement,

RSPA included appendix A to Part 194, setting

forth a recommended format (including specific

types of information to be included in each plan

 

21An onshore facility that, because of its location, could

reasonably be expected to cause substantial harm to the

environment by discharging into or on the navigable

waters, adjoining shorelines, or exclusive economic zone.
33

section) for operators to use in preparing their

plans. RSPA also met with groups of operators,

provided examples of “best practices,” and

communicated in writing and by telephone with

operators to assist them in preparing acceptable

response plans.

After operators submitted response plans to

RSPA, its staff and contract personnel compared

the plan content against a checklist developed to

assist them in quickly identifying plans that did

not contain all required sections or that did not

include all required information. When a plan

did not pass this initial completeness check,

RSPA notified the operator of the items omitted.

This completeness check did not entail a

specified assessment of the plan for adequacy.

Plans passing the completeness check were

reviewed in detail, this time using a 37-page

checklist, to assess whether the plan adequately

addressed required response issues, such as

procedures, notifications, equipment and

materials, and training. Operators of plans found

unacceptable were notified of noncomplying

provisions.

Plan Content. Examination by Safety Board

staff of plans prepared by 10 operators,

including the plans of all those operators whose

pipelines failed during the 1994 San Jacinto

flood, revealed that all but 1 operator

conditioned the implementation of response

actions on its becoming aware of an actual

release of product from its pipeline. Responding

to a substantial threat of a release was not

addressed. The plan of one operator included

plans for responding to substantial threats of

discharges, and cited preparations and actions to

take in the event of earthquakes, hurricanes,

tornadoes, bomb threats, etc., but flooding was

not included.

RSPA advised Safety Board staff that it had

not informed operators during the plan

development phase that their plans must include

provisions on responding to events that might

pose a substantial threat of pipeline discharge.

RSPA staff stated that they had focused their

reviews on an operator’s ability to respond to an

actual release of oil, and acknowledged that

RSPA had not examined the plans to confirm

that they contained provisions on responding to

substantial threat of discharge. RSPA staff have

stated that they intend, after the Safety Board

issues its report on the 1994 pipeline ruptures at

Houston, Texas,22 to send a letter to all plan

holders reminding them of the importance of

being prepared to respond to a substantial threat

of a worst-case discharge, even in the absence of

an actual release. RSPA staff have also stated

that RSPA will conduct a public meeting in fall

1996 to receive comments on changes required

in Part 194 to meet OPA 90 requirements.

Industry Design Standards and

Guidance

Gas Pipelines -- B31.8 Code. In 1952, the

American Standards Association issued Gas

Transmission and Distribution Piping Systems

(B31.1.8-1952) as the first code applicable

solely to gas piping. It contained no standards or

cautions on constructing pipelines across rivers

or flood plains, nor did it include information

about operating and maintaining these systems

while in service. (Later editions addressed

flooding and washouts as hazards to pipelines

and identified actions, such as increasing the

pipe wall thickness, that might protect the pipe

against failure.)

In 1969, the code was updated to recognize

the need to anchor pipelines that are normally

under water and to provide specific design

attention to pipelines that may be subject to

washouts due to natural hazards caused by

streambed changes, channel deepening, and

changes in the location of the channel in the

streambed. It also recognized that the design had

to be unique and based on the specific

characteristics of the stream being crossed.

While several editions of the code have since

been issued, no significant changes to the design

provisions have been made.

 

22This report.
34

Gas Pipe Design Manuals. The Gas

Engineers Handbook,

23 which was first

published in 1934 and went out of print in 1978,

was an aid to gas engineers who were designing

gas piping systems. The handbook advised that

pipelines under rivers might be subjected to

loads caused by bank recession, streambed scour

and fill, buoyancy, drag, movements of debris

and sand, and temperature changes. It

recommended that designers consider the effects

of river traffic and future improvements likely to

be made affecting navigation and flood control

and, so far as possible, to eliminate such

exposures. Among other advice, the handbook

stated that the designer should:

• Obtain a complete historical survey

detailing movements of banks and

“thalweg,”24 determine recorded

depths of scour, and review the

hydrograph of the stream (the

information obtained should cover a

considerable distance on each side of

the proposed crossing location);

• Perform soil borings along the

proposed crossing location; and,

• Provide flexibility for the crossing

pipe sufficient to allow it to resist

subsequent forces.

The handbook provides typical cross-section

and plan diagrams for stream crossings, but

gives no information specific to the design of

pipelines crossing flood plains.

Beginning in 1987, the American Gas

Association began publication of its Gas

Engineering and Operating Practices Series to

fill the void left when the Gas Engineers

Handbook stopped being published and to

provide more current information to member gas

companies on many aspects of the gas

distribution, storage, and transmission business.

 

23Sponsored by the American Gas Association and

published by The Industrial Press, New York, New York.

24The line extending down a channel that follows the

lowest elevation of the streambed.

The American Gas Association book

Transmission Pipelines/Planning and

Economics (Book T-1), published in 1989,

advises operators to use weights and coatings

for pipes crossing rivers and discusses general

installation methods for installing river

crossings, but it provides no specific design

recommendations for pipelines that cross flood

plains or rivers. The book advocates using

directionally drilled (or bored) crossings for

rivers because this method has the advantages of

impacting the environment less, causing no

disruption to navigation, and allowing

installation of crossings from beyond levees.

Guide for Gas Transmission and

Distribution Piping Systems. The Natural Gas

Pipeline Safety Act became effective on August

12, 1968. This act required the Secretary of

Transportation to adopt, within 3 months,

interim safety standards for gas pipelines, and to

establish, within 24 months, minimum Federal

standards for gas pipelines. Representatives of

the American Society of Mechanical Engineers

discussed with the Secretary what future role its

B31.8 Committee might have in pipeline safety.

Based on that discussion, the society decided to

form a Gas Piping Standards Committee (later

renamed the Gas Piping Technical Committee)

to develop and publish “how to” specifications

for complying with Federal gas pipeline safety

regulations.

The 1973 edition of the Guide for Gas

Transmission and Distribution Piping Systems,

as well as its current edition (1995–1998),

recommends installing sufficient weights or

anchorage to prevent the flotation of pipelines in

areas normally under water or subject to

flooding. It also cautioned that pipelines

crossing rivers may be subject to washouts as a

result of streambed changes, high water

velocities, channel deepening, or changing of

the channel location in the streambed. Because

of such hazards, operators were advised to give

design attention to protecting such pipelines by

locating them in the more stable areas of the

riverbank and bed, and that factors such as line
35

depths, pipe bend locations in the riverbanks,

wall thickness, and pipe weightings be based on

the individual characteristics of the river.

Liquid Pipelines -- API Bulletin 1105. In

March 1955, the American Petroleum Institute

(API) issued API Bulletin 1105, Bulletin on

Construction Practices for Oil and Products

Pipe Lines, as a tentative document. It was

effective for 1 year unless approved again by the

API. The API did not renew the bulletin because

the guidance it contained was expected to be

included in a soon-to-be developed standard on

liquid pipelines (B31.4 Code).25 The bulletin

advised pipeline operators to survey each water

course crossing to obtain all information needed

to design the crossing. It stated that a major

water crossing must be the subject of a special

study to design the proper type of installation. It

advised that the width of the valley and the

flood plain, the height of the river’s banks, the

width of the streambed, and the type of soil in

the area must be considered in developing

crossing designs. This bulletin provided

considerable guidance on designing and

installing pipelines crossing water courses and

flood plains.

B31.4 Code. The development of the liquid

pipeline industry’s pipeline code followed a

pattern similar to that of the gas pipeline code.

The American Standards Association B31.1.1

code served as the standard for liquid pipelines

until December 13, 1966, when the American

Standards Association issued the B31.4 code.

Like its gas code counterpart, this code stated

that its design requirements were adequate for

public safety under conditions usually

encountered, and it cautioned design engineers

that they needed to “provide reasonable

protection to prevent damage to the pipeline

from unusual external conditions which may be

encountered in river crossings” and other

locations (paragraph 402.1). Although the API

Bulletin 1105 had not been in effect since

March 1956, the liquid pipeline code still

referenced the bulletin. It stated that the bulletin

 

25See following section.

was a guide for developing specifications and

practices, and that its use would contribute to

safety and sound engineering practices when

constructing liquid petroleum pipelines.

The liquid piping code required that all river

crossings be surveyed and profiled after

construction (436.5.1 (b)(14)), that all

underwater crossings be inspected for

conditions that might affect the safety and

security of the crossings, and that inspections be

performed any time an operator felt that a

crossing might be endangered by floods, storms,

or suspected mechanical damage (451.5 (b)).

The 1979 update of the code removed the

references to API Bulletin 1105, which had not

been renewed for 23 years. Other applicable

code sections previously referenced have since

remained unchanged.

Pipe Failures During Floods

Flooding during summer 1993 in Iowa,

Missouri, and Nebraska caused significant

damage to pipelines in those States, including

pipeline ruptures. On April 1, 1993, in Sioux

City, Iowa, a 6-inch AMOCO pipeline ruptured

in the Big Sioux River due to scouring along the

riverbed. Three hundred and ninety barrels of

LPG were released. On July 26, 1993, a 6-inch

MAPCO pipeline was exposed by scour in a

creek bed and its banks, and was struck by flood

debris, which caused it to rupture. The rupture

resulted in the release of 2,203 bbls of

anhydrous ammonia. On December 1, 1993, a

10-inch Conoco pipeline ruptured in a flooded

area near Franklin, Missouri, resulting in the

release of 200 bbls of gasoline.

Safety Board staff reviewed pipeline

accident reports submitted to RSPA by the

pipeline industry for the years 1991 through

1993 to help assess the magnitude of damages

caused to pipelines and communities during

intervals of flooding. During the 3-year period

examined, 21 pipelines ruptured during floods; 5

were liquid pipelines (3 of which transported
36

highly volatile liquids), 13 were natural gas

transmission pipelines, and 3 were gas

distribution pipelines. The diameters of the

ruptured pipelines ranged from 4 to 30 inches.

Property damages for the 5 liquid pipeline

accidents were estimated by their operators to

total more than $1.7 million. The 13 natural gas

transmission accidents were estimated by the

gas operators to have caused about $700,000 in

property damages, and the 3 gas distribution

operators estimated their losses to be about

$9,000.26

After the 1993 flooding in the midwestern

States, RSPA issued Advisory Bulletin ADB93-03 to pipeline operators in those flooded

areas to advise them of measures they should

consider to ensure the safety of their pipelines.

Among others, the bulletin contained the

following suggestions for preventive actions:

• Deploy personnel so that they will be

in position to take emergency actions,

such as shutdown, isolation, or

containment;

• Extend regulator vents and relief

stacks above the level of anticipated

flooding;

• Evaluate the accessibility of pipeline

facilities that may be in jeopardy;

• Perform frequent patrols to evaluate

right-of-way conditions at water

crossings during flooding and after

waters subside. Determine if flooding

has exposed or undermined pipelines

as a result of new river channels cut

by the flooding or by erosion or

scouring;

• Coordinate with emergency and spill

responders on pipeline location and

 

26Based on previous Safety Board reviews of property

damages reported to RSPA by pipeline operators, the total

property damages reported are likely significantly less than

actual losses to all parties. They also likely do not include

environmental damages and losses, or losses due to

community disruptions.

condition, and provide maps and

other relevant information to them;

and,

• Coordinate with other pipeline

operators in the flood area and

establish emergency response centers

to act as liaison for pipeline problems

and solutions.

On October 25, 1994, RSPA issued Pipeline

Safety Advisory Bulletin ADB-94-05 (see

appendix B), which provided observations on

the flooding near Houston, Texas, and actions it

believed pipeline operators should take to

ensure the integrity of pipelines in case of

flooding. That bulletin includes essentially the

same suggestions for preventive actions as did

Advisory Bulletin ADB-93-03.

Also on October 25, 1994, the RSPA

Administrator stated that RSPA must determine

what changes may be necessary to ensure that

pipelines have the best chance possible of

withstanding inevitable, but often unpredictable,

natural disasters. He advised that RSPA would

accelerate the completion of a pending

rulemaking that would propose new

requirements for hazardous liquid pipeline

valves and leak detection systems. He further

advised that final rules were scheduled for

issuance by December 1995. Also, the

Administrator stated that RSPA would perform

a comprehensive study of the ability of the

Nation’s pipeline systems to withstand the risks

posed by natural disasters. He advised that

issuance of the report findings and

recommendations was planned for summer

1995.

On June 7, 1995, in response to significant

pipeline accidents that had been caused by

natural disasters, including the flooding of the

San Jacinto River near Houston, RSPA entered

into an agreement with FEMA. The agreement

called for FEMA to conduct a study on the

design, construction, and operating methods that
37

pipeline operators use to counter the effects of

natural hazards on pipelines. In so doing, FEMA

was to perform the following tasks:

1. Using the San Jacinto River basin,

perform a prototype study of tasks 2

through 5 (see following) to validate

the feasibility of applying the study

results nationwide;

2. Provide exposure risk analysis for

natural disasters, including floods,

earthquakes, landslides, tornadoes,

hurricanes, forest fires, and blizzards,

in the Nation;

3. Provide an analysis of high

consequence areas in the United

States by considering deaths and

fatalities, disruption of commerce,

damage to environmentally sensitive

areas, and damage to property;

4. Identify pipelines in geographical

areas that have high exposure risk to

natural disasters and high

consequence. FEMA is also to

develop a listing of pipeline

segments, pipeline operators,

commodities transported, and worstcase discharge estimates for liquid

pipelines;

5. Identify 10 areas of high pipeline

concentrations in the high

exposure/consequence areas.

The FEMA study is still in progress. It is

expected to be completed in fall 1996.

RSPA had previously contracted with Texas

A&M University to provide technical

engineering support with respect to pipeline

research. One element of that contract had

called for the university to:

Conduct an analysis regarding the

probability and the consequences of

pipelines being seriously affected by

natural disasters and propose potential

measures to prevent leaks or spills and to

mitigate the consequences of leaks and

spills resulting from natural disasters.

 With the issuance of the FEMA contract,

RSPA revised this element of the Texas A&M

contract. The revised task called for the

university to:

Analyze the potential effects of natural

disasters on the physical and operating

characteristics of pipelines in various

geographical areas, and provide

recommendations that will prevent or

mitigate ruptures resulting from exposure

to these events.

In making this modification, RSPA observed

that:

Safety programs for pipelines have often

focused on preventing third-party and

corrosion damage. While these types of

events may account for the majority of

serious damages to pipelines, potential

catastrophic damage to pipelines due to

natural disasters needs to be analyzed so

that measures can be developed that

would prevent or mitigate the

consequences.

The report on this modified requirement of

the Texas A&M contract will likely be available

in fall 1996.

Tests and Research

Metallurgy -- On-site examinations of the

exposed portions of the 4 pipes that ruptured in

the new channel formed when the San Jacinto

River cut through the oxbow (Colonial’s 40- and

36-inch, Texaco’s 20-inch, and Valero’s 12-inch

pipelines) revealed that each pipe had a buckle

deformation in several areas consistent with

each pipe bending southward in the direction of

the water flow. Laboratory examination of the

failures indicated that each pipe contained

fatigue cracks emanating from multiple origins.
38

Riverbed Examinations -- The Texas

Department of Transportation evaluated the

extent of scour around the substructure of

critical sections of the two Interstate 10 bridges

(east- and west-bound). The results of the sonar

tests performed on October 21–22, 1994,

documented 12 locations in the main channel for

distances up to 130 feet south of the east-bound

Interstate 10 bridge.

 Those tests indicated that the main channel

in the area of the Exxon pipelines experienced

about 10–12 feet of scour. Water velocities

measured during the testing were found to be 13

feet per second—approximately 8.9 miles per

hour. A previous Safety Board report27 indicated

that stream velocities of this magnitude can

generate forces sufficient to move 5,000-pound

rocks within a stream.

 

27Highway Accident Report--Collapse of New York

Thruway (I-90) Bridge Over The Schoharie Creek, Near

Amsterdam, New York, April 5, 1987 (NTSB/HAR-88/02).
39

Pipeline Ruptures

Examination of four of the eight pipe failures

from the San Jacinto flood plain showed that

their fracture faces included fatigue cracks that

had originated from multiple origins. Those

pipes were uncovered and their foundations

were undermined when the new channel cut

through the oxbow. This situation allowed the

flood waters to oscillate the unsupported

pipelines and deflect them southward in the

direction of the water flow. These forces caused

the pipe walls to bend and buckle, creating

fatigue cracks at multiple origins. The fatigue

cracks continued to grow, decreasing the

effective thickness of the sound pipe wall

remaining, until the pipe could no longer

contain the internal pressure of the gas or liquid.

Design of Pipelines in Flood Plains

The location of the pipelines within the flood

plain and the design of the pipelines in this

location appear to have been the most relevant

factors affecting their survival. The pipelines

that were ruptured or damaged most severely in

the flood plain were those installed in areas

where the river course meandered the most,

where significant mining operations had been

conducted, and where streambed scouring could

be expected.28

Based on the information operators provided

about the 21 pipelines in Areas 2 and 3, 11 were

designed using only the Federal regulations

and/or industry codes as the bases for their

design and construction. The design bases for

only 7 of the 21 included some study of the river

to supplement the design and installation

 

28Particularly where the river width constricted.

practices for their construction. The Safety

Board concludes that the design bases of most

pipelines undermined or ruptured during the

flood did not include study of the flood plain to

identify potential threats; rather, operators used

only general design criteria applicable at the

time the pipelines were installed.

Three of the four pipelines that ruptured in

river crossings were operated by Exxon and

were located at the Interstate 10 bridge where

the river width is constricted and the streambed

is subject to scour, especially during flooding.

Exxon reported that it had studied the river

conditions to supplement its design and

installation decisions, but did not indicate

performing any study of the flood plain or of the

effects of scour.

After 1934 and until 1978, designers of the

gas pipelines installed across the San Jacinto

flood plain had the Engineers Handbook

available to them. It advised them to develop a

complete historical survey of areas where

streams were to be crossed and to consider

during the design process those future changes

that might occur in navigation, river traffic, and

flood control. Designers of liquid pipelines had

the 1955 API Bulletin 1105 available to them

for a brief time. The bulletin provided

comprehensive guidance on designing pipeline

crossings of streams and flood plains. It

included explicit cautions and advice on the

types of studies, tests, and historical reviews

that should be performed as integral parts of the

designing of pipelines crossing flood plains.

Nevertheless, no San Jacinto pipeline operator

cited either of these guidance documents in

response to the survey questions about the

design bases of their pipelines.

ANALYSIS
40

Had the API Bulletin 1105 been maintained

as a permanent design support document, the

information it contained would have raised

serious reservations to designers against

installing a pipeline across the San Jacinto flood

plain in areas of significant stream meanders.

Moreover, such information would have

strongly recommended against installing a

pipeline in such an area, especially since

previous sand mining operations had made the

route less stable. If no other cost-effective routes

had been available, then extensive testing and

research to define the potential safety threats

and provide protection against such threats

would certainly have been indicated.

If unacceptable threats of failure remained

for pipe segments in the flood plain after design

modifications had been made, a plan should

have been developed for shutting down and

purging the pipeline of product any time

projected environmental conditions were likely

to exceed the design limitations of the pipeline.

The need to periodically reassess the forces that

might be imposed on the pipeline by changes

within the flood plain should also have been

recognized through the use of API Bulletin

1105.

The propensity of alluvial streams to

meander, to cut off oxbows during floods, and

to change stream flow characteristics in

response to human-made and natural changes in

flood plains has been well-documented for many

years. However, only the 1955 API Bulletin

1105, a tentative standard in effect for only 1

year, provided reasonable guidance on designing

pipelines that cross flood plains. Other than

providing general cautions about the need to

protect pipelines from unusual external

conditions that may be encountered in river

crossings, neither Federal requirements nor

other industry codes have provided guidance to

designers on the types of threats posed to

pipeline integrity when pipelines are located in

flood plains.

Furthermore, the Federal regulations,

industry codes, and present-day design and

guidance manuals do not give adequate

guidance to designers on the types of studies of

flood plains that should be performed. Designers

are not sufficiently warned of the specific

hazards to pipelines, such as riverbed scour, that

can occur during flooding where a channel is

narrowed by obstructions like bridges. Also,

current documents do not address the need for

pipeline operators to monitor changes within

flood plains that might increase the threat

potential beyond that evaluated at the time the

pipeline was designed and installed.

While multiple pipeline failures such as

occurred in the San Jacinto flood plain are

infrequent, individual flood-caused failures are

not. No effective standards or guidance

currently exist for designing pipelines that cross

flood plains or river crossings. This deficiency

is especially significant with respect to pipelines

located near bridges and other locations where

the potential for streambed scour is greatest.

Consequently, such standards are needed to

identify to designers the many threats posed to

pipelines when crossing rivers and flood plains,

and to define the types of research, study, and

future design considerations that must be

conducted preparatory to designing pipelines

that cross flood plains.

The Safety Board concludes that standards

for designing pipelines across flood plains are

needed to define the multiple threats posed to

pipelines and to address the research, study, and

future considerations that must be used for

designing pipelines and periodically

reevaluating the integrity of their designs during

their operating life. The Safety Board therefore

believes that, with the American Petroleum

Institute taking the lead in this initiative, the

American Petroleum Institute, the Association

of Oil Pipe Lines, and the Interstate Natural Gas

Association of America should work together to

develop design and construction standards

adequate for pipelines to safely cross flood

plains and streambeds, including the

development of recommended practices for

periodically reassessing crossing designs in light
41

of changes that have occurred in the flood plain

or streambed.

Pipeline Operator Responses and Oil

Spill Response Plans

The many pipeline operators affected by the

flood responded to their similar failures of

pipelines crossing the flood plain with

considerably different strategies. On learning of

the failures, a few operators elected to shut

down operations, but left products under

pressure and valves open in the shutdown

pipelines. Some shut down operations, closed

valves, and purged the pipelines of products.

One operator continued operations for a time,

but posted employees at valves near the river

crossing to be prepared to close them should a

rupture occur. Other operators continued

operations as usual, though they were aware of

several failures of pipelines across the San

Jacinto flood plain. The Safety Board concludes

that most operators of pipelines crossing the San

Jacinto River flood plain continued operations

without evaluating the capability of the pipeline

design to withstand the threats presented by the

flood. The Safety Board further concludes that

few pipeline operators took effective response

actions during the San Jacinto flood to minimize

the potential for product releases.

Among the objectives sought by the OPA 90

requirements were for RSPA to require (1) that

liquid pipeline operators identify events that

pose substantial threats to pipelines that might

result in product discharges, and (2) that

operators have an action plan designed to

minimize such threats. Had these objectives

been accomplished, the responses of the liquid

pipeline operators to the flood and pipe failures

would likely have been reasonably uniform.

None of the RSPA-approved operator plans

reviewed by Safety Board staff included

information on actions that were to be

implemented should a flood pose a substantial

threat of discharge from a pipeline. Only one

operator’s plan contained any planning

concerning events that might pose a substantial

threat to a pipeline.

RSPA staff have acknowledged that they had

failed to recognize these OPA 90 objectives and

that they had not, through counseling of

operators and evaluation of operator plans,

checked to ensure that plans met these

objectives. With respect to this accident,

therefore, the Safety Board concludes that

pipeline operators would have been more likely

to have implemented early shutdown and/or

purging of products from pipe segments

crossing the San Jacinto flood plain had RSPA

required them to develop plans for responding to

substantial threats of a pipeline failure and

product discharge.

 The Safety Board recognizes that RSPA’s

failure to ensure accomplishment of these OPA

90 objectives was an oversight. However, it

does not view as sufficient the means proposed

by RSPA staff to remedy the error. RSPA must

do more than send each operator a letter

advising that the operator must be prepared to

respond to substantial threats to its pipelines.

Recognizing potential threats to pipeline

failures and developing means to remedy or

minimize such threats require actions

significantly different from those needed to

develop product cleanup processes.

Consequently, for RSPA to cause each operator

to recognize and be prepared to respond to

substantial threats of product discharges, it must

require operators to identify events most likely

to pose substantial threats to their pipelines. In

so doing, each operator should be able to

compare the forces that might be imposed on its

pipeline, weigh those forces against the design

capabilities of its pipeline, and identify locations

where the potential for damage is greatest.

Based on such evaluation, the operator would be

able to develop action plans to remedy or

minimize the identified threats.

The Safety Board believes, therefore, that

RSPA must require operators of liquid pipelines

to address, in their OPA 90 spill response plans,
42

identifying and responding to events that can

pose a substantial threat of a worst-case product

release. The Safety Board considers that it

should be possible to have such modifications

completed within a year.

Emergency Response to Pipeline

Releases

The Safety Board concludes that the

response by local, State, and Federal

government agencies to the flood emergency

was well-managed and effective. Immediately

following the first Colonial pipeline rupture, the

Harris County Sheriff’s Department effectively

coordinated the available resources. The early

activation of an Incident Command System, as

well as the previously conducted drills of the

Harris County Disaster Plan, greatly assisted the

Incident Commander in maintaining effective

management of both local and Federal agencies

responding to the flood and the gasoline fire.

The success of these efforts was supported by

the dedication of the responders, who worked

tirelessly around the clock responding to human

needs.

However, Colonial’s inability to promptly

identify the location of the rupture in its 40-inch

gasoline pipeline and rapidly isolate the

ruptured segment by closing remote-controlled

valves unnecessarily endangered area residents.

It was fortunate that a large part of the

endangered areas had been evacuated earlier

(due to flooding) before the pipe ruptured.

The need to improve public safety by

requiring effective monitoring of pipelines and

remote-controlled or automatic closing valves to

rapidly detect and stop the release of hazardous

materials from ruptured pipelines has been

consistently addressed in Safety Board reports.29

 

29Pipeline Special Study--Special Study of Effects of

Delay in Shutting Down Failed Pipeline Systems and

Methods of Providing Rapid Shutdown, December 30,

1970 (NTSB/PSS-71/01); Pipeline Accident Report--

Phillips Pipe Line Company Propane Gas Explosion,

Franklin County, Missouri, December 9, 1970

In this case too, the lack of effective

operational monitoring and of remote- or

automatic-operated valves prevented pipeline

operators from rapidly detecting and stopping

the release of products, which permitted the

release of large volumes of products. The

pipeline ruptures and releases, and threats of

additional ruptures experienced during the San

Jacinto flood, further support the necessity for

improvements in this regulatory area to

minimize the volume of hazardous materials

released when pipelines fail.

The RSPA Administrator stated on October

25, 1994, that it was essential to liquid pipeline

safety that his Administration implement

rulemaking on requirements for valves and leak

detection systems for liquid pipelines. He

further stated that such action should be

completed by December 1995. However, that

rulemaking action remains far from complete.

The Safety Board concurs with the RSPA

Administrator on the need to improve the ability

to rapidly shut down failed liquid pipelines and

urges RSPA to expedite completion of the rapid

detection and shutdown objectives called for in

Safety Recommendations P-87-22, P-91-1, and

 

(NTSB/PAR-72/01); Pipeline Accident Report--Mid

America Pipeline System Liquefied Petroleum Gas Pipeline

Rupture, West Odessa, Texas, March 15, 1983

(NTSB/PAR-84/01); Pipeline Accident Report--William’s

Pipe Line Company, Liquid Pipeline Rupture and Fire,

Mounds View, Minnesota, July 8, 1986 (NTSB/PAR87/01); Railroad Accident Report--Derailment of Southern

Pacific Freight Train on May 12, 1989, and Subsequent

Rupture of Calnev Pipeline on May 25, 1989, San

Bernardino, California (NTSB/RAR-90/02); Pipeline

Accident Report--Liquid Propane Pipeline Rupture and

Fire, Texas Eastern Products Pipeline Company, North

Blenheim, New York, March 13, 1990 (NTSB/PAR-91/01);

Pipeline Accident Report--Texas Eastern Transmission

Corporation Natural Gas Pipeline Explosion and Fire,

Edison, New Jersey, March 23, 1994 (NTSB/PAR-95/01);

and Special Investigation Report--Evaluation of Accident

Data and Federal Oversight of Petroleum Product

Pipelines (NTSB/SIR-96/02).
43

P-95-1.30 (See appendix C for details concerning

these recommendations.)

The Safety Board concludes that failed liquid

pipelines continue to release excessive volumes

of petroleum and liquid products into the

environment because RSPA has not established

requirements for rapid detection and shutdown

of failed pipe segments, and the liquid pipeline

industry has not incorporated means for rapidly

detecting, locating, and shutting down failed

pipe segments.

Environmental Spill Response

Oversight

Overall, the spill response efforts undertaken

were quite effective, due in large part to

interagency coordination in both planning and

implementing actions. When petroleum products

spilled onto the flood waters from ruptured

pipelines in the EPA’s assigned inland area of

responsibility and flowed into areas in the Coast

Guard’s assigned coastal zone of responsibility,

the two agencies promptly and harmoniously

resolved a potentially contentious issue on

overall command of the environmental cleanup

response. The two agencies’ operations

continued to be mutually supportive throughout

the remainder of the response.

Federal, State, and local agencies and their

contractors apparently worked effectively

among themselves and with the pipeline

operators and other private interests in

responding to the pipeline failures and product

spills. Improvements were needed in some

areas, however, as noted by the FOSC in his

March 9, 1995, memorandum critiquing the

response. Among the areas noted by the FOSC

as requiring improvement were

communications, uniformity in incident

command systems used by Coast Guard units,

personnel training, fatigue countermeasures, and

command and control of operations.

 

30Safety Recommendation P-95-1 was reiterated earlier

this year in NTSB/SIR-96/02.

Communication -- The supervisor of Division

I’s spill response operations, who was located

remote from the unified command center, was

not aware of many activities occurring in his

area of responsibility because he was not kept

informed of decisions made by command

officials. He was not aware that the EPA OSC

and his technical assistance team had been

assigned to deploy booms in the area of the new

channel, nor was he aware of the plan approved

by the FOSC and the TGLO for installing fire

booms and enhancing the in-situ burn in his

area. For the supervisor of Division I to have

carried out his assigned mission successfully, he

should have been fully informed of those

activities.

In-Situ Controlled Burn Decision -- At the time

the FOSC approved the Burn Enhancement

Proposal, he did not consider that what was

being proposed was technically an in-situ

burning. In fact, the proposal was for

performing an in-situ burn, but it contained few

of the features required to ensure safety during

in-situ burning. The FOSC, as well as the TGLO

representative who approved the burn, should

have recognized that to carry out the proposal

safely, it was necessary to:

• Perform several risk assessments for

downwind plume monitoring;

• Prepare a detailed safety plan,

describing the steps to be taken for

protecting the personnel igniting and

controlling the burn;

• Put adequate communication

procedures in place to minimize the

opportunity for incorrect or

inappropriate actions; and,

• Notify area fire and police agencies in

a timely fashion before conducting

the in-situ burn.

Had they taken these steps, the FOSC and the

TGLO representative would have learned that

the Planning Section had already completed

much of the research and planning work
44

 necessary for approving an in-situ burning. A

proper review of the proposal should have

quickly identified that the proposal was not

consistent with the actual conditions because

there were three, not one, pipelines releasing

products into the water, and because three

different products—diesel fuel and gasoline, as

well as crude oil—would be involved. Also, a

review of the proposal should have speedily

revealed that the hazards posed would be

significantly different from previously

conducted burns because of the site environment

(onshore and residential) and because more

volatile material (gasoline) would be involved.

All of these differences should have been flags

cautioning the FOSC of the need for greater

deliberation.

Reasonable forethought did not necessarily

have to have been a source of delay, but it

should have provided responders with sufficient

input to properly consider the proposal, to

establish adequate controls to meet all

requirements, to provide opportunity to inform

affected leadership of the plan, and to provide

controls and training on implementation to

minimize errors. The FOSC’s and the TGLO

representative’s approval of a proposal that did

not contain required safeguards significantly

increased the risks to those implementing the

plan, as well as to the response personnel and

the public. Additionally, the approvals did not

comply with several requirements of the RRT’s

operational procedures for conducting in-situ

controlled burns.

In hindsight, the in-situ burn was likely the

most effective remedy measure that could have

been undertaken. However, based on the

foregoing facts, the Safety Board concludes that

the risks to workers and the public were

increased significantly when the unified

command conducted an in-situ burn without

having in place appropriate checks and balances

to ensure that approved procedures and

requirements were followed explicitly.

Fatigue --The work environment in a spill

response situation calls for the most effective

command and control procedures to guard

against errors that may endanger responders and

the public. The Safety Board recognizes that this

environment is especially demanding due to the

numbers of people and separate agencies and

companies involved, the many hours worked

each day by responders, and the constant risks

faced by responders. Such environments

substantially increase the opportunity for human

error by fatigued workers who have worked

several days without adequate rest periods. The

Safety Board agrees with the FOSC that a single

incident command management process should

be used to ensure that all response personnel

clearly understand the command structure and

control functions.

Training -- Based on the FOSC’s findings in

the critique following the San Jacinto accident,

the Safety Board concludes that spill

management personnel responding from other

regions of the country and trained on different

incident command procedures created

communications, command, and control

difficulties because they were not familiar with

the incident command structure and procedures

in use in the Galveston Bay area.

Command and control, uniform incident

command structure, and responder training were

issues raised following the March 1989 accident

involving the EXXON VALDEZ releasing oil

after striking a reef in Prince William Sound,

Alaska.31 Since that time, the NRT has been

working to improve these and other areas

identified as requiring improvement. In June

1996, the NRT issued its Technical Assistance

Document Incident Command System/Unified

Command. This document provides guidance on

responding to spills, regardless of the spill

source or the transportation mode. The purpose

of this document is:

 

31Marine Accident Report—Grounding of U.S.

Tankship EXXON VALDEZ on Bligh Reef, Prince William

Sound Near Valdez, Alaska, March 24, 1989 (NTSB/MAR90/04).
45

...to educate all responders of the

National Response System to the

organizational management concept of

Unified Command as it fits within the

Incident Command System for emergency

response. Unified Command is a

necessary tool for effectively managing

multi-jurisdictional responses to oil spills

or hazardous substance releases.

The NRT states that it hopes that this

document will increase awareness, improve

integration and training, help develop a common

language and response culture, and help achieve

consistent, effective, and efficient response

among National Response System members.

The Safety Board agrees with the NRT’s

objectives and considers that the technical

document will enhance overall response

preparedness. The NRT is in a uniquely

advantageous position to foster achievement of

the stated objectives for all spill responders. The

NRT may encourage the Coast Guard and the

EPA to integrate into their procedures and

training of response personnel the command and

control principles of the technical document and

provide training to all of their personnel who

may occupy management positions during a

response. The Safety Board concludes that

implementation of the unified incident

command structure and operational principles in

the NRT’s Technical Assistance Document

Incident Command System/Unified Command

will enhance the overall preparedness for

responding to petroleum spills. Therefore, the

Safety Board believes that the NRT should

motivate NRT agencies to integrate into their

area contingency plans the command and

control principles contained in Technical

Assistance Document Incident Command

System/Unified Command and encourage them

to train all personnel assigned management

responsibilities in those principles. In addition,

the Safety Board believes that the NRT should

include procedures for implementing its Unified

Command/Incident Command System that will

ensure that all safety-critical operations are

coordinated with parties at risk.

After-Action Critique – Neither the FOSC’s

nor the joint Coast Guard/RSPA’s after-action

critiques were comprehensive or complete

because they did not include all responding

agencies and interests, nor did several key Coast

Guard management personnel participate. These

lapses prevented the after-action critiques from

addressing and providing insight about the

significant command and control deficiencies

experienced during this incident. Among the

deficiencies not identified by the critiques were

communication problems experienced in the

Operations and Planning Sections—essential

units under the FOSC’s command for effectively

managing the spill response.

Had the after-action critiques included all

agencies participating in the unified command

and all personnel functioning as managers, these

reports could have made known to the Coast

Guard Commandant and the NRT the

experiences and views of all participating

agencies and organizations on actions that could

have enhanced the response effectiveness.

Overall critiques of the operation should have

identified Harris County’s and potentially other

agencies’ support for improving

communications among participating parties,

thereby strengthening the FOSC’s

recommendation to the Coast Guard on

communication improvements. Also, the

critiques should have provided opportunity for

the FOSC, the EPA OSC, and the other response

participants to have learned and understood the

circumstances leading to the in-situ burn, which

would have assisted them in identifying specific

command and control improvements that, if

implemented, could greatly reduce the potential

for similar problems in future responses. The

Safety Board therefore concludes that some

lessons on improving the area’s spill response

preparedness were not learned primarily because

a comprehensive after-action critique was not

conducted.
46

On September 15, 1994, an amendment to 40

CFR 300.165 of the National Contingency Plan

eliminated the requirement for OSCs to prepare

reports for every major pollution incident.

Instead, to reduce the “burden placed on OSCs

and to avoid redundant paperwork,” OSCs are

now to prepare a report only if requested by the

NRT or the RRT. The stated rationale for the

amendment was that:

The most important information

contained in OSC reports – lessons

learned in specific responses – is

expected to be available from other

material prepared by the OSC, including

the pollution report and the OSC log

book.

The Safety Board agrees that the lessons

learned from spill responses are important

findings developed from after-action critiques

that should be shared with all NRT agencies and

reviewed by the NRT to assess the need to

modify its procedures and guidance documents.

Valuable lessons can be learned from each and

every response without respect to response size

or complexity. Each response should be

assessed by the NRT and its member agencies to

help identify improvements in procedures and

agency guidance.

Therefore, the Safety Board believes that the

NRT should establish guidance calling for

FOSCs to conduct a comprehensive after-action

critique of each spill response to incorporate the

observations of all participating agencies to

identify improvements needed in equipment,

communications procedures, guidance,

techniques, and management. The Safety Board

further believes that the NRT should request

that FOSCs document and forward to NRT

headquarters all “lessons learned” developed

from after-action critiques for review and

implementation nationwide as appropriate.
47

1. The design bases of most pipelines

undermined or ruptured during the flood did

not include study of the flood plain to

identify potential threats; rather, operators

used only general design criteria applicable

at the time the pipelines were installed.

2. Standards for designing pipelines across

flood plains are needed to define the

multiple threats posed to pipelines and to

address the research, study, and future

considerations that must be used for

designing pipelines and periodically

reevaluating the integrity of their designs

during their operating life.

3. Most operators of pipelines crossing the San

Jacinto River flood plain continued

operations without evaluating the capability

of the pipeline design to withstand the

threats presented by the flood.

4. Few pipeline operators took effective

response actions during the San Jacinto

flood to minimize the potential for product

releases.

5. Pipeline operators would have been more

likely to have implemented early shutdown

and/or purging of products from pipe

segments crossing the San Jacinto flood

plain had the Research and Special

Programs Administration required them to

develop plans for responding to substantial

threats of a pipeline failure and product

discharge.

6. The response by local, State, and Federal

government agencies to the flood emergency

was well-managed and effective.

7. Failed liquid pipelines continue to release

excessive volumes of petroleum and liquid

products into the environment because the

Research and Special Programs

Administration has not established

requirements for rapid detection and

shutdown of failed pipe segments, and the

liquid pipeline industry has not incorporated

means for rapidly detecting, locating, and

shutting down failed pipe segments.

8. Risks to workers and the public were

increased significantly when the unified

command conducted an in-situ burn without

having in place appropriate checks and

balances to ensure that approved procedures

and requirements were followed explicitly.

9. Spill management personnel responding

from other regions of the country and

trained on different incident command

procedures created communications,

command, and control difficulties because

they were not familiar with the incident

command structure and procedures in use in

the Galveston Bay area.

10. Implementation of the unified incident

command structure and operational

principles in the National Response Team’s

Technical Assistance Document Incident

Command System/Unified Command will

enhance the overall preparedness for

responding to petroleum spills.

11. Some lessons on improving the area’s spill

response preparedness were not learned

primarily because a comprehensive afteraction critique was not conducted.

CONCLUSIONS
48

As a result of its investigation, the National

Transportation Safety Board makes the

following recommendations:

-- to the Research and Special Programs

Administration:

Require operators of liquid pipelines to

address, in their Oil Pollution Act of 1990

spill response plans, identifying and

responding to events that can pose a

substantial threat of a worst-case product

release. (Class II, Priority Action)

(P-96-21)

-- to the National Response Team:

Make your membership aware of the

circumstances and nature of the events in

the October 1994 environmental response

at Houston, Texas, specifically in regard

to the need for coordinating all planning

and operational activities prior to

conducting in-situ burn countermeasures.

(Class II, Priority Action) (I-96-1)

Motivate National Response Team

agencies to integrate into their area

contingency plans the command and

control principles contained in Technical

Assistance Document Incident Command

System/Unified Command and encourage

them to train all personnel assigned

management responsibilities in those

principles. (Class II, Priority Action) (I96-2)

Include procedures for implementing your

Unified Command/Incident Command

System that will ensure that all safetycritical operations are coordinated with

parties at risk. (Class II, Priority Action)

(I-96-3)

Establish guidance calling for Federal

On-Scene Coordinators to conduct a

comprehensive after-action critique of

each spill response to incorporate the

observations of all participating agencies

to identify improvements needed in

equipment, communications procedures,

guidance, techniques, and management.

(Class II, Priority Action) (I-96-4)

Request that Federal On-Scene

Coordinators document and forward to

National Response Team headquarters all

“lessons learned” developed from afteraction critiques for review and

implementation nationwide as

appropriate. (Class II, Priority Action)

(I-96-5)

-- to the American Petroleum Institute:

Take the lead to develop, in cooperation

with the Association of Oil Pipe Lines

and the Interstate Natural Gas Association

of America, design and construction

standards adequate for pipelines to safely

cross flood plains and streambeds,

including the development of

recommended practices for periodically

reassessing crossing designs in light of

changes that have occurred in the flood

plain or streambed. (Class II, Priority

Action) (P-96-22)

RECOMMENDATIONS
49

-- to the Association of Oil Pipe Lines:

Develop, in cooperation with the

American Petroleum Institute and the

Interstate Natural Gas Association of

America, design and construction

standards adequate for pipelines to safely

cross flood plains and streambeds,

including the development of

recommended practices for periodically

reassessing crossing designs in light of

changes that have occurred in the flood

plain or streambed. (Class II, Priority

Action) (P-96-23)

-- to the Interstate Natural Gas Association of

America:

Develop, in cooperation with the

American Petroleum Institute and the

Association of Oil Pipe Lines, design and

construction standards adequate for

pipelines to safely cross flood plains and

streambeds, including the development of

recommended practices for periodically

reassessing crossing designs in light of

changes that have occurred in the flood

plain or streambed. (Class II, Priority

Action) (P-96-24)

 BY THE NATIONAL TRANSPORTATION SAFETY BOARD

JAMES E. HALL

Chairman

ROBERT T. FRANCIS II

Vice Chairman

JOHN A. HAMMERSCHMIDT

Member

JOHN J. GOGLIA

Member

GEORGE W. BLACK, JR.

Member

September 6, 1996

51

APPENDIX A

Selected “Lessons Learned” Developed by the FOSC (March 1995)

CGULLS LONG REPORT

1. CGULLS Number: N/A, Submitted by Marine Safety Office

Houston, Texas, LT LEONARD, COMM: (713) ..671-5171.

2. Operations surrounding the SAN JACINTO RIVER INCIDENT.

3. KEYWORDS: Incident Command System (ICS), Area Contingency Plan (ACP), Training, Key Personnel.

4. TITLE: INCIDENT COMMAND SYSTEM

5. OBSERVATION : Some personnel were familiar with the Incident

Command System (as defined in the ACP), others were not. In some

cases, personnel were familiar with different versions of the

Incident Command System (National Fire Academy, FIRESCOPE,

Phoenix Fire Department, District 11, etc.), which increased

confusion to a certain degree.

6. DISCUSSION: Personnel from Marine Safety Offices Houston and

Galveston were familiar with ICS as defined in the ACP through

numerous exercises. In addition, MSOS Houston and Galveston had

worked with several of the contractors on these exercises in an

ICS environment. Personnel who augmented from outside these

commands; including cutters and aviation. units; were not f a mi liar

with this type of a command and control system. “’Just-in-time i

’ training had to be provided to assimilate them into the incident

command structure. Personnel from MSO Houston served in each of

the Unified Command sections as either the Section Chief or as

the Assistant Section Chief (Initially, this was not true with

the Planning Section, but an M SO Houston officer was quickly

assigned as Section Chief). In most cases, the Section Chiefs during the flood response portion became the Assistant Section

Chiefs during the busiest portions of the spill response. As the

organization began to downsize, the Assistant Section Chiefs

again became Section Chiefs. This permitted continuity and local

area knowledge within each-section. Division Supervisors were

staffed with personnel from outside the MSO Houston command due

to no other MSO Houston officers or chief petty officers being

available -for assignment. The three offiers assigned Division

Supervisor duties performed very well and no loss of

effectiveness was realized.

7. W O RK-AROUND: The employment of a National Strike Force

“organizational expert,” nationally certified as an ICS

Instructor, facilitated overall ICS operations within the Unified

Command Center. This was

organizational model used

8. RECOMMENDED ACTION:

a. Commandant should

accomplished by utilizing the ICS

by the National Strike Force.

specify a standard skeletal ICS type of

5
52 APPENDIX A

organization to be employed nationwide. Commandant should

consider providing the field with samples of well developed

response organizations to assist Area Committees with the

organizational development process. Commanding. Officers’of

Marine Safety Offices should train personnel within their area of

responsibility in the Incident Command System.

b. Area Committees should fully develop the organizations to

be used in their areas in accordance with the standard. They

should identify the individuals to fill the roles as defined in

their ACP. These personnel should be identified by name or

source organization. Due to the high turnover of personnel at

Coast Guard units, Commanding Officers of Marine Safety Offices

should ensure that All assigned officers and chief petty officers

be trained as division supervisors. Officers should also be

trained to fill a minimum of two other positions (such as

logistics officer and operations officer). This would ensure an

appropriate mix of personnel at each unit to allow for the

organization to grow, stabilize, and downsize.

c. Unified Commanders should assign officers or chief petty

officers from the impacted Captain of the Port Zone to serve as

Division Supervisors. Assign officers from the impacted Captain

of the Port Zone to serve as Section Chiefs or Assistants in the

Finance, Logistics, ..Operations, and Planning sections. This

would provide continuity and local area knowledge “as the

organization grows, stabilizes, and downsizes.

d. “Mobility of management” should be discouraged by

personnel serving as Unified Commanders--when a person is

assigned to a position within the Unified Command, he/she should

remain in this position unless unusual circumstances dictate

otherwise. Personnel may fleet up/down as the organization grows

or downsizes --this is expected. What is to be avoided is

constant reorganization and assigment of new personnel to a

particular position on a daily basis. Both require constant

retraining and can lead to confusion.

e. A “three tiered” response structure should be developed

based on:

1. Responses that can be handled at the local level.

2. Responses that require “additional resources from

within the district (i.e. support from other than local units or

the District Response Assist Team and Special Forces located

within the district)

3. Responses that require support from outside the

district’s area of responsibility (i.e. resources from units,

including the National Strike Force, located outside of the

district, logistical support from the appropriate Maintenance and

6
APPENDIX A 53

Logistics Command, or additional Area or Headquarters

assistance).

9. COMMENTS: The key to the ICS organizational structure is.

that it can continue to expand as the response requires, with

minimal disruption to the organization. Incoming personnel

should be informed of their assignment prior to arrival. MSO

Houston recently published a “Personnel Planning for Contingency

Operations” letter letting District (m) ana other MSOS in. the

Eighth District know which personnel at this unit are qualified

to fill ICS-type positions. This will facilitate trained

personnel being dispatched to an incident. Using a standard

skeletal organization will help the transition tO larger response

organizations when using personnel from outside the area. Also,

industry response organizations will know what to expect on a

nationwide basis when they become part of an Incident Command

System.
54 APPENDIX A

CGULLS LONG REPORT

1. CGULLS Number: N/A, Submitted by Marine Safety Office

Houston, Texas, LT LEONARD, COMM: .(713) 671-5171.

2. Operations surrounding the SAN JACINTO RIVER INCIDENT.

3. KEYORDS: Personnel, Hour(s), Rest.

4. TITLE: EXCESSIVE WORK HOURS

5. OBSERVATION: Many personnel, especially those in critical

command positions, worked excessively long hours.

6. DISCUSSION: The San Jacinto River Incident began as an

intensive, 36-hour search and rescue operation. MSO Houston and

Air Station Houston together rescued or assisted 574 persons

during this time. This was followed by a 22-hour period of

extensive port recovery operations (channel, vessel, and bridge

inspections and surveys; pollution investigation and response;

wreck removal operations). While still in the port recovery

phase of operations, the pipeline explosion, fire, and spill

occurred. This led to another seventeen days of pollution

response. The Unified Commander determined that a,12-on/12-off

rotation would provide for. the best’ operational control of

personnel and resources. It would also allow personnel an

adequate amount of rest in between shifts. This policy was not

universally observed by key personnel in command and control

positions. MSO Houston personnel in key command and control

positions worked 20+ hour days during the first seven days, and

averaged 14-18 hour days thereafter. Additionally, these

personnel ’took only one day off during this nineteen day period

(though more days off would have been granted if requested). In

at least five instances, officers were~directed to take a day

off. Though there was no recognized loss of effectiveness, the

decision-making capability of these individuals could have been

impaired and stress or safety related problems could have

occurred. “ COMDTINST M301O.12B’, the Contingency Preparedness”and

Planning Manual, Volume II “(referencing COMDTINST M5312.llA, the

Coast Guard Staffing .Standards Manual) provides workweek planning

factors, which were exceeded by the majority of personnel

involved in the San Jacinto River Incident. COMDTINST M301O.12B

leads one to believe that personnel will work a 40-68 hour work

week during contingency operations. This is probably

unrealistic, especially prior to any augmenting forces arriving

as certain missions still need to be performed. Additionally,

senior personnel are reluctant to take time off and depart the

command center for fear of being “out of touch” before the

situation is under control.

7 . WORK-AROUND : The Unified Commander determined that a 12-

on/12-off rotation would provide for the best operational control

8
APPENDIX A 55

of personnel and resources and also allow personnel an adequate

amount of rest in between shifts. This rotation was not followed

by key personnel who continued to work 100+ hour weeks for three

straight weeks with minimal rest

8. RECOMMENDED ACTION:

Commandant should publish clearer guidelines than those

delineated in COMDTINST M301O.12B. Those provided for aviators

in COMDTINST M371O.1C may be used as an example. Leaders must

set the example by ensuring their subordinates follow these

guidelines

b. All personnel in leadership positions must be cognizant

of the amount of time their subordinates are working, especially

in an environment as stressful as experienced during the San

Jacinto River Incident. They must ensure that their personnel

are receiving an adequate amount of rest away from the work site.

In addition, these supervisors must also look at their own work

hours, and ensure that they too get adequate rest away from the

work site.

b. If the command center is relocated to a location more

than a one hour drive from the normal worksite (as happened

during this incident due to bridge closures and enhanced traffic

congestion ),the Logistics Section of the Unified command should

procure hotel rooms or similar accommodations closer to the new

command center. This would assist all individuals in receiving

adequate rest.

9. (U) COMMENTS: None.
56 APPENDIX A

CGULLS LONG REPORT

1. CGULLS Number: N/A, Submitted by Marine Safety Office

Houston., Texas, “LT LEONARD; COMM: (713) 671-5171;

2. Operations surrounding the SAN JACINTO RIVER INCIDENT.

3. KEYWORDS : Coast Guardsmen, Operations Section, Division

Supervisors, Foremen.

4. TITLE: SUPERVISORY PERSONNEL

5. OBSERVATION: Coast Guardsmen assigned to cutters, boat

crews, helicopters, and operational field divisions received

conflicting guidance and orders from the Unified Command Center

(Operations Section), Division Supervisors (Coast Guard

officers), and civilian foremen (from contractors).

5. DISCUSSION

a. One cutter was given instructions from the Operations

Section of the Unified Command to deploy the VOSS. The foreman

from a nearby civilian contractor recommended they not deploy the

VOSS due to the swift currents and called. District Eight for

confirmation.. 3District. agreed with. the foreman. The Operations

Section later contacted-the cutter to ask “why the VOSS was’ not

deployed. After explaining their reasons, they were again

directed to deploy the VOSS.

b. In another similar incident, one cutter was directed by

an operational Coast Guard unit to stop its current mission,

assigned by the Operations Section, and proceed on another

mission. The Division Supervisor then asked the vessel where it

was going and was informed that it had ‘a different mission to

complete.

c. In several instances, . helicopters were redirected from

their assigned missions (skimmer control, aerial surveys, etc. )

to conduct overflights for Division Supervisors or contractor

foremen. Very rarely was. this change i n mission communicated. to

the Operations Section.

In all of the above instances, these redirected resources were

not utilized in the manner specified by the Unified Commander

(through his Operations Section).

7. WORK-AROUND : On a daily basis, the Operations and Logistics

Sections spent a great deal of time trying to determine the

location and mission of resources that had been redirected. At

one point, the Operations Section had to give orders to

individual assets in order to ensure the Unified Commander’s plan

was followed. Not only did this cost money and time, but it was

10
frustrating for the crews who had to endure these conflicting

orders.

8. RECOMMENDED ACTION:

a . Unified Commanders must explain that, except for reasons

of safety, all mission changes should be directed by the Unified

Commander or the operations Section. Division Supervisors may

modify missions within their area of responsibility, but must

inform the Operations Section as soon as practicable.

b. Commanding Officers of Marine Safety Offices should

conduct training for senior Coast Guard personnel and contractors

on the incident command system. Ensure personnel assigned to key

position know and understand their role in the “big picture.”

Practice the incident command system in exercises.

c. Unified Commanders need to ensure organizational liaison

officers are present in the Unified Command Center who represent

all parries (Coast Guard, governmental agencies, contractors? and

responsible parties) to assist in resolving conflicts.

d. Unified Commanders must emphasize the need to “pass the

word”, to all personnel who maybe affected by mission changes.

Organizational liaisons. can facilitate this.

9. COMMENTS: None.

11

59

APPENDIX B

 Pipeline Safety Advisory Bulletin ADB-94-05; Pipelines Affected by Flooding

 [Federal Register: November 3, 1994]

----------------------------------------------------------------------------------------------------------------------

DEPARTMENT OF TRANSPORTATION

Research and Special Programs Administration

Pipeline Safety Advisory Bulletin ADB-94-05; Pipelines Affected by Flooding

AGENCY: Research and Special Programs Administration (RSPA), DOT.

ACTION: Advisory to each owner or operator of a hazardous liquid or natural gas transmission

pipeline operating in areas that may be subject to severe flooding.

----------------------------------------------------------------------------------------------------------------------

Summary: This advisory is for all operators of pipelines which may be affected by flooding. It

provides observations from RSPA, Texas Railroad Commission (TRC), and other federal and

state agencies as a result of the recent floods near Houston. This advisory also includes actions

that operators should consider taking to assure the integrity of pipelines in case of flooding.

Background: As the result of unprecedented flooding of rivers and streams in the Houston area,

seven natural gas and hazardous liquid pipelines failed in or near the San Jacinto River over the

three day period October 19-21, 1994. These failures included: an Exxon 8-inch diameter LPG

line; an Exxon 8-inch diameter fuel line; an Exxon 20-inch diameter hazardous liquid line; a

Colonial 40-inch diameter products (gasoline) line; a Colonial 36-inch diameter products

(heating oil) line; a Texaco 20-inch diameter crude oil line; and a Valero 12-inch diameter

natural gas line. While no determination of cause of failure has been made for any of these lines,

RSPA and the TRC believe that the extreme flooding by the San Jacinto River was probably a

substantial contributing factor in each of the failures.

The damage to pipelines caused by the flood may have resulted either from the extreme force of

the flowing water, as the San Jacinto carved new temporary channels, or from pipelines being

struck by heavy debris that was reported as having flowed down river at the height of the

flooding. Because RSPA and the TRC cannot at this time determine the exact effects of the

flooding, operators should consider the potential effects of flooding as posing a possible threat to

the integrity of their lines.
60 APPENDIX B

Advisory: As the result of seven natural gas and hazardous liquid pipeline flood-related failures

in or near the San Jacinto River in Texas on October 19-21, 1994, operators should consider the

actions recommended in this Advisory Bulletin for application to pipelines located in any area of

the United States subject to widespread flooding.

RSPA pipeline safety regulations in 49 CFR 192.613 for natural gas pipelines, and 49 CFR

195.401 for hazardous liquid pipelines, require an operator to maintain continuing surveillance of

its facilities and to correct damage to its pipeline that could affect the safe operation of the

pipeline (such as damage that may result from extreme flood conditions). If the operator of a

natural gas pipeline determines that the pipeline is in unsatisfactory condition and no immediate

hazard exists, the operator must recondition or phase out the segment involved, or reduce the

maximum allowable operating pressure. For hazardous liquid pipelines, if the condition presents

an immediate hazard to persons or property, the operator may not operate the affected part of the

system until the unsafe condition is corrected. In summary, if the operator has reason to believe

that flooding has adversely affected, or will adversely affect, its pipeline, the operator must take

corrective or preventative action.

In addition, operators must consider the application of RSPA's reporting requirements in 49 CFR

Part 191, and subpart B of 49 CFR Part 195, as well as applicable state requirements, that require

operators to submit telephonic and written reports when natural gas or hazardous liquids are

released causing damages meeting the reporting thresholds. Finally, RSPA regulations also

require operators to submit reports of safety-related conditions involving potentially unsafe

conditions on natural gas and hazardous liquid pipelines (49 CFR 191.23 and 191.25, and 49

CFR 195.55 and 195.56). Operators need to direct their resources in a manner that will enable

them to determine the potential effects of the flooding on their systems, and take the following

actions as appropriate:

• Deploy personnel so that they will be in position to take emergency actions, such as shut

down, isolation, or containment.

• Extend regulator vents and relief stacks above the level of anticipated flooding, as

appropriate.

• Evaluate the accessibility of pipeline facilities that may be in jeopardy, such as valve

settings, needed to isolate water crossings or other sections of a pipeline.

• Perform frequent patrols, including overflights as appropriate, to evaluate right-of-way

conditions at water crossings during flooding and after waters subside. Determine if

flooding has exposed or undermined pipelines as a result of new river channels cut by the

flooding or by erosion or scouring.

• Coordinate with emergency and spill responders on pipeline location and condition, and

provide maps and other relevant information to them.
APPENDIX B 61

• Coordinate with other pipeline operators in the flood area and establish emergency

response centers to act as liaison for pipeline problems and solutions.

• Determine if facilities which are normally above ground (e.g., valves, regulators, relief

sets, etc.) have become submerged and are in danger of being struck by vessels or debris;

if possible, such facilities may be marked with an appropriate buoy with Coast Guard

approval.

• Perform surveys to determine the depth of cover over pipelines and the condition of any

exposed pipelines, such as those crossing scour holes. Where appropriate, surveys of

underwater pipe should include the use of visual inspection by divers or instrumented

detection. Information gathered by these surveys should be shared with landowners.

Agricultural agencies may help to inform farmers of the potential hazard from reduced

cover over pipelines.

• Assure that line markers are still in place or are replaced in a timely manner, and notify

contractors, highway departments, and others involved in post-flood restoration activities

of the presence of pipelines and the risks posed by reduced cover.

 If a pipeline operator has suffered damage to its line, or has shut in the line, or has operated at a

reduced pressure as a precautionary measure during the flood, the operator should advise the

State Pipeline Safety Office (for intrastate lines), or RSPA's Regional Pipeline Safety Office

(interstate lines) prior to returning the line to service, on increasing the operating pressure, or

otherwise changing the operating status of the line. The State Safety Division or the RSPA

Regional Pipeline Safety Office, as appropriate, will advise on a case- by-case basis whether, and

under what conditions, a line can safely be returned to full service.

 Issued in Washington, D.C. on October 28, 1994. George W. Tenley, Jr., Associate

Administrator for Pipeline Safety. [FR Doc. 94-27227; Filed 11-2-94; 8:45 am] BILLING CODE

4910-60-P.

63

APPENDIX C

 Safety Recommendations P-87-22, P-91-1, and P-95-1

Safety Recommendation P-87-22

As noted in the Edison, New Jersey, pipeline accident report,1

 the National

Transportation Safety Board began in 1970 to address the need for rapid shutdown of failed pipe

segments. The Safety Board identified the need to require automatic control valves and/or remote

control valves to facilitate rapid shutdown of failed pipelines in five accident investigations

dating back to 1970.2 As a result of its investigation of the 1986 Mounds View, Minnesota,

accident,3 the Safety Board recommended that RSPA:

P-87-22

Require the installation of remote-operated valves on pipelines that transport

hazardous liquids, and base the spacing of remote-operated valves on the

population at risk.

To date, RSPA has not implemented any requirements for automatic control valves or

remote control valves as means of achieving rapid shutdown of failed pipeline segments. Safety

Recommendation P-87-22, which was classified “Closed—Unacceptable Action/Superseded” on

February 7, 1995, was superseded by Safety Recommendation P-95-1, which is detailed below.

Safety Recommendation P-91-1

The Safety Board has repeatedly issued recommendations addressing pipeline monitoring

and leak detection and the use of remotely operated or automatic valves as methods to achieve a

rapid shutdown of failed pipeline segments, to isolate the failed pipeline segments, and to limit

 

1

Pipeline Accident Report--Texas Eastern Transmission Corporation Natural Gas Pipeline Explosion and

Fire, Edison, New Jersey, March 23, 1994 (NTSB/PAR-95/01).

2

Pipeline Special Study--Special Study of Effects of Delay in Shutting Down Failed Pipeline Systems and

Methods of Providing Rapid Shutdown, December 30, 1970 (NTSB/PSS-71/01); Pipeline Accident Report--Phillips

Pipe Line Company Propane Gas Explosion, Franklin County, Missouri, December 9, 1970 (NTSB/PAR-72/01);

Pipeline Accident Report--Mid America Pipeline System Liquefied Petroleum Gas Pipeline Rupture, West Odessa,

Texas, March 15, 1983 (NTSB/PAR-84/01); Pipeline Accident Report--Williams Pipe Line Company, Liquid

Pipeline Rupture and Fire, Mounds View, Minnesota, July 8, 1986 (NTSB/PAR-87/01); Railroad Accident Report--

Derailment of Southern Pacific Freight Train on May 12, 1989, and Subsequent Rupture of Calnev Petroleum

Pipeline on May 25, 1989, San Bernardino, California (NTSB/RAR-90/02); Pipeline Accident Report--Liquid

Propane Pipeline Rupture and Fire, Texas Eastern Products Pipeline Company, North Blenheim, New York, March

13, 1990 (NTSB/PAR-91/01).

3

NTSB/PAR-87/01.
64 APPENDIX C

the release of product from the pipeline. In its 1991 report on the pipeline accident at North

Blenheim, New York,4 the Safety Board recommended that RSPA:

P-91-1

Define the operating parameters that must be monitored by pipeline operators to

detect abnormal operations and establish performance standards that must be met

to detect and locate leaks.

In response to this recommendation, RSPA committed to undertake a 2-year study to

determine whether SCADA systems and SCADA-based leak detection systems should be

required on gas and hazardous liquid pipelines.

In May 1992, RSPA contracted with the Volpe National Transportation Systems Center

(Volpe) to analyze SCADA systems and computer-generated leak detection systems to determine

(1) the feasibility and costs of requiring operators to use SCADA systems with a leak detection

subsystem and, (2) the existing impediments or needed improvements to minimize the time that

SCADA systems require to detect and locate leaks. The study was also to recommend resolutions

for identified difficulties. On August 31, 1992, the Safety Board classified Safety

Recommendation P-91-1 “Open-Acceptable Response.”

The Volpe study was completed in September 1995,5 and it indicated that a SCADA or

leak detection system “can be found to suit most pipeline environments.” It further stated,

Field instruments coupled with a telephone line and a personal computer can, in

most cases, provide the pipeline operator with reliable status information on the

pipeline. Implementation of a system, including dispatcher training, can allow

almost any pipeline operator to conduct effective rupture detection.

Safety Recommendation P-95-1

Between 1987 and 1992, RSPA conducted research studies and published several

proposed rules in response to Safety Board recommendations and Congressional proposals. The

Pipeline Safety Act of 1992 (Public Law 102-508) mandated that RSPA complete a study on

emergency flow restricting devices for hazardous liquid pipelines by October 1994 and issue a

final rule by October 1996. Under this act, RSPA's study was to assess the effectiveness of

emergency flow restricting devices (including remote control valves and check valves) and

equipment used to detect and locate pipeline ruptures and minimize product releases from

pipeline facilities.

 

4

NTSB/PAR-91/01.

5

Sherry Smith Borener, et al. Remote Control Spill Reduction Technology: A Survey and Analysis of

Applications for Liquid Pipeline Systems, U.S. Department of Transportation (Cambridge, Massachusetts: Volpe

National Transportation Systems Center, 1995).
APPENDIX C 65

On January 19, 1994, RSPA issued an advance notice of proposed rulemaking (Docket

No. PS-133, 59 FR 2802) soliciting comments on a series of questions on emergency flow

restricting devices and leak detection systems to assist it in developing requirements. RSPA

stated that responses received by April 19, 1994, would be used in developing a rulemaking

proposal. RSPA further stated that it had been concerned for some time with rapid leak detection

on hazardous liquid pipelines and the optimum placement of emergency flow restricting devices.

In the advance notice of proposed rulemaking, RSPA reviewed its actions on this issue since

1978, including its March 1991 publication of the Emergency Flow Restricting Devices Study.

RSPA further indicated that it was soliciting information and data by posing a series of questions,

rather than conducting a traditional research survey of a selected number of respondents, so that

it could obtain a broader base of data and accelerate the regulatory process.

In the 1995 Edison report,6 the Safety Board stated its belief that RSPA's 1991

Emergency Flow Restricting Devices Study was seriously flawed and caused the Congress, in

Public Law 102-508, to inappropriately limit considerations of emergency flow restricting

devices to hazardous liquid pipelines. The Safety Board also noted that its review of RSPA's

1991 study and the Edison accident clearly demonstrated that RSPA needed to reconsider its

actions on using remote control valves and automatic control valves as main line valves to

promptly limit the flow of natural gas to failed pipeline segments, especially in urban or

environmentally sensitive areas. To that end, the Safety Board classified Safety Recommendation

P-87-22 “Closed-Unacceptable Action/Superseded” and recommended that RSPA:

P-95-1

Expedite requirements for installing automatic- or remote-operated mainline

valves on high pressure pipelines in urban and environmentally sensitive areas to

provide for rapid shutdown of failed pipeline segments.

In a May 12, 1995, response to Safety Recommendation P-95-1, RSPA stated that it

intended to publish a notice of proposed rulemaking in fall 1995 that would specify those

circumstances under which operators of hazardous liquid pipelines would be required to use

emergency flow restricting devices. The Safety Board classified the recommendation “OpenAcceptable Response.” The Safety Board reiterated Safety Recommendation P-95-1 to RSPA in

early 1996.7

 

6

NTSB/PAR-95/01.

7

Special Investigation Report--Evaluation of Accident Data and Federal Oversight of Petroleum Product

Pipelines (NTSB/SIR-96/02).
66

API American Petroleum Institute

CFR Code of Federal Regulations

EPA Environmental Protection Agency

FEMA Federal Emergency Management Administration

FOSC Federal On-Scene Coordinator

LPG Liquefied Petroleum Gas

NRS National Response System

NRT National Response Team

OPA 90 Oil Pollution Act of 1990

OSC On-Scene Coordinator

OPS Office of Pipeline Safety/ Research and Special Programs

Administration

RSPA Research and Special Programs Administration, U.S. Department

of Transportation

RRT Regional Response Team

SCADA Supervisory Control and Data Acquisition

TGLO Texas General Land Office

USGS U.S. Geological Survey

GLOSSARY OF ACRONYMS