Prudhoe Bay Oil Field Spillage Engineering Essay

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In state of Alaska the major revenue for the government is from production of oil. The Prudhoe Bay oil field was largest pipe line on Alaskan's North Slope and largest in both North America and United States was discovered in March 20, 1968, while the plant infrastructure completed and production began on June 20, 1977. It produces approximately 1.5 million barrels per day and is operated by BP (British petroleum exploration Alaska) company. Bp has strong presence in this area and is supported by state because of tax returns, which turns to be 80% of the unobstructed state revenues (Onlinepub, 2009)

General

A 34 inch diameter pipeline which is located next to the road near the Caribou Cross carries the oil between the two gatherings centres across western half of the Prudhoe field. Where oil is been treated to remove impurities and water and made ready for shipment through Trans-Alaskan pipeline system (TAPS). (Fineberg, 2006)

Fig1. Pipeline structure (Wordpress, 2009)

General causes for oil spill

Mechanical failure: It can occur either during construction, poor quality of materials, deterioration of pipe line due wear and tear.

Corrosion: It can occur internally or externally mainly due to lack of anticorrosion coating or any kind of chemical deposition e.g.: calcium

Operational errors: It can be either human error or system failure. This can be due to lack of maintenance

Third party activities: External source can damage pipelines either accidental or incidental (such as sabotage)

Natural hazards: pipelines are submerged and can be affected by river flowing, erosion, snow and rapid change in temperature.

But, on 5.45am 2nd march 2006 nation was affect with one of the largest oil spill in last three decades. The reason that led to the oil spill was near the gathering centre across caribou cross that had a sprung of leak. This was been undetected for 5 days. Moreover, estimated amount of oil spill figure was 267,000 US gallons initially. Later end it touched to 212,252 US gallons of oil spilled over 1.9 acres. The important factors for the occurrence of this event are

Corrosion detection system failed

leak detection system failed

Faulty alarms

Poor management and maintenance no PIG (pipeline investigation gauge) used. (Fineberg, 2006 )

The result can be seen below

Fig1. Oil Spill (Barringer, 2006)

Catastrophic failure

At 5.45am 2nd march 2006 a worker driving across the Prudhoe Bay oil field smelled a strong odour of petroleum, which was been estimated leakage from last five or more days prior to the leak which eventually turned out to be the largest oil spill so far. The leakage was from a 34 inch diameter pipeline across road that carried the oil from gathering centre 1(G1) to gathering centre 2(G2) was eventually reported as there was ¼ inch of hole in pipeline. When pipeline dips into the culvert and passes over the caribou cross this is almost covered with snow. The main reason for disaster was company monitoring program for corrosion and pipeline leakage detection system failed.

This most devastated failure in oil history can be further described with the help of following analysis.

Fault tree analysis

Event tree

Cause and consequences

FMEA (Fineberg, 2006 ),(Mms,2010)

Fault tree

OIL Spill

Field pipeline leakage system failed

Corrosion monitoring system

Corrosion

Poor management and maintenance

No pigging since 7 years

Cost cutting

No regular inspection

Old pipeline

No turbine replacement

Inadequate system

Alarms

Old System

Sensor

Ultrasonic sensor

Magnetic sensor

Corrosion

As infrastructure completion of Alaskan pipeline system and production began on was June 20, 1977, which is relatively old and none of the pipes have been replaced before the event occurred. Old pipeline was usually made of steel with the inner diameter of 10 to 120cm and this pipeline was buried under the ground with the typical depth of 1 to 2 meters (3 to 6 feet). The oil is kept in motion with the help of pumps that are along pipeline. The usual speed of flow is about 1 to 6 meters per second. The crude oil contains certain amount of wax and calcium. While in cold climate wax builds up occurs in pipes and calcium leads to corrosion if not been detected of clean from long time. Moreover, pipeline is been used from last several years without any replacement, cleanup or check. Every pipeline system has the life span which can be seen from the following bath curve. (Fineberg, 2006 ),(Wikipedia,2010)

Fig2. Pipeline bathtub curve (Onlinepub, 2009)

Corrosion monitoring system

Corrosion occurred in the internal part of pipeline and could have been easily detected with the help of the corrosion monitoring system. But eventually this system also failed due to the following reasons

Old System

The corrosion system was installed in 1977 based on old technology and was not been replaced or maintained with updated standard checks. The new system of corrosion inhibitor is type of chemical which is been added to the fluid to prevent and easily detect corrosion in system (Innospec, 2010)

Sensors

The corrosion monitoring system has two types of sensors magnetic sensors senses with the help of the magnetic field while ultrasonic sensors sense with vibrations. These sensors where already been failed and had repeated alarms on several occasions that were ignored. (Onlinepub, 2009) (Wikipedia, 2010)

Field pipeline leakage detection system

Leakage detection system is the most important system in any oil industry. Moreover, here system failed due to

Inadequate system

As per the BP (company) system with less stringent leak detection system was suitable for the North Slope and continuously ignored installation of the new system which could easily alerted the operators and spill could have been avoided. Company was even been fined by Alaskan department of Environment conversation (ADEC) in 2002 and was warned to installed a new leakage detection system (Fineberg, 2006)

Turbine replacement

The company used the old set of turbines. According to the records by (ADEC) in 2002 the pipeline system was been was under test and was fail for two times and then the crew members have to work for 5 hours in order to maintain the stable test flow. ADEC administrator mandated the use of best available technology (BAT) but BP ignored it. (Fineberg, 2006)

Alarms

After turbine test it had stable flow of fluid. The flow throughput was reduced by 0.5% and alarms triggered after 13 hours. In order to see effectiveness of leak detection system it's really important to know that how many hours the system is really been able to detect the leakage and what is minimum threshold leak warning level. But in this case the leakage system was unreliable.(Fineberg, 2006)

No PIG used

PIG (pipeline inspection gauge) is used for maintenance of the pipelines without stopping the flow of the liquid. It performs the operation like cleaning its inspection. It flows through the entire pipeline until it reaches the other end. Normally smart pigs are available which are specially used for oil and gas pipeline. They are more accurate and perform more functions. Moreover, here BP had never send the corrosion PIG in order to inspect the line since 1998 that is more than seven years and even ignored the used of smart pig. (Onlinepub, 2009), (Wikipedia, 2010)

Fig3. Smart Pig (Pacificenergypier400, 2010)

Poor management and maintenance

Corrosion problem was known before between gatherings centres and was known by BP (company) but was ignored.

In 2003 Alaskan department of Environment conversation (ADEC) had recommended BP workers to inspect pipeline daily to ensure things are fine. But it didn't carried out this process

Company was fined by ADEC in May 2002 of $300000 for failure of leak detection system. While in August 2002 fine of $ 1.3 million for safety violation as the worker got burn in explosion. In addition to that penalty of $100000 for failure that it couldn't meet new procedures.

The employees had even raised problem before the actual incident happen. But things were ignored by BP management team.

In February 2003 there was concern on "corrosion monitoring staff level" which was reduced from eight members to six

Even U.S news and world report stated that BP workers complain that in order to meet the budget cuts they have to work with worn-out hazardous and dangerous equipment.

BP even reject improvement of parts due to its installation cost for e.g. new turbines would have cost them $10million and work had to be stop for four days and loss of 2.2 million barrels was estimated to avoid this cost. The idea of installation was ignored.

In initial stage BP declined that it took money save measures to maintain the pipeline. But later Robert Malone chairman of BP said in the report that "increase in budget wouldn't have prevented oil spill"

Event Tree

Corrosion

(1)

Sensor Faulty

(2)

Corrosion detection system failed (3)

Leakage occurred

(4)

History faulty alarms (5)

Leakage detection system failed (6)

Result

Cause and consequences

FMEA (Failure mode and effect analysis)

Unit identification

Unit

Function

Failure

Mode

Failure

Cause

Failure

Effect

Likelihood

Severity

Corrosion system

Corrosion detection

Sensor failed and faulty alarms

Unreliable and old system

Corrosion detection system failed

6

10

Field Leakage system

Leakage

Detection

History of faulty alarms

Inadequate

System and old turbines not replaced

Field leakage system failed

7

9

Detect ability

Risk Priority Number

(RPN)

Recommended

Corrective

Action

L

S

D

Amended

RPN

5

300

Installation of new system

4

6

3

72

Replace old alarms with new and accurate

3

7

4

84

Timely inspection

3

5

5

75

6

378

Installation of new turbines and system

5

6

4

120

Clear all the faulty alarms

4

7

5

140

Proper maintenance

5

6

6

180

Similar catastrophe event

EVENT 1

In January 15, 2009 a similar near miss event occurred at Trans Alaska pipeline system (TAPS) during routine pigging check. At certain point of operation pig got stuck in pump station1 (PS1) which was not known by operators. Moreover, at this point light fluid bypassed pig and entered PS1 and ultimately was released out from stations two breakout tanks or by pass tanks. Fortunately everything was fine or else it would have led a source of ignition. The main reasons for failure are

Improper work plan for pigging in project as it failed recognize the potential of stuck pig. No backup for possible consequences encountered in the operation.

The safety analysis conducted by production staff members was inadequate. Moreover, it had not considered the potential of the downstream flow. Due to which light fluid entered PS1.

When such unexpected problem with the pigging occurred, there was communication failure between pipeline person operating PS1 and production person conducting pigging operation. (Onlinepub, 2009)

EVENT 2

This event occurred in winter 2008 in North Slope as it has very limited crude oil logistic system. Trans Alaska pipeline system (TAPS) marine is depended on this for the movement of the oil to lower refineries in other 48 states. But problem with these refineries is limited storage space due to weather conditions, economic consideration and short of infrastructure. Thus during the unusual events refineries are not been able to hold supply of oil and thus storage tanks have a large amount oil spill. Moreover, it's not been detected due to improper leakage detection system and tank capacity full alarms are already faulty or not working. All this factors led to oil spill. (Onlinepub, 2009)

Recommendations

Replacement of corrosion detection system, field leakage and turbines with best suitable technology available (carried out )

All the faulty alarms should be cleared and replace the nonworking once(carried out )

Proper management practices related to work plan of pigging and commutation between gathering centres, pipeline operators and person conducting pigging should be maintained(carried out )

Management issues raised

Complains from employees shouldn't been avoided (carried out )

The problems and improvement suggested by the ADEC should be followed(carried out )

proper risk analysis and methodology should be adopted by management team in order to avoid such events( not carried out )

Highly focus on reliability analysis, planning, technology and safety measurement should be adopted (carried out )

Cost cutting and operating budget should not be lowered so much that it leads to disaster. ( not carried out )

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