NTSB/PAB-07/02 

E PLURIBUS UNUM

NATIONAL TRA SPORTATIO

N

B OARD

SAFE T Y

N

National Transportation Safety Board 

Washington, D.C. 20594 

Pipeline Accident Brief

Accident No.: DCA05-MP001 

Type of System: Hazardous liquid 

Accident Type: Pipeline rupture and leak with vapor cloud 

Location: 6 miles west of Kingman, Kansas 

Date: October 27, 2004 

Time: 11:15 a.m. central daylight time 

Owner: Magellan Midstream Partners, L.P. 

Facility: Magellan Ammonia Pipeline/Enid Lateral 

Operator: Enterprise Products Operating L.P. 

Fatalities/Injuries: None 

Damage/Clean-up Cost: $680,715 

Material Released: Anhydrous ammonia 

Quantity Released: 4,858 barrels (204,000 gallons) 

Pipeline Pressure: 981 psig 

Component Affected: Pipe 

The Accident 

About 11:15 a.m. central daylight time1 on October 27, 2004, an 8-inch-diameter pipeline 

owned by Magellan Midstream Partners, L.P., (Magellan) and operated by Enterprise Products 

Operating L.P. (Enterprise) ruptured near Kingman, Kansas, and released approximately 4,858 

barrels (204,000 gallons) of anhydrous ammonia.2 Nobody was killed or injured due to the 

release. The anhydrous ammonia leaked into a creek and killed more than 25,000 fish including 

some from threatened species. The cost of the accident was $680,715, including $459,415 for 

environmental remediation. 

Accident Narrative 

On October 27, 2004, a pipeline controller in the Enterprise control center in Houston, 

Texas, was operating an 8-inch-diameter anhydrous ammonia pipeline owned by Magellan. The 

 1

 All times in this brief are central daylight time. 

2

 Anhydrous ammonia is classified in 49 Code of Federal Regulations (CFR) Part 195 as a highly volatile 

liquid. Anhydrous ammonia is transported as a liquefied gas in a pipeline and, when released, will immediately 

return to a gaseous state and rapidly expand. It is a hazardous liquid that is highly corrosive and toxic, and its vapors 

also are extremely irritating and corrosive. Anhydrous ammonia may be fatal if inhaled, ingested, or absorbed 

through the skin. 
2 NTSB/PAB-07/02 

ammonia pipeline runs from Borger, Texas, to Mankato, Minnesota. The Enid Lateral segment of 

the ammonia pipeline originates at the Koch Enid production facility in Enid, Oklahoma, runs 

through Harper Station (Kansas), and ties in to the mainline at Partridge Station. (See figure 1.) 

Figure 1. Map of Magellan ammonia pipeline showing rupture location on 8-inch Enid Lateral. 

When the pipeline controller returned to his console after getting his lunch, he noticed 

two rate-of-change alarms3

 that had been displayed on the alarm screen for the ammonia pipeline 

less than a minute earlier. The supervisory control and data acquisition (SCADA) event log 

indicated negative rate-of-change alarms for suction pressure at both Harper Station (at 

11:15:43 a.m.) and Conway Station (at 11:16:27 a.m.). 

About 11:18 a.m., an off-duty volunteer firefighter traveling on Highway 54 called 911 to 

report a huge vapor cloud on the north side of the highway that he believed was a pipeline 

release. (See figure 2.) The 911 center in Kingman County, Kansas, is in the county sheriff’s 

office. The Kingman County Fire Department was dispatched to the rupture site about 11:20 a.m. 

Because the rupture site was in an agricultural area that is home to several threatened and 

endangered species of fish and wildlife, it was designated by Enterprise as a high-consequence 

area.

4

 The vapor cloud moved northwest from the rupture and affected vegetation in an area 

 3

 A rate-of-change alarm is displayed when a change in pressure or flow exceeds an identified value. 4 A high-consequence area is defined in the Federal pipeline safety regulations as a commercially navigable 

waterway, high- or concentrated-population area, or unusually sensitive area that might be affected by an accident 
3 NTSB/PAB-07/02 

approximately 1/2 mile wide and 1 1/2 miles long. The release entered an unnamed tributary 

stream that was approximately 36 feet from the pipeline failure. The tributary stream enters 

Smoots Creek approximately 1 1/2 miles downstream of the rupture. 

Figure 2. Ammonia vapor cloud moving northwest from pipeline rupture. 

Between 11:19:34 a.m. and 11:19:55 a.m., four more alarms from Conway Station were 

displayed at the controller’s console, including low suction pressure,5

 low-low suction pressure,6

an uncommanded pump shutdown, and a rate-of-change alarm that was followed by a low 

suction pressure alarm from Partridge Station. Then two additional rate-of-change alarms were 

displayed, at 11:20:31 a.m. from Conway and at 11:21:26 a.m. from Partridge. In the 13 seconds 

between 11:27:33 a.m. and 11:27:46 a.m., five additional alarms were displayed, including low 

flow and the uncommanded shutdown of Abilene Station. At 11:27:50 a.m., the controller 

increased the flow rate set point on the flow control valve at Enid Station from approximately 

450 barrels per hour to 550 barrels per hour. At 11:27:51 a.m., a second low-low suction pressure 

alarm from Conway Station was displayed. 

 involving the pipeline. Title 49 CFR 195.450 contains the criteria for designating an area a high-consequence area 

for hazardous liquid pipelines. 5

 A low suction pressure alarm for a pump at a pump station along a pipeline can be set at a value selected by 

the pipeline controller (higher than low-low) as a warning of an abnormal condition or a possible pipeline leak. 6

 A low-low suction pressure alarm is a high level (red) alarm in the SCADA system that is considered an 

immediate response alarm. 
4 NTSB/PAB-07/02 

The controller knew that Enterprise maintenance personnel were working at Conway 

Station. In a telephone call to Conway Station at 11:28 a.m., he asked why the pump had shut 

down. By 11:30 a.m., Conway Station personnel had told the controller that they had not caused 

the pump to shut down. At 11:34:05 a.m., the SCADA system displayed a low suction pressure 

rate-of-change alarm downstream at Linn Station followed by a low-low suction pressure alarm 

at 11:34:30 a.m. 

On the basis of the 911 call at 11:18 a.m., the Kingman County sheriff’s office had 

responded to the site and started telephoning residents in 35 houses; four families were 

evacuated; no residents were home at 28 houses. By about 11:40 a.m., the sheriff’s office and the 

fire department had blocked roads that could be affected by the vapor cloud. 

About 11:48 a.m., the dispatcher called Enterprise’s control room to report the release 

that had been reported to 911. Another controller, who was sitting at the console adjacent to the 

ammonia pipeline controller’s console, answered the phone and handled the call. The ammonia 

pipeline controller told investigators that when he heard the telephone ring he immediately 

realized that there was a leak on the ammonia pipeline. He started to shut down the pipeline at 

11:48:20 a.m. by remotely stopping the pumps at Enid, Verdigris, Wellsford, and Borger 

Stations,7

 in that order. The last one, Borger, was shut down at 11:52:57 a.m. From his console, 

he remotely closed the block valve at Harper Station, and at 11:54:24 a.m., he closed the block 

valve at Partridge Station. These closures isolated a 50.85-mile-long segment of pipeline in 

which the rupture had occurred. At 12:08 p.m., he dispatched Enterprise personnel to close 

manual block valves at milepost markers 21 and 32 to further isolate the leaking pipeline 

segment. At 12:56 p.m. and 1:09 p.m., respectively, those valves were closed. These valve 

closures reduced the isolated segment of pipeline in which the rupture had occurred to 11 miles. 

Controller’s Actions 

The controller told investigators after the rupture that he had been viewing the tabular 

screen and knew the alarms indicated a potential problem with the pipeline. To evaluate the 

alarms from the pipeline, he used the tabular data screen in the SCADA system. This screen 

listed the pipeline facilities and displayed current data for the entire pipeline system, including 

pump station suction and discharge pressures, pump status, tank levels, flow rates, valve status, 

and set points. Alarm information that was displayed on the alarm screen also flashed and 

changed color on the tabular screen. The controller’s assessment was that he was delivering more 

ammonia from the pipeline than was being added to the pipeline and that this condition had 

decreased the pressure. This assessment led him to increase the flow rate at 11:27:50. He later 

said that he thought that within 10 or 15 minutes the pressure readings would increase. 

Therefore, he planned to wait for a few minutes, and, if the pressure readings for the pipeline did 

not increase, he would reevaluate and delve deeper into the situation. 

The SCADA system can display a trend screen that shows pressure and flow trend data 

graphically, and the controller told investigators that looking at a trend screen would have been 

helpful in the analytical stage. However, he did not use trend screens in evaluating the incoming 

 7 The controller stopped pumps at these stations because at the time he did not know whether the leak was on 

the mainline from Borger, on the Enid Lateral, or on the mainline downstream of Partridge Station.
5 NTSB/PAB-07/02 

data. He said that his training did not specify which screens to use to analyze and evaluate the 

SCADA data. He stated that from 11:15 a.m. to 11:48 a.m. an unusually high number of alarms 

and status events were displayed for the pipeline.8 During this 33-minute period, the SCADA 

system displayed 119 alarms and status events. The controller said that he felt that he had full 

authority to shut down the pipeline and that he did not believe there would be consequences from 

Enterprise if he shut down a pipeline and it was subsequently determined that there was no leak. 

The operations control supervisor stated in an interview that he expects pipeline 

controllers to use the tabular screen as the main screen, or “front page.” He said that controllers 

are taught to access and display a trend screen, or “second page,” to further investigate an alarm 

and the condition that caused it. The supervisor said that pressure and flow changes are the 

primary parameters used to detect leaks. He stated that at the time of the accident, rate-of-change 

alarms were displayed in blue and immediate response alarms were displayed in red. He 

indicated that he believes the controller had enough information between 11:20 a.m. and 

11:25 a.m. to lead him to shut down the ammonia pipeline. 

Telephonic Reporting of Release 

The Federal pipeline safety regulation for telephonic reporting of hazardous liquid 

pipeline accidents (49 CFR 195.52) requires telephonic notification to the National Response 

Center when the pipeline accident has caused a death or injury requiring hospitalization; has 

resulted in either an unintentional fire or explosion; has caused estimated property damage 

(including cleanup and recovery costs and the value of the lost product) exceeding $50,000; has 

resulted in pollution of streams, rivers, reservoirs, or other similar bodies of water; or, in the 

judgment of the operator, is significant even though the accident does not meet the other 

specified criteria. The regulation further requires an operator to include in the telephonic 

notification not only the basic details, such as the identity of the operator, the location and time 

of the accident, and the number of fatalities and injuries, but also “all other significant facts 

known by the operator that are relevant to the cause of the failure or extent of the damages.” 

On August 30, 2002, the Pipeline and Hazardous Materials Safety Administration 

(PHMSA)9

 published a Federal Register notice issuing a safety advisory bulletin10 to operators 

of gas and hazardous liquid pipelines and liquefied natural gas facilities about telephonic 

reporting. In the notice, PHMSA stated that it is critical for an operator to provide accurate 

information on the extent of the incident and that PHMSA expects an operator to provide 

significant updated information during the emergency response phase. The bulletin stated that if 

 8

 The pipeline systems that this controller operated experienced an increase from an average of 137 alarms in an 

hour to 286 alarms between 11:00 a.m. and noon. 9

 In a U.S. Department of Transportation reorganization, the Research and Special Programs Administration 

(RSPA) ceased operations on February 20, 2005. RSPA’s Office of Pipeline Safety programs moved to the new 

Pipeline and Hazardous Materials Safety Administration. All references to predecessor agencies are designated as 

PHMSA in this report. 10 The August 30, 2002, advisory bulletin was issued in response to the Safety Board’s Safety Recommendation 

P-02-02 (See Rupture of Piney Point Oil Pipeline and Release of Fuel Oil Near Chalk Point, Maryland, April 7, 

2000, Pipeline Accident Report, NTSB/PAR-02/01 [Washington, DC: NTSB, 2002.]). The Safety Board 

issued Safety Recommendation P-02-02 to PHMSA to require pipeline owners and operators to provide follow-up 

telephone updates to the National Response Center when they discover that the information they initially reported 

contains significant errors or when they identify significant new information directly related to the reporting criteria. 
6 NTSB/PAB-07/02 

additional information leads to a significant change in the estimated quantity of product released, 

the estimated number of fatalities and injuries, the extent of environmental damage, or the extent 

of property damage, the operator should make an additional telephonic report to the National 

Response Center. PHMSA considered “significant change” to include an increase or decrease of 

previously reported fatalities or injuries and a revised estimate of product released or property 

damage that is at least 10 times greater than the previous estimates. Regarding release estimates, 

the bulletin also stated that if the operator does not provide an estimate, the National Response 

Center will record a default estimate of 1,000 barrels (42,000 gallons). In February 2005, 

PHMSA informed the Safety Board that rather than the National Response Center entering the 

1,000-barrel default estimate, PHMSA will consider telephonic reports made without a spill 

estimate to have the same priority as reports with spill estimates of 1,000 barrels. The National 

Response Center confirmed in March 2005 that it will not enter the 1,000-barrel default value if 

the operator does not provide a spill estimate. 

The U.S. Environmental Protection Agency (EPA) requires that an anhydrous ammonia 

release equal to or greater than 100 pounds of ammonia (equivalent to approximately 20 gallons) 

be reported within 15 minutes of discovery. 

About 12:15 p.m. on October 27, the controller notified Enterprise’s central region 

operations manager of the release. Because field personnel were too busy to make the call, the 

manager called the controller back to tell him to report the accident to Enterprise’s accident 

reporting contractor.11 In the controller’s phone conversation with the accident reporting 

contractor at 12:23 p.m., the controller reported that a large quantity of anhydrous ammonia had 

been released and had formed an ammonia vapor cloud, but he stated that he did not know the 

amount of anhydrous ammonia that had been released. When the contractor responded that 

without an estimate of a specific quantity the National Response Center would enter a 1,000-

barrel estimate in its incident report, the controller told the contractor that a 1,000-barrel estimate 

would be fine. The contractor asked whether the amount released was at least 20 gallons.12 The 

controller confirmed that it was. Later, when the contractor asked for a damage estimate, the 

controller said that he had no idea. When the contractor asked him to choose one of several 

ranges of dollar values from less than $5,000 to exceeding $50,000 as an estimate of the damage 

caused by the release, the controller chose the less-than-$5,000 range. 

At 1:08 p.m., Enterprise’s reporting contractor reported the release to the National 

Response Center. The National Response Center report of the incident stated that the release was 

a vapor cloud over the pipeline due to unknown causes. The contractor reported the estimated 

quantity of the release as 20 gallons and told the National Response Center that Enterprise would 

calculate the amount released when it got a chance. An updated release amount was not reported 

to the National Response Center. 

A PHMSA inspector arrived on site at 7:00 a.m. the next morning, October 28. About 

8:00 a.m., the inspector learned from Enterprise operations employees that at that time, the 

 11 3E Company was Enterprise’s accident reporting contractor. 12 When reporting an anhydrous ammonia release of unknown volume, Enterprise reported small releases as at 

least 20 gallons to indicate that a reportable quantity had been released. 
7 NTSB/PAB-07/02 

estimated amount of anhydrous ammonia released was at least 3,000 barrels (126,000 gallons).13

This estimate of the release volume was based on an approximation of the amount of product 

normally contained in the pipeline between the two valves that had been manually closed. The 

final estimate of the release volume was later calculated by Enterprise to be 4,858 barrels 

(204,000 gallons). 

The EPA had received the initial report of a 20-gallon release from the National Response 

Center on October 27 about 2:42 p.m. EPA representatives indicated that the EPA had not 

responded to the accident site because the reported release volume was so small. The next 

morning, during a review of the previous day’s National Response Center reports, the EPA duty 

officer noticed that a vapor cloud had been reported, and he called Enterprise at 9:30 a.m. to ask 

why a vapor cloud was associated with a 20-gallon release. The Enterprise representative told the 

duty officer that the amount of ammonia released was much greater than the reported quantity, 

and he estimated the release to be at least 2,000 barrels (84,000 gallons). Following the phone 

call, two EPA on-scene coordinators were dispatched to the site to investigate. 

The EPA on-scene coordinators arrived at the site at 5:00 p.m. and discussed with Apex 

Environmental, Inc. (Apex), Magellan’s environmental contractor, the need for sparging14 at 

Smoots Creek to lower the pH levels in the creek. Apex began sparging about 9:00 p.m. Sparging 

continued for several weeks following the rupture. Later, the Kansas Department of Health and 

Environment authorized the spreading of 3,500 cubic yards of nitrogen-rich soil, which had been 

excavated from the rupture location, over a cultivated area to fertilize the ground. 

Pipe Specification and Operating Conditions 

The 8.625-inch nominal outside diameter carbon steel pipe at the rupture location was 

specified as American Petroleum Institute Specification 5LX, grade X46, 0.156-inch nominal 

wall thickness with an electric resistance welded seam. After Mid-America Pipeline Company 

completed construction, the pipeline segment at the rupture location was hydrotested to 1,580 

pounds per square inch gauge (psig) on December 11, 1973. At the rupture location, the pipeline 

had a maximum operating pressure of 1,198 psig. The calculated pipeline operating pressure at 

the rupture site at the time of the release was 981 psig, and records of the operating conditions 

immediately before the accident do not indicate that the maximum operating pressure had been 

exceeded. The exterior surface of the pipe was coated with tar tape primer and spirally wrapped 

with a continuous overlap of tar tape. At the location of the rupture, the pipe was 4 feet 5 inches 

underground and was cathodically protected to control external corrosion. 

Materials Laboratory Examination and Tests 

The pipe segment that ruptured was removed and sent to the Safety Board’s Materials 

Laboratory for examination and testing. The segment had four external gouges. The 

 13 The 3,000-barrel estimate was a rough field estimate. With the postaccident implementation of new reporting 

procedures, Enterprise would have been able to provide a more refined estimate of 3,600 barrels. See “Enterprise’s 

Postaccident Actions – Telephonic Report Procedure” in this report. 14 Sparging is the process of injecting compressed air into a waterway causing volatile pollutants such as 

ammonia to vaporize into the air. 
8 NTSB/PAB-07/02 

approximately 11.7-inch-long rupture occurred at one of the gouges. (See figure 3.) Over most of 

the rupture length, the gouge penetrated 0.019 inch (approximately 12.2 percent of the pipe wall 

thickness) into the pipe wall. Within the gouge, shear cracks penetrated the metal. From the base 

of the shear crack that led to the rupture, a fatigue crack propagated toward the interior of the 

pipe. The fatigue crack extended approximately 0.080 inch below the shear crack with no 

external corrosion that resulted in a loss of material thickness. A detailed examination showed 

that the fatigue region had five bands, each with a different shade of gray, consistent with crack 

arrest marks. The area below the fatigue crack had a shear lip created during the sudden and final 

rupture of the pipe. 

Figure 3. Ruptured 8-inch Enid Lateral anhydrous ammonia pipeline showing four gouges 

and rupture. 

The results of chemical analysis, dimensional measurements, and tensile strength testing 

were in accordance with the American Petroleum Institute specification for 5LX-X46 pipe. An 

examination of a cross section of the gouge at the fracture origin area showed that metal of a 

different composition had transferred to the wall of the pipe. Elemental analysis of a metal tooth 

from the backhoe bucket owned by the property owner did not provide a unique signature when 

compared to the transferred metal in the gouges. The examination of the cross section revealed 

no manufacturing defects (such as laminations, voids, or porosity) in the pipe material. The 

examination of the inside surface of the pipe showed no corrosion degradation or additional 

cracking. 
9 NTSB/PAB-07/02 

Construction and Excavation Activity 

To identify any construction and excavation activities in the area of the rupture, 

investigators examined all available maintenance records, aerial patrol records, and aerial 

photographs that covered the period from construction of the pipeline in 1973 to the present, but 

identified no excavation activities immediately over the rupture site. The 1973 construction 

specifications for the pipeline required that any coating damage be repaired before backfilling 

the pipeline. The trench for the pipeline was excavated with a trenching machine, and backfilling 

was done with an auger-type backfill machine or a bulldozer. According to the construction 

specifications, where these machines could not be used to backfill, the site inspector would 

approve the method of backfilling before it began. The pipeline tie-in inspector for the Enid 

Lateral construction did not recall what occurred at the accident location, and no construction 

inspection records exist. He indicated that a backhoe was not likely to be used in the pipe rupture 

area during construction because the unnamed stream was not a major stream crossing that 

required the use of a backhoe. 

According to the current owner (since 1989), the area where the pipe ruptured had not 

been cultivated. Between 1990 and 1992, he had used his backhoe to grade the unnamed stream’s 

banks to create a vehicle ramp that was approximately 100 feet north of the pipe rupture. He told 

investigators that no excavation had been performed at the location of the rupture. 

The four gouges located longitudinally along the top half of the pipeline are consistent in 

shape and location with the type of mechanical damage caused by excavation equipment such as 

a backhoe. Since a unique metallurgical signature was not found in the analysis of metal deposits 

within the gouges, the Safety Board could not determine whether the landowner’s backhoe 

bucket was the source of the deposits. The pipeline tie-in inspector stated that on this pipeline 

construction project a backhoe typically would not have been used for crossing a stream of this 

size. However, the Safety Board could not rule out damage to the pipeline during construction. 

Available information and records covering the time from when the pipeline was constructed in 

1973 to the present did not indicate any excavation activity by the pipeline operator near the 

location of the rupture. However, the possibility of unknown excavation activities could not be 

eliminated. The Safety Board concludes that heavy equipment damage to the pipeline during 

construction or subsequent excavation activity created a pipe gouge that initiated metal fatigue 

cracking and led to the eventual rupture of the pipeline. 

Enterprise’s Policies and Procedures 

Procedures for Abnormal Operating Conditions 

Enterprise’s procedure manual defined an abnormal operating condition as “any condition 

that may cause, create, or contribute to a situation which exceeds the design or normal operating 

parameters of the pipeline.” The manual instructed controllers to treat an unexplained variation 

in pressure or flow as an abnormal operating condition. It also instructed controllers to continue 

to monitor pipeline operations and follow specific steps that include checking “with others 

involved with the operations to determine the cause of the variation” and to be “especially 

attentive for any sign that an emergency condition may follow.” 
10 NTSB/PAB-07/02 

To investigate a variation in pressure or flow, control room personnel were to notify oncall field personnel or supervisors; review flow data; check instantaneous line balance by 

comparing simultaneous meter readings at point of origin, destination, and intermediate 

locations; and contact customers for possible explanation of the pressure or flow variation. If a 

logical reason for a variation could not be determined, the control room operator was to shut 

down the pipeline and monitor pressure. 

Enterprise’s draft Natural Gas Liquids Pipeline Control Operations and Maintenance 

Training Manual15 also contained information regarding the monitoring and control of anhydrous 

ammonia pipelines. The manual noted that rate-of-change alarms usually occur at the onset of an 

abnormal condition or a pipeline leak. Controllers were instructed to investigate all rate-ofchange and parameter alarms immediately, and they were advised that if an alarm resulted from a 

known cause, the pipeline system in the area of the alarm would stabilize in a short period of 

time. If the cause of a rate-of-change or parameter alarm was not readily apparent and the alarm 

was accompanied by one or more indications of a product release, or the pressure or flow failed 

to stabilize, controllers were instructed to shut down and block in the line segment. If a sudden 

unexplained decrease in operating pressure without a corresponding increase in flow rate was 

observed, the controller was instructed to shut down and block in the line segment for 30 minutes 

and then observe the line segment for any sign of a leak. 

Controllers were instructed during training to use trend screens to monitor the pipeline 

pressure and, if the pressure continued to fall or did not stabilize, to perform an emergency 

shutdown. This procedure was included in the training manual. The alarm response matrix in the 

training manual described the SCADA alarm color scheme and listed a rate-of-change alarm as a 

high-level alarm. The matrix also indicated that rate-of-change alarms for pressure and flow 

(high-level, immediate attention) were shown in red on the SCADA screen and that these alarms 

indicated a possible line break. 

Enterprise defined an emergency as a “significant change from steady state operating 

conditions” that could include an “accidental release of hazardous vapors or liquids from a 

pipeline causing a hazardous situation.” When a controller determined that an emergency 

existed, the manual required him to shut down pumps that feed the affected facility and close the 

nearest upstream remotely operated block valve. Pump stations downstream of the facility were 

to remain operating until they shut down on low flow, and then the nearest remotely operated 

downstream block valve was to be closed. The controller also was to notify identified personnel 

within the company as well as customers and emergency response agencies. 

Controller’s SCADA Training and Qualification 

The controller who operated the pipeline during the accident started at Enterprise as an 

area operator and was promoted to operations supervisor in the field in 1996. He took controller 

training, consisting of classroom study of company procedures and manuals, operations, SCADA 

information retrieval, and site-specific information. He functioned as a pipeline scheduler from 

1997 until 2003. In February 2003, he began on-the-job controller training. Enterprise assessed 

the effectiveness of his training by testing his knowledge and observing his actions in operating 

 15 Enterprise used the draft manual for training controllers. 
11 NTSB/PAB-07/02 

pipelines. He completed refresher training on May 21, 2003. His training included the study of 

procedural and training manuals for the ammonia pipeline. The study material explained how to 

respond to abnormal conditions and use trend screens with graphical displays. He successfully 

completed written examinations covering this material on September 13, 2003, and was qualified 

by Enterprise to operate the pipeline. Enterprise did not have a pipeline simulator for controller 

training but did use noncomputerized simulations in postaccident controller training sessions in 

2001. The review of noncomputerized simulations of accidents is not a requirement listed in 

Enterprise’s training program. 

Telephonic Report Policy 

Enterprise’s Procedural Manual for Operations, Maintenance, and Emergencies stated 

that operations personnel are accountable for telephoning a report of an accident to the National 

Response Center. The procedure repeats the requirements for telephonic reporting in 

49 CFR 195.52. 

Enterprise’s draft Natural Gas Liquids Pipeline Control Operations and Maintenance 

Training Manual stated that its reporting contractor would do all reporting of releases and 

accidents to Federal, State, and local authorities for Magellan’s ammonia pipeline, and that the 

Enterprise field supervisor was responsible for reporting releases and accidents to the contractor. 

Enterprise did not have a policy about who was responsible for deciding whether to send an 

additional report to the National Response Center in order to comply with the August 30, 2002, 

PHMSA advisory bulletin urging operators to update a telephonic report with significant new 

information, including a change in the estimate of the release volume. 

Before the accident, Enterprise’s central region operations manager had supplemental 

reporting guidelines drafted for training field personnel. The operations manager’s objective was 

to improve timely reporting of accidents in his region using the reporting contractor. The 

guidelines identified reporting responsibilities and included a list of questions that the contractor 

would ask. However, the guidelines did not address how to estimate the quantity of product 

released or how to make a dollar estimate of damages. The draft guidelines were used in a 

training session conducted during a quarterly safety meeting in the quarter ending 

March 31, 2003. The draft guidelines, Release Reporting Roles and Responsibilities, dated 

June 3, 2003, was the last update of the draft. 

Integrity Management Program for Ammonia Pipeline 

Williams Companies, Inc. (Williams), the previous owner and operator of the pipeline, 

prepared the initial integrity management program for the ammonia pipeline. It used a relative 

risk assessment model that considered the following factors: third-party damage, corrosion, 

incorrect operation, design, and leak impact. It ranked various pipeline segments according to 

their risk with respect to each other. Using this model, a lower score indicated higher risk, and a 

higher score indicated lower risk. The risk scores were used with other input to prioritize 

scheduling of baseline assessments of pipeline segments. Pipe segments with risk scores of 0 to 

35, 36 to 66, and 67 and above were considered high, medium, and low risk, respectively. When 

the baseline assessment plan was developed, the model assigned a risk score of 69 (low risk) to 
12 NTSB/PAB-07/02 

the segment on the Enid Lateral that ruptured in this accident. This Enid Lateral segment was 

scheduled for a baseline assessment in 2006. 

In February 2003, Enterprise became the operator for the pipeline under contract to a 

subsidiary of Williams. Enterprise has been responsible for the integrity management program 

for the pipeline since that time. Williams subsequently sold the pipeline to Magellan, and 

Enterprise continued as the operator. The original integrity management program remained in 

effect until 2004 when Enterprise finished developing its own integrity management program, 

which was the program in effect at the time of the accident. The risk model in the Enterprise 

program was the same as the one used by Williams, and the risk score for the pipeline segment 

that contained the rupture had not been revised. 

PHMSA’s integrity management regulations list risk factors that must be considered in 

prioritizing the scheduling of baseline assessments. A pipeline segment’s leak history is 

specifically included in the list of risk factors. Although Enterprise had leak history data for the 

accident pipeline segment, Enterprise did not have complete instructions for calculating the leak 

history risk factor in its integrity management program. As a result, leak history was not used in 

calculating the relative risk scores, nor was it otherwise considered to classify pipe segments as 

high, medium, or low risk for the baseline assessment before the Kingman accident. 

Federal Integrity Management Inspections 

In September and October 2003, PHMSA inspected the Enterprise integrity management 

program for the anhydrous ammonia pipeline, including the Enid Lateral pipeline segment. The 

inspection revealed some deficiencies that were noted on PHMSA’s Integrity Management 

Inspection Form and Inspection Summary Report. PHMSA identified several compliance issues 

and issued a Notice of Amendment to Enterprise on April 22, 2004, to correct deficiencies in its 

integrity management program. One of the compliance issues pertained to risk factors used in 

prioritizing the baseline assessment schedule. PHMSA noted that the following risk factors 

required by regulation were not addressed by Enterprise: seam type, results of previous 

assessments, defect type and size that the assessment method can detect, and defect growth rate. 

PHMSA also asked that more detail be included in documentation describing how these risk 

factors will be integrated into the decision-making process for prioritizing the baseline 

assessment schedule. However, PHMSA did not identify that pipeline leak history also was not 

used in Enterprise’s calculation of relative risk scores. 

In letters dated May 21 and July 28, 2004, Enterprise responded to the PHMSA Notice of 

Amendment with revised procedures to integrate the risk factors that had been identified in the 

notice as deficient. However, Enterprise did not update its baseline assessment for prioritizing 

the scheduling of pipeline segments using the revised procedures. Enterprise also did not modify 

or update the procedures for leak history in its revised procedures. After reviewing Enterprise’s 

May 21 and July 8 responses, PHMSA closed the Notice of Amendment on October 18, 2004. 

PHMSA did not require Enterprise to update the baseline assessment using the revised risk factor 

procedures. 
13 NTSB/PAB-07/02 

Enterprise’s Postaccident Actions 

SCADA Alarms Review 

After the accident, Enterprise established a program to review the rate-of-change alarms 

systemwide because the company believed that the alarms were not as effective as they should 

be. The goal of the review was to make the alarms more meaningful by significantly reducing the 

number of alarms that could distract controllers from more critical alarms. Before the review, 

controllers received about 10,000 SCADA alarms/events systemwide on an average day. After 

the review, the average number of alarms per day dropped below 4,000. After determining that 

controllers would not be overwhelmed by reclassifying rate-of-change alarms to a higher 

priority, Enterprise changed the alarm from medium level (blue) to high level (red) to emphasize 

the need for immediate attention to those alarms. 

Controller Training 

Enterprise supervisors reviewed the circumstances of the accident with the controller and 

identified deficiencies in his response. No disciplinary actions were taken against the controller. 

Enterprise conducted two training sessions for its entire staff of anhydrous ammonia and natural 

gas liquid pipeline controllers. In the training sessions, Enterprise used a noncomputerized 

simulation to analyze the ammonia pipeline accident. During this simulation, as each alarm came 

in, the associated trend screen was displayed. The SCADA tools available for analyzing 

incoming alarm data, including trend screens, were reviewed. Controllers were told that if they 

saw an abnormal condition that indicated a possible leak and they were unable to analyze the 

condition and determine the cause of the problem within approximately 5 minutes, the controller 

was to shut down and block in the pipeline. Enterprise has not made noncomputerized 

simulations a part of its recurrent training program. 

Telephonic Report Procedure 

Enterprise developed a new telephonic reporting procedure, dated January 20, 2006, for 

estimating the amount of product released and related damages based on pipeline physical 

characteristics and available operating data. When sufficient operating data are not available for 

anhydrous ammonia pipelines, the initial release amount to be reported will be the quantity of 

product contained between the valves closed on either side of the leak. The procedure also 

addresses a potential delay in telephonic reporting for releases that exceed the EPA reportable 

quantity. Specifically, to expedite the reporting to the National Response Center, Enterprise now 

requires the employee who reports the release to the reporting contractor to stay on the phone 

with the reporting contractor while the report is made. Enterprise also has designated company 

employees who will supply telephonic updates, as necessary, to the National Response Center. 

Integrity Management Program 

Since the accident, Enterprise has revised its risk assessment model to incorporate a 

pipeline leak history factor in its risk assessment calculation. It also has revised its baseline 

assessment of pipeline segments using all risk factors to schedule baseline assessments. 
14 NTSB/PAB-07/02 

Probable Cause 

The National Transportation Safety Board determines that the probable cause of the 

pipeline rupture near Kingman, Kansas, on October 27, 2004, was a pipe gouge created by heavy 

equipment damage to the pipeline during construction in 1973 or subsequent excavation activity 

at an unknown time that initiated metal fatigue cracking and led to the eventual rupture of the 

pipeline. Contributing to the severity of the accident was the pipeline controller’s failure to 

accurately evaluate available operating data and initiate a timely shutdown of the pipeline. 

Recommendations 

As a result of its investigation of the October 27, 2004, anhydrous ammonia pipeline 

accident, the National Transportation Safety Board makes the safety recommendations listed 

below. For more information about these recommendations, see the safety recommendation 

letters16 to the recipients. 

To the Pipeline and Hazardous Materials Safety Administration: 

Require in 49 Code of Federal Regulations 195.52 that a pipeline operator must 

have a procedure to calculate and provide a reasonable initial estimate of released 

product in the telephonic report to the National Response Center. (P-07-7) 

Require in 49 Code of Federal Regulations 195.52 that a pipeline operator must 

provide an additional telephonic report to the National Response Center if 

significant new information becomes available during the emergency response. 

(P-07-8) 

Require an operator to revise its pipeline risk assessment plan whenever it has 

failed to consider one or more risk factors that can affect pipeline integrity. 

(P-07-9) 

To Enterprise Products Operating L.P.: 

Provide initial and recurrent training for all controllers that includes simulator or 

noncomputerized simulations of abnormal operating conditions that indicate 

pipeline leaks. (P-07-10) 

 16 These letters are available on the National Transportation Safety Board’s web site. 
15 NTSB/PAB-07/02 

BY THE NATIONAL TRANSPORTATION SAFETY BOARD 

MARK V. ROSENKER 

Chairman 

DEBORAH A. P. HERSMAN

Member 

STEVEN R. CHEALANDER 

Member 

ROBERT L. SUMWALT 

Vice Chairman 

KATHRYN O’LEARY HIGGINS 

Member 

Adopted: June 14, 2007