Accidents Have Caused Major Explosion
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In the past few years there had been a steady increment in the usage of the risk assessment in the offshore production facilities. This is especially after the Piper Alpha disaster in 1988 and many other major accidents that killed many lives. Operators are showing an increasing awareness by reviewing the safety of their existing topside production facilities. The Piper Alpha accident provided adverse confirmation that the predictions of risk analyses regarding major accidents were certainly prudent. Quantitative Risk Assessment (QRA) is very useful in order to reduce the risks especially on the hydrocarbon releases from offshore topsides facilities. (Harmony, 1998)
The accidents have caused major explosion and followed by some other minor explosions that release huge amount of hydrocarbons such as gas, liquid and 2-phase liquid. According to the investigation report that had been made after the accident, the main reason that causes the accident is the handover work made by two different shift personnel. Communication problem is one of the reasons of the tragedy. Initially the platform only produced crude oil. However, after a few years natural gas is also being produced. During the installation of the gas conversion equipment, the fire walls were not upgraded to the blast wall that causes a severe explosion throughout the disaster. Moreover, the pumping operation of oil and gas was continued even though the fire started
to spread on the platform due to lack of professed authority that just witness the burning of the Piper (Taylor, Wallace, & Ward, 1991).
It was started from the two condensate injection pumps which are A and B. The day shift engineer forgot to inform the condition of pump A to the night shift engineer in which the pressure valve was removed for recalibration and recertification. There are about 106 recommendation has made for the future of safety offshore by the Cullen Report. All of the recommendations had been accepted and implemented by the offshore operators later then (Simon, 2012a).
Petrobras Enchova Central Platform was listed in the major offshore accidents. This platform also listed as one of the worst and notable blowouts in the history of offshore oil platform. It is located in the Enchova Field, Brazil and operated by Petrobras. Two major incidents recorded in these fields which were on 16 August 1984 and 24 April 1988. The first accidents caused by blowout followed by explosion and fire. Most of the personnel were evacuated safely by chopper and lifeboat. Unfortunately, 42 workers died during the evacuation processed. The main reason that killed many lives during evacuation is because the failure of lowering mechanism of a lifeboat. The lifeboat was suspended and eventually fell 10-20m to the sea which killed 36 personnel. The other six workers were killed when they jumped from the platform to the sea at 30-40m height. (Simon, 2012b)
The second accident occurred on 24 April 1988 which is four years later during the workover operations on the platform. One of the well that operated by the platform blew out and finally ignited that resulted in the destruction of the platform. Petrobras decided to drill two relief wells in 30 days' time and eventually succeed in controlling the blowout (Maduro & Reynolds, 1989). The workover well was performed in order to convert oil well to gas well. Then the blowout occurred during that converting process. The fire resulted from gas ignition last for 31 days. There was no loss of life recorded because the floating living quarters were separated from the platform during the blowout. The operator incurred a total loss because the extensive damage to the topside structure (Simon, 2012b).
Ekofisk Bravo Platform is another type of platform that was listed in the top five worst blowout accidents in the oil and gas industry in which the volume of hydrocarbon released is about 202,381 barrels. This platform is operated by Philips Petroleum Company located at Ekofisk field in Norwegian continental shelf. The event of blowout was recorded on 22 April 1977, a few years after the discovery of this field in 1969. It was declared that the blowout cause the biggest oil spill in the North Sea.
The blowout occurred during the workover of the production well. It was started when the production tubing was pulled out at 10000 feet depth. Then the blowout preventer (BOP) is not yet installed after removing Christmas tree prior to the production tubing pulling process. The downhole safety valve was malfunctioned because of improperly installed that cause well kick then resulted in well blowout that release large amount of hydrocarbon to the environment. There was no loss of life recorded as the evacuation job carried properly.
Initially the total release calculated was 202,381 bbls by the Norwegian Petroleum Directorate. Then the oil was evaporated up to 40% of the initial release and a total spill estimated is lower than the initial amount. It was reported that there was no significant effect to the environment.
The investigation to determine the root cause of the accident had been carried out. They found that the main reason of the blowout was caused by human errors. The human errors include inappropriate planning and well control, misjudgment on the job scope difficulty for instance ignores the proper installation documentation and equipment identification (Simon, 2012c).
Bekok C platform that is operated by PETRONAS Carigali Sdn. Bhd. is one of the listed platform accidents in Malaysia that cause severe injuries to the workers. This platform is located 200km from the coast of Peninsular Malaysia. The major factor of the tragedy is because of the gas leaked that cause fire on the platform. Basically, the platform went through scheduled shutdown in order to plan maintenance activities during the accident (Bernama, 2010).
There were about 108 personnel on the platform at that moment of incident and six of them were injured because of the fire. The fire just started after midnight and brought under control by the emergency response teams (ERT). The injured personnel were the one that on duty at that time and in the process to complete their shift. The six injured personnel suffered several burns on parts of their body including the face. The fire might be resulted from sparks that produced from one of the maintenance valves. The remaining 102 workers have been evacuated safely to the nearby platform (Chris, 2010).
Another offshore accident in Malaysia is Tukau B platform located in Miri's offshore. This platform is operated by PETRONAS Carigali Sdn Bhd which is Malaysia's National Oil Company. The fire occurred on 11 June 2012 which is the latest accident at an oil and gas facility recorded on offshore platform.
It was reported that 16 workers were on the platform at that time of fire. Five of them (two PETRONAS employees and other three contractor staff were suffered first and second degree burn. There was no loss of life reported as other remaining workers were evacuated safely to the nearby platform, Tukau A living quarters. (Mohamad Abdullah, 2012)
The fire resulted from the explosion at Tukau B oil drilling platform started to spread on the structure at 9.20am at the compressor skid. Fortunately they managed to put the fire under control within an hour that prevents the fire to spread over the platform. The personnel were doing some maintenance works on the platform at the time of fire.
The human errors could be the reason of the explosion that cause fire and injured some of the workers. Most of the accidents occur were mainly cause by the engineering workers that do not have good understanding on the safety elements. Misjudgment on the job difficulty has been normal situation on the event of fire and explosion. Improper use of standard operating procedure for equipment always becomes major factor in platform accident. This is mainly occurring during the maintenance works that involve the operator and contractor staffs (Luin, 2012).
The most recent incident that involves oil and gas industry in Malaysia is the fire and explosion of the oil tanker named Bunga Alpinia own by Malaysian International Shipping Company, MISC which occurred at 26 July 2012. This event of fire and explosion take place at Rancha-Rancha industrial zone, Pulau Enoe near Labuan.
It was reported that the oil tanker was loading six tons of methanol at the PETRONAS Chemicals Methanol Sdn Bhd jetty when a small fire ignited during a thunderstorm. The fire started at 2.30am and resulted in at least three major explosions that shake the Labuan Island.
Bunga Alpinia had 29 crews on board consisting 23 Malaysians and six Filipinos. The accident killed five workers; four of them were Malaysian and one Filipino as mentioned by MISC Company which is a subsidiary of PETRONAS. Another 24 workers were evacuated safely to onshore (Almeida, 2012).
The fire and explosion just occurred nearby the PETRONAS Chemical Methanol plant that arise another concern if the flames from the tanker ignite the methanol silo. The effect might be severe which can cause enormous destruction to the surrounding area.
According to Oil & Gas UK Knowledge Centre, hydrocarbon release may contribute to major accidents as well as determine a key performance indicator of asset integrity management of offshore installations. A hydrocarbon can potentially release to atmosphere due to leakage from equipment, flanges, valves, pipe works and etc. Each of this equipment has their own release frequency.
QRA study is very important in order to identify the most cost effective ways to reduce risks to people and to the production asset. It is also important for company to improve their understanding on the risks and hazard involved in its offshore operations (Hanson, Lewis, & Walters, 1995).
For Quantitative Risk Assessment study, the release frequency of each Isolatable Section needs to be calculated. The QRA is employed in order to size hazards and advantages gained from their concession. The QRA particularly calculates the overall risk and potential loss of life and the average individual risk of fatality. In order to determine the release frequency the installation type and location are the important parameters that should be considered.
The overall objective of these studies is to calculate the hydrocarbon release frequency for each isolatable section of offshore production facilities. In order to determine the release frequency, the isolatable section of the topsides production facilities needs to be identified at the early period of the research. The quantity of each of the process equipment needs to be determined in order to get the release frequency.
The other objective is to utilize the raw and modify data of release frequencies from the risk assessment data directory (OGP Publications) in order to classify the release criteria by using the inventory released.
Scope of the Research
In this research, a typical unmanned platform is used as a subject of study. A complete offshore production facility will be divided into several sections in QRA study. The sections are known as Isolatable Section. The Isolatable Section consists of different type and sizes of equipment, flanges, valves, pipe works and etc. The research will identify method to calculate the release frequency of a given Isolatable Section of Offshore Production Facilities.
All of the possible process equipment with various sizes is listed down to make the parts count easier. There are three types of release which are full releases, limited releases and zero pressure releases but in these studies full releases type will be used in order to determine the release frequency for each isolatable section.
The parts count of process equipment with its specific sizes can be done by using the data that is provided in the Process and Instrumentation Diagram P&ID. Other than that, the volume of equipment on the topsides of offshore facilities also needs to be calculated by using the volume equation. Process Flow Diagram (PFD) is used in order to determine the volume of each of the process equipment.
2.1 Quantitative Risk Assessment
According to C.M. Pietersen et al. (1991), Quantitative Risk Assessment (QRA) can be defined as a method to determine the risk in major offshore platform accidents. It is crucial to determine the release frequencies from process equipment in the event of failure so that the risk can be identified. P.J Corner et al. (1991) state that QRA can use many type of methods or model ranging from simple correlation to complex computer codes. The method of assessment includes the effect of releases such as fire and explosion models, the model for assessing the impact resulting from the fire and explosion and the probability of failures of the process equipment on the topsides platform. Based on R J Hanson et al. (1995), the QRA (computer based model) was implemented in order to evaluate the risk reduction measures.
In order to improve safety on offshore platform, QRA was introduced after the tragic accident that killed many lives in the event of fire and explosion at Piper Alpha platform. Lord Cullen in his report of The Inquiry based on Piper Alpha Disaster had identified that QRA as a technique that provides a structured, objective and quantitative approach in order to have better understanding on the risks and ways to overcome or control them (Hanson et al., 1995).
2.2 Hydrocarbon Release Frequency
2.2.1 Type of Offshore Topsides Production Facility
Offshore topsides production facilities investment is substantial in order to maximize the production. The main production facilities can encompass half of an offshore topsides platform area and half of the capital or installation cost. There are approximately 16 types of process equipment on the topsides of offshore installation facilities handling hydrocarbon that have potential to release hydrocarbon in the event of equipment failures based on the Risk Assessment - OGP (2010). The process equipment include steel process pipe, flanges, manual and actuated valves, instrument connections, process (pressure) valves, centrifugal and reciprocating pumps, centrifugal and reciprocating compressors, heat exchangers (four different types), filters and pig traps (launchers/receivers).
2.2.2 Type of Releases
According to the analysis of historic process release frequency data (Producers, 2010), releases can be divided into three different types which are full releases, limited releases and zero pressure releases. Full releases can be described as flow through the defined hole is consistent, starting at the normal operating pressure then continuing until controlled by emergency shutdown and blowdown. Limited releases can be classified as cases in which pressure is not zero but the quantity of releases are much less than from a full release. The main reason of these releases is because of the human intervention such as closing an inadvertently opened valve. Then it may cause by the failure from the system itself. Zero pressure releases can be defined as the cases where pressure inside the leaking equipment is virtually zero. This is because of the equipment has a normal operating pressure of zero.
Releases can be classified as major, significant and minor based on the (Pratt, 2002) statement. Significant releases are those lying between major and minor releases. Release frequency of the major hydrocarbon release is higher compared to the significant and minor releases (Edmondson & Hide, 1996).
2.2.3 Type of Hydrocarbon Releases
Hydrocarbon releases have the highest risk on offshore platform that potentially cause loss of life (Hanson et al., 1995). According to Derek B Pratt (2002), the hydrocarbon release type can be classified into three which are gas, liquid and two phase hydrocarbon. Hydrocarbon such as diesel, methanol, hydraulic oil, lubricating oil and helicopter fuel were included. These types of hydrocarbon are termed as non-product hydrocarbon. (Hare, 2008) states that there are five types of hydrocarbon release which are gas, oil, non-process hydrocarbon, 2-phase hydrocarbon type and lastly condensate.
2.3 Inventory of Basic Data
2.3.1 Number of Decks on the Platform
Basically there are three types of decks found in offshore platform which are cellar deck, main deck and helideck. Cellar deck is the lower part of the platform while main deck is the upper part of the platform. Helideck is installed on this main deck which commonly above the living quarters. In some platforms, there are four types of decks existed which are spider deck, cellar deck, main deck and helideck.
Most of the time, all of the drilling or production facilities are placed or installed on the main deck such as power generator and water treatment while all of the manifolds and Christmas trees will be installed on the cellar deck.
One of the significant issues in order to reassessment and requalification of an old platform is the wave-induced force on offshore platform decks. Platform may be subject to partial or even fully submerge in the event of severe storms due to seafloor sinking the cellar deck. The structural integrity of the platform will be obviously affected and is thus a very crucial issue of concern (Grønbech, Sterndorff, Grigorian, & Jacobsen, 2001).
2.3.2 Accommodation Arrangement
Living quarters are the crucial requirement for the safe operational and life support requirements for personnel in the offshore Oil and Gas Industry. The other key requirement in the design and build of offshore facilities is to provide functional spaces for optimum comfort of personnel. Providing a safe environment offshore is mandatory in this industry.
The location of the living quarters on the platform is one of important parameters in personnel safety requirement. The findings presented to the Cullen report based on the past Piper Alpha disaster regarding on the risk reduction would be achieved whether by accommodating personnel on a nearby flotel (floating hotel) or on PDQ (production, drilling, quarters) platform. The advantage is that personnel are separated from fire and explosion hazards if there are accommodated on a nearby flotel but the disadvantage of exposing them to other hazards such as transportation and flotel capsize (E.F, 1993).
According to the QRA made based on the Piper Alpha disaster, it can be concluded that safety can be improved by decreasing the number of personnel offshore or separating production and accommodation platforms linked by bridges. (Lewis & Spouge, 1994) in their study also claimed that the risks depend mostly on the separation between the accommodation and the hydrocarbon inventories.
2.3.3 Location of Helideck
Location of helideck also one of the important parameters in the offshore platform and should be taken into consideration in order to reduce the risks. The scope of study carried out by K.H Von Blohn et al. (1979) included different locations of helideck on platform, effect of a seaway on the wind velocity profile, effect of varying wind velocity on the turbulence level and air flow around modules without the helideck.
Most of the helideck are located directly on top of the crew quarters structure (Blohn, Peterka, Cermak, Barnard, & Ewald, 1979). Based on the wind tunnel tests made on the Maui - B platform, the flow conditions over the helideck for all approach wind directions tested are improved if the original helideck shape is raised 2.5 m above the crew quarters.
Different types of drilling rig or platform have different location of helideck for instance jack-up rig, submersible platform and drillship because they are different in sizes and water depth. The location of helideck also differs between fixed and unfixed structure (BOMEL Limited & Burt, 2012).
2.3.4 Location of Process Equipment
In order to ensure the safety of personnel working on the offshore platform the process equipment should be placed or installed at the right position where there is less tendency of injury during the event of emergency. In other words, accident can be prevented if the equipment had been engineered properly (Johnstone & Curfew, 2011).
Properly layout the facility on the platform is the first job in building a new facility. The equipment that needs to be installed should be listed out and a plot plan of the site must be obtained in order to plan equipment layout. It is started by placing the most hazardous items of equipment on the site. Some examples of hazardous items are venting system, flaring system, fire process equipment, engines and rotating equipment, separators, tanks and unfired vessels.
According to J.E Johnstone et al. (2011), venting system should be positioned downwind of the facility in which the released gases will not risk the personnel life and platform area. Venting system must be placed where there are no or far from the source of ignition. The same goes to the flaring system.
Fired process equipment such as heater treaters, heater or separator, glycol and amine reboiler should be placed away from the equipment that process or store flammable hydrocarbons. It is also should be located away from the potentially released type equipment such as vents and pig receivers.
Pumps and compressors which are categories as engines and rotating equipment must be placed on the site to avoid damage from any possible hydrocarbon releases, ignition and noise. Liquid hydrocarbons may be released to the environment resulted from losing seals of pumps while compressors normally leak small amount of oil which might cause fire if there are source of ignition (Johnstone & Curfew, 2011).
2.3.5 Location of Risers and Pipelines
Risers and pipelines are frequently become one of the main risk contributor on an offshore platform. The most crucial safety goal is to minimize the potential leakage from a riser or pipeline. The impact and corrosion are the significant failure causes by risers and pipelines (Edmondson & Hide, 1996). The location of riser and pipeline should be planned properly because of a limited space on platform in order to operate in a safe condition (Sarica & Tengesdal, 2000). Moreover the congestion on the platform should be reduce in order to lower the risks (Majumder, Markanday, & Anand, 1991).
According to P.J Corner et al. (1996), the most important approach in QRA is the failure that will cause different in the holes sizes and leaks rate to the marine environment. The impact may result in rupture or destruction of the platform while corrosion may cause small holes on the riser or platform which can be repaired and not hazardous. It is also essential to anticipate the release duration in order to determine the significant effects. It might be the long duration release of medium size cause destruction compare to enormous release of very short duration. Some risers are installed outside of the shafts, leakage and explosion will occur if hit by ships (Larsen & Engseth, 1978).
2.3.6 Location of Wellheads
Wellhead is the equipment that installed on the surface of an oil and gas well that acts as a pressure seals and suspension point for casing string. Wellhead that is located at the production platform is called surface wellhead while if the wellhead is located below the water it is termed as subsea wellhead or mudline wellhead.
Wellhead should be located properly on the platform because wellhead load includes all casing strings with cement weight, tubing strings weight, weight of wellhead itself and BOP equipment (Anderson, 1984). Meaning that wellhead carries massive loads and part of the platform weight.
2.3.7 Location of Any Drilling Activities
Drilling operation is one of the most hazardous activities on the offshore platform. Many personnel are at risk because of the intensive labor work. This is because this operation involves in heavy lifts of many components, BOP stacks, collars and precisely miles of drill pipe. Additional risk will be encountered during exploration drilling especially on the shallow gas hazards and the ultra deepwater operations that potentially have high pressure and temperature (HPHT) wells. Harsh environment condition also need to be considered (E.F, 1993).
The best location of any drilling activities is away from the living quarters in order to reduce the risks on personnel. This is for instance in the event of blowout, the personnel can be evacuated safely from the platform.
The drilling operations should be separated from production in order to reduce the release frequency of reservoir fluids on the platform as well as reduce the population at risk. Blowout that can claim many lives also can be prevented if drilling and production carried out separately (E.F, 1993).
According to E.F et al. (1993), the risk to people working offshore start when they leave the shore and stop when they return onshore. The main transportation of the personnel (crew change) is by helicopter or boat. The use of QRA technique had made the risk become apparent because the future risk can be predicted, accidents to be anticipated and ways to overcome or prevent is considered by interpreting the past accident experiences (Lewis & Spouge, 1994).
The helicopter accident can be categorized into three major sections which are accidents in flight, accidents on take-off and accidents on landing while crew boat accident can be described in two categories which are fatalities in transit and fatalities in transfer. Helicopter crash is on the second ranking for causing of fatalities on UK Continental Shelf (UKCS) after hydrocarbon fire and explosion (Lewis & Spouge, 1994).
Based on transport risk study carried by JR Spouge et al. (1994), it can be concluded that transport risks are important. Transportation by using helicopter has higher risk if compared with crew boat. This is because the usage of helicopter is higher for crew change operation since the distant of onshore and platform is considered while crew boats indicate dissimilar problems in evaluating risk due to their great safety record.
2.4 Inventory of Materials That May Cause a Fire or Explosion
2.4.1 Inflammable, Combustible and Explosive Materials
Inflammable, combustible and explosive materials are materials that are capable to cause fire and explosion. These types of materials should be placed or stored away from the fired process equipment, venting and flaring system in order to prevent any ignition from occurring.
These materials must be located away from the living quarters to prevent severe injury to personnel on board in the event of fire and explosion. The blast or firewall has to be installed around these storage materials to reduce the impact of explosion. Properly handling method has to be done on these materials.
2.4.2 Medium of Materials Released
There are many ways for materials release to the surrounding environment. One of medium of materials release is through cracks, splits or holes in the containment envelope. This medium is created from the degradation of the equipment such as corrosion, erosion and wears out.
The releases of material to the atmosphere may be resulted from opening pathway that is provided by the opening of equipment that still containing hydrocarbon by personnel with intention (Pratt, 2002).
2.4.3 Types of Fire
The event of fire and explosion are common in the oil and gas industry especially on the offshore oil and gas platform and drilling rigs (Heaviside, 1980). Every year many injuries and loss of life are recorded because of fire and explosion itself. Personnel are suffered from first to third degree burn which can cause severe injury as well as loss of life. Fire can be classified into four categories which are jet fire, flash fire, pool fire and fireball.
18.104.22.168 Jet Fire
Jet fire can be classified into two categories which are the fire that colliding against wall resulting in a diffuse flame and without collision. Immediate ignition will cause jet fire (Pietersen & Engelhard, 1991). Jet fire also termed as spray fire. Diffusion flame is resulted from the combustion of a fuel that unceasingly released with significant momentum in a particular direction or direction. The releases of gaseous, flashing liquid and pure liquid inventories can cause jet fires (Executive, 2012).
22.214.171.124 Flash Fire
According to C.M Pietersen et al. (1991), in case of gases, delayed ignitions in open spaces will result in flash fire. A flash fire is a sudden, intense fire caused by ignition of a mixture of air and a dispersed flammable substance such as solid, flammable or combustible liquid or a flammable gas. It is described as high temperature, short duration and a rapidly moving flame front.
Fireball can arises from the delayed ignition in enclosed containment that resulting in gas cloud explosion (Pietersen & Engelhard, 1991). The gas cloud explosion together with fire will gives tremendous effect on the offshore platform such as destruction of platform. Fireball can cause severe injuries as well as loss of life to the personnel on board.
126.96.36.199 Pool Fire
Pool fire can be defined as the turbulent diffusion fire burning above a horizontal pool vaporizing hydrocarbon fuel where the fuel has zero or low momentum. Pool fires could be static which depends on where the pool is contained. Large amount of hydrocarbon inventories have the highest risk and likelihood for the arising of pool fire (Executive, 2012).
2.5 Identification of Initial Accidental Events
2.5.1 Release and Leakage of Hydrocarbon from Process Equipment
Hydrocarbon releases is one of the main reasons that result in accident. The release of hydrocarbon from the process equipment may cause ignition followed by fire. Each of the process equipment has its own release rate and frequency. The release rate may be depends on the size and diameter of the equipment.
The leakage of hydrocarbon from process equipment can lead to fire and explosion. Oil and gas can migrate to other areas of the platform in a split second and cause ignition that may destruct the platform as well as kill many lives.
It is important to minimize the number of equipment and piping installation in order to reduce the failure rate. It is better to operate at low pressure if possible to lessen the leak. The equipment with high leak potential such as compressor is place in open ventilated area. Separation between process system from drilling systems, utilities and accommodation is made by using blast and firewalls (Comer & Eades, 1991).
2.5.2 Failure of Utilities
The failure of utilities such as electric power shutting down pumps, compressors or motor operated valves can result in overpressure. Overpressure can be defined as pressure build up over the set pressure of the primary relieving device. Overpressure can cause sudden rupture or leak of utilities. Loss of cooling system such as water and refrigeration can form hazardous situations (Johnstone & Curfew, 2011).
2.5.3 Falling Loads
According to E.F. Brandie (1993), falling loads or dropped objects will create an immediate hazard to offshore workers. It also has high potential to cause major accidents if falling on the process equipment.
The object may be dropped from platform deck or during crane transport to the sea and impact the subsea equipment such as manifold or wellhead. During offshore operation, small objects like cable trays, tools and scaffolding may be dropped regularly but with little impact to the platform area. If applied to larger objects such as drill pipe, the impact is greater even though the probability of the objects to drop is small (Luo & Davis, 1992).
2.5.4 Helicopter Accidents
Helicopter plays an important role in the offshore oil and gas industry. According to UK Health & Safety Executive, about 48 million personnel were transported to and from offshore platform on the UKCS from 1976 until the end of 2002. Seven fatal accidents were recorded that claimed about 88 personnel and flight crew. It was recorded 12 fatal helicopter accidents at UKCS offshore operation since 1976 which claimed 92 lives (Rowe, Howson, & Sparkes, 2002).
Based on the studies carried by Rowe et al. (2002), one of the main reasons in helicopter crash is the aerodynamic effects around offshore platform. These aerodynamic phenomena create a potential hazard to choppers that operating to their helidecks.
Based on the study carried by T. Ulleberg et al. (1991), there are about 24 risk factors had been identified and it was further divided into four main categories that cause fatal helicopter accident. The main four categories are related to operational functions, technical functions, general management and external factor.
There are six risk factors identified in operational functions which are operating conditions, heliports and helidecks, pilot performance, operating procedures, pilot working conditions and emergency preparedness. Then the risk factors for technical functions including technical reliability, inadequate design, maintenance planning, human performance in maintenance, spare parts, equipment and provisions, crashworthiness and design for emergencies, ergonomic design and physical work environment.
On the general management sides, risk factors included policy, organization and responsibility, economy and budget, personnel management, QA and safety management as well as communication and information flow. External factors comprise of oil companies, aviation authorities, air traffic control and external navigation aids as well as manufacturers (Ulleberge, Ingstad, Rosness, & Sten, 1991).
2.5.5 Collision of Ships
Ship is one of the most important medium of transportation for offshore operation. Thus ship has potential or ability to cause severe accident on the offshore platform. This is because ship collision is listed among the initial accidental events (Pietersen & Engelhard, 1991). Collision between ships and platforms also listed as a main risk contributor (Larsen & Engseth, 1978). The collision of ship with the platform might cause massive destruction to the structure of platform particularly when the ship collides with the hazardous area on the platform (Petersen & Pedersen, 1981).
According to Carl Martin Larsen et al. (1978), there are three categories of ships that might hit a platform which are by-passing ship, tankers involved in offshore loading and supply ships in operation close to the platform. The design of platform also will affect the severity of ship collision. Some of the reasons are that platform not sighted and platform protection failure. The risk that might be appeared during ship collision is blowout, explosion, well problems and fire (Massie & Buijs, 1991). It can be said that collision risk can be reduced by reducing probabilities and risk is described differently with different categories of ship.
2.6 Means of Detection
The modes of detection will be active during the event of emergency. It depends mainly on the type of hydrocarbon and severity release. The means of detection comprise of heat, smoke, flame or fire as well as gas. The other detection modes are by visual such as sound and smell. Early detection of hazard will be able to prevent any accident from happening. According to F.A Heraiba et al. (1993), the main function of detection system is to give an early warning of fire and gas leak in the system.
2.6.1 Heat Detection System
Heat detector can be classified into heat detector combining rate of rise and temperature and also thermostat type. Heat detection systems that normally install in the unit control rooms of gas turbine driven equipment and also inside satellite modules is heat detector combining rate of rise and fixed temperature. Thermostat type is placed in areas that more robust detector is needed and at higher ambient temperature such as turbine enclosures (Heraiba & Rahman, 1993).
2.6.2 Smoke Detection System
According to Leslie Heaviside et al. (1980), smoke detectors are normally installed in the electricity generator rooms, switch rooms, control rooms and any other possibility areas where flammable materials exist in which smoke will be produced at the early stage of combustion. Smoke detector also install at the empty space around the living quarter areas.
2.6.3 Flame Detection System
Ultra violet detection system is installed in the areas where flame will be directly produced during fire incident. The areas are included wellhead, separator room, pig launcher areas and drilling zones (Heaviside, 1980). Flame detector responds when the flame stage of the fire is achieved. Welding flash may cause the detector to response (Heraiba & Rahman, 1993).
2.6.4 Gas Detection System
An important aspect to the safety system installed on offshore oil production platform is the early detection of flammable gases and vapors. The common type of flammable gas detector used is electro catalytic. Gas detectors are usually placed near the sources of gas leakage such as gas separator and gas compressor equipment as well as near wellhead areas. Gas detector may also be installed in the ventilation exhaust ducts from areas in which gas may be present or in ventilation inlet ducts into areas in which gas is not typically expected (Heaviside, 1980).
2.7 Emergency Actions
The emergency shutdown system can be described as a system which instantaneously terminates all production activities and other system that not vital for platform emergency operation. The objective of this system is to reduce the effect of an accident or a hazard so that personnel, equipment and environment are protected.
Emergency shutdown system can be activated automatically or manually from a third-party system such as fire and gas system. In emergency shutdown resulted from fire, gas release and major spills, the equipment will be shut down quickly as possible followed by depressurize and drain equipment then lines to leave them in the safest condition. It can create additional wear and tear on machinery because the shutdown time is shorter.
2.7.1 Automatic Shutdown
In the event of emergency, an automatic shutdown system will activate a trip. Signals from process sensors, fire and gas detector and manual push button function as inputs to the logic unit. Then this unit will evaluates the signals and provide output signal to field devices, shutting down the production and utility equipment based on the predefined shutdown sequences (Huse, 1985).
2.7.2 Manual Shutdown
Manual shutdown normally done to equipment that is no longer required for duty, inspection or maintenance. In a case of emergency, the shutdown button is normally pressed. Manually shutdown may cause minimum disruption to production and minimum risk of damage to equipment.
2.8 Causation and Operating Mode
The operating mode on the platform which can cause hydrocarbon releases are divided into six categories which are during the normal production, start-up or reinstatement, maintenance, well operation, shut down and others. The other category includes pigging, abnormal production, testing and sampling (Pratt, 2002).
Four major causation categories are design, equipment, operational and procedural faults. Hydrocarbon releases are normally higher in production compare to other intervention activities like drilling or workover.
2.8.1 Equipment Fault
According to the research carried by UK HSE Executive, equipment fault is the most frequent reported factor that causes accident on offshore platform. This is because most of the time, hydrocarbon releases are higher from the process equipment especially during normal production.
Most of the equipment is used throughout the life of the platform without any replacement in order to reduce the operating cost. The equipment is operated correctly but failed due to corrosion, erosion, fatigue and vibration (Pratt, 2002). The types of equipment that fail the most frequently are piping, valves and instruments. It is clearly seen that the reason for piping leaks is because of large quantities of pipe that being installed on the platform. Mechanical failure is one of the causes that lead to piping failure (Bonn, 1998).
According to Robert J.C Bonn (1998), gas compression and separation system also has high probability to cause major leaks on offshore platform. The main reason for equipment failure is because of the mechanical failure which is similar to other equipment.
2.8.2 Operational Fault
Operational fault is resulted from an improper operation carried by personnel on platform or operator. According to Derek B Pratt (2002), the hydrocarbon releases also resulted from the lack of attention by personnel that purposely open the equipment that still containing hydrocarbons and equipment is left insecure after maintenance.
According to Robert J.C Bonn (1998), the most common operational fault that contributes to hydrocarbon release and leak is improper action taken by personnel. It is further divided into four job tasks which are inspection, maintenance, operation and testing.
Operational fault may lead to the piping leaks. For instance, incorrect fitting, improper operation and improper inspection might cause piping leaks. Improper inspection will result in failure of the piping compare to other equipment (Bonn, 1998).
Operational faults include drilling and production operation. Drilling operation involves heavy lifts of many components such as drill pipe and BOP. The falling of this equipment might cause tremendous effect to the platform as well as personnel.
The crane operation may create high risk to the surrounding platform area because the load might be fell to the platform deck and hits the equipment.
2.8.3 Procedural Fault
Most of procedural fault occur during the maintenance work carry by contractor. Most of the contractor that doing the maintenance work takes this issue lightly. They ignore the procedure because their excuse is that they are expert on that job. Moreover they always do the maintenance works and under judge the proper procedure given.
Based on research carried by Robert J.C. Bonn (1998), major cause of procedural fault is failed in the permit and work procedure system. The most common is caused by scarce procedures. Violation of procedure and permit are still occasional.
Most of the offshore platform accidents are caused by the ignorance of personnel on the procedure during the maintenance operation on the platform. This is termed as procedural violation. Inadequate procedures also may lead to accident because improper handling of the equipment.
The policies and procedures should be improved and make sure that all personnel are competent in their use. Optimize the usage of available guidelines and industry best practices.
2.8.4 Design Fault
Modern design is normally much better than the older design. Design stage is one of the most important parameters in order to ensure the safety of the offshore platform. Wrongly design may cause a great damage and loss of life of the personnel. Increase the distance between living quarters and hazardous areas, install barriers between high hazard processes and low hazard supporting utilities and offer optimum design of fire and blast protection system is a very important parameters in design a platform (E.F, 1993).
Design standards should be reviewed mainly for an older installation or ageing platform against inspection and maintenance standards. According to Robert J.C Bonn (1998), design is not a main issue on the hydrocarbon releases but further study had identified that more robust and user-friendly designs might reduce the number of releases credited to equipment and operational failures.
3.1 Procedure in Quantitative Risk Assessment (QRA)
In this chapter, the steps in carrying out the Quantitative Risk Assessment (QRA) are explained in detail. The important steps that comprise in Quantitative Risk Assessment (QRA) process are listed below:
Hazard Identification (HAZID)
Comparison with Acceptance Criteria
Information Required In Order To Conduct QRA
Before proceeding to the first part of the QRA study, information or data required conducting these studies need to be collected or gathered first. This is to ensure that data required is available in order to start the assessment. Some data or information required in this study includes:
Latest layout, elevation and plot plan drawings
Process flow diagram (PFD)
Process & instrumentation drawings (P&ID)
Hydrocarbon release frequency (OGP)
Offshore workforce personnel distribution
Current safety case
Details of any previous explosion analysis
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Figure 1: Shows process need to carry out in order to conduct Quantitative Risk Assessment (QRA) study. (Source: PETRONAS Technical Standard, 1992)
Hazard Identification (HAZID)
The first part of the study is to identify all type of hazards that is possible to cause hydrocarbon releases and potential hazards to personnel on the offshore platform. Hazard can be divided into categories which are:
Separators and other process equipment
Compressors and other gas treatment equipment
Process pipes, flanges, valves, pump
Topsides flow lines
Turret swivel system
Blowout in drilling
Blowout in completion
Blowout in production
Blowout during workover
Blowout during abandonment
Import flow lines
Subsea wellhead manifolds
Non -hydrocarbon Hazard
Loss of structural integrity
Diesel, chemicals, lubricant oil/ hydraulic oil fires, electrical fires
All of these hazard categories should be identified first before proceed to next step. These types of hazard are the most frequent reported and recorded that result in offshore accident. In these studies, only release frequencies from process equipment are considered.
Release Frequencies Evaluation
Each of the process equipment that is installed on the topsides offshore platform has a potential to release hydrocarbon. Since the detailed count of all the offshore platform items such as valves, flanges and process pipes are based on the P&ID is necessary at this level of analysis, a simple parts count methodology is applied.
As input to the release calculation, the hydrocarbon inventory for each isolatable segment is required. The inventories will be calculated using probabilities with event tree analysis (ETA).
Parts count need to be done in order to determine the release frequencies for each of the equipment. The parts count is done by calculating all of the equipment between Emergency Shutdown Valves (ESDV) based on the P&ID and PFD of the offshore platform.
The release frequency for each of equipment is then classified into several hole size classes in order to consider the different dimension of the potential releases. For example, small (3-10mm), medium (10-50mm), large (50-150mm) and full bore (equipment diameter).
Then each of the release class is used as the independent top event with its own leak and release frequencies. The international database of release frequencies is used as reference for calculation. In this study, the database from OGP Risk Assessment Data Directory which is data for Process Release Frequencies will be used.
Other than that, the volume of equipment on the topsides of offshore facilities also needs to be calculated by using the volume equation. Process Flow Diagram (PFD) is used in order to determine the volume of each of the process equipment.
Modification of release frequency
In order to match the release frequency with Malaysia's platform, some modification has to be done on the international database by using Simple Modification Based on Broad Mechanisms (CCPS) Method. This is a straightforward method but the modification factors are decision based and do not consider for the actual company practices on order to manage pipeline integrity.
3.4.4 Topside Leaks Release Rates
Release rates are identified from the calculated result for each of the process equipment by referring to the modeling of topside process leaks:
Small releases is equivalent to 0.5 kg/s
Medium releases is equivalent to 5 kg/s
Large releases is equivalent to 35 kg/s
Release rate and duration normally leads to the estimation of an averaged scenario considered to be representative of a range of events.
Fire and Explosion
After the identification of release frequencies for each hole or diameter size of each equipment, it is crucial to determine the possible accidental events related to each unit of event tree analysis (ETA) (Pellino & Rainaldi, 2011). According to Shukran Farid (2011), the likelihood of a fire or explosion occurring from a release is determined by using Event Tree Analysis (ETA).
Based on research carried by S. Pellino et al. (2011), the main accident events which may be considered in the analysis are:
Immediate and Delayed Ignition
The ignition type can be identified from a set of generic release rate. There are two major types of ignition that need to be distinguished which are:
Immediate ignition in which avoids personnel escaping before the event of fire.
Delayed ignition is due to the gas cloud drifting over an ignition source on the platform. This may enable personnel to escape before the fire or explosion occurs.
After all of the hazards are listed out, the next step to be taken is assessing the consequences. The severity is identified in order to rank the risk. According to John Spouge (1999), consequence can be classified into four main categories:
Severe (Multiple Fatalities)
Very Serious (A Fatality)
Moderate (Medical Treatment)
Potential severity may impact people or personnel on board, the surrounding environment, the assets value own by company which is referred to platform and regulation. This severity is ranking zero (no impact) to five (massive impact).
The hydrocarbon leak frequency analysis will be conducted. Frequency assessment should be done in order to determine the likelihood or probability of occurrence. It can be divided into five main categories which are:
Very unlikely to occur
Not likely to occur
Likely to occur sometime
Likely to occur several times
Likely to occur repeatedly
In this paper, the calculated risk is the hydrocarbon releases from different type of process equipment that is available on the topsides production platform such as process pipe, flanges, valves, instrument connections, process vessel, pumps, compressors, heat exchanger, filters and pig traps.
In QRA study, the risk measures that will be calculated are individual risk per annum (IRPA), potential loss of life (PLL), F-N Curve and TRIF. IRPA can be defined as the chance of an individual becoming fatality while PLL is the estimated number of fatalities per year which is proportional to the summation of all IRPA.
POB = Personnel on Board of the facilities
Comparison with Acceptance Criteria
The individual risk of 1x10-3 per year is used as the maximum tolerable criterion for personnel. The limit of 1x10-5 per year is described at which individual risk becomes broadly acceptable or a negligible criterion.
The region between these two limits is defined as the ALARP (As Low As Reasonably Practicable) region. The individual risk criteria that have been approved for offshore installation application are in the range between 1x10-3 to 1x10-5 per year (Shukran Farid, 2011).
The calculated result of the study will be compared with the risk acceptance criteria in order to determine the severity of the hydrocarbon releases to the platform as well as personnel on board.
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Figure 2: Shows the Unacceptable Region which is range from 1x10-3 to 1x10-4, ALARP region (As Low As Reasonably Practicable) and Broadly Acceptable region that range between 1x10-5 to 1x10-6. (Source: (Shukran Farid, 2011)
Focus in This Study
Essentially, this study is focus on the hydrocarbon release frequencies of each of the topside platform process equipment. There are total of 16 equipment need to focus on. This equipment is listed on the Process Release Frequencies, Risk Assessment Data Directory (OGP Publication, 2010).
Parts count is the process in order to determine the number of the equipment that is available on the topside platform production facility. The procedure for determining number of equipment is mentioned below:
The layout, P&ID and PFD of unmanned offshore platform is given by the supervisor.
The Emergency Shutdown Valve (ESDV) is determined from the P&ID in order to determine number of manual valve between ESDV.
Isolatable section is determined based on location of ESDV. Isolatable section is based on platform deck.
The hole size (diameter) of manual valve is identified based on the size of process pipe and dimension in the layout. The hole sizes are range between 2 inches to 36 inches.
The number of manual valve for each isolatable section that is between two ESDV based on the hole size is identified and keyed in inside the spreadsheet
The number of manual valve based on the hole size is then multiply with the full manual valve release frequencies in order to get release frequencies.
The multiplication is also repeated with the modification data of full manual valve release frequencies.
Steps (i) until (vi) are repeated for the rest of 15 process equipment.
Determination of Volume
Volume of equipment is determined using dimension available on the platform layout and PFD given by supervisor. The determination of equipment's volume is very important in order to estimate the maximum potential volume of hydrocarbon release for each of the equipment. In order to calculate the volume for each of the equipment, some processes need to be considered as stated below:
The volume formula for process pipe is determined in order to proceed with volume calculation.
Volume of process pipe = L
The hole size (diameter) and length of process pipe is determined by referring to the layout of offshore platform.
All of the data is inserted in the volume formula and volume of process pipe is calculated.
Steps (i) to (iii) are repeated using other selected equipment such as process (pressure) vessel, pump and compressor.
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