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SAFETY: On 25-Oct-88, at the SRC Pulau Merlimau (island) refinery, 3 floating roof tanks containing a total of 46,820 m3 (294,500 barrels) of naphtha were completely destroyed in a major fire that took 5 days to completely extinguish. Fortunately, no-one was killed but 25 people (mainly firefighters) were injured, 5 of them seriously. The 3 identical tanks were 41 m (135 ft) diameter x 20 m (66 ft) high. They were spaced 21 m (70 ft) apart but within a common bund. Just before the incident, 1 of the tanks had been receiving sour straight run naphtha but the tank filling operation had been stopped after the floating roof of the tank was discovered partially submerged. Attempts to transfer product out of the stricken tank had to be stopped when it was observed that the anti-rotation guide pole attached to the shell had been physically displaced. The refinery fire service began to apply foam but ignition occurred about 10 minutes later and the fire immediately developed to a full surface fire. The 2 adjacent naphtha tanks caught fire a few hours later, initially in the rim seal area and rapidly developed to fully involved fires. The fire was so intense it threatened to involve tanks containing kerosene, reformate, motor gasoline, and diesel in adjacent bunded areas.
The immediate cause of the incident was ignition of naphtha vapour in the first tank by static electricity inadvertently generated by application of foam. Critical factors included deferral of inspection and maintenance (corroded annular pontoons were partially flooded with product), the remote location (a small island) and heavy local rainfall at the time. Root causes included inadequate hazard awareness (static electricity generation from application of foam via jet nozzles), inadequate management of change (deferral of scheduled tank inspection and overhaul), inadequate emergency response planning (logistics of shipping firefighting equipment and personnel from mutual aid partners while evacuating non-essential refinery personnel) and inadequate process safety management (cost reduction prioritised over safety).
A key lesson learned is that application of foam by jet nozzles on firefighter’s appliances or remote fire monitors can generate enough static electricity to ignite a fire in a flammable atmosphere. Recent research carried out by the oil industry has shown that applying large volumes of foam rapidly can extinguish even a fully developed tank fire. However, this requires specialist equipment and high capacity pumps, foam generators and pourers or monitors that are specially designed to avoid buildup of static charges and possible ignition. If a floating roof becomes jammed or sinks, it is important that any transfer of oil into or out of the tank is stopped immediately to mitigate the risk of frictional sparks causing ignition.
A long time ago I proposed a nitrogen blanket feed at the top of the tanks but it was rejected as if inadvertently it leaked or was misused then a nitrogen filled confined space could be created. Perhaps a dry riser that could be connected to an N2 supply in an emergency might give a safety blanket? Risk v reward I suppose.
INTEGRITY: On 31-Oct-07, a large pool fire developed at the base of a dehexaniser (naphtha splitter) column at the former Petroplus Coryton refinery (UK). Fortunately, there were no injuries but there was significant fire damage to equipment and piping and a substantial opportunity cost (lost production) due to an extended unplanned outage while an investigation and repairs were carried out. The source of the leak was traced to a pipe rupture at the low point at the dead centre of the underside of a short horizontal section of the hydrotreated naphtha feed line close to the dehexaniser feed inlet nozzle.
The immediate cause of the fire was over-pressure and rupture of the dehexaniser feed line at the low point of a short horizontal section due to reduced pipe wall thickness caused by corrosion under insulation (CUI); the leaking preheated sweet naphtha pooled at the base of the column and the resulting vapour cloud found an ignition source.
Critical factors included 1) existence of a clash between the insulated pipe and a structural member supporting an access platform, 2) the dehexaniser column had been delivered to site with the feed piping already installed and insulated but with no access platforms (these had to be installed in the field due to limited headroom beneath elevated piperacks which would have precluded transportation of the column through the refinery on a self-propelled multi-axle trailer), and 3) the affected section of pipe was located in an obscure position (beneath the access platform and approximately 30 m or 98 ft above grade).
Root causes included 1) inadequate design (failure to comply with the project piping standard which required a minimum 25 mm or 1" clearance between the insulated pipe and a structural member), 2) inadequate correction of non-compliant pipe installation (insulation and cladding cut away to address the pipe vs structural member clash), and 3) inadequate inspection and preventative maintenance (weatherproof sealant perished or absent).
For guidance on CUI risk mitigation and management, see the following publication from the UK Health and Safety Executive (HSE):
www.hse.gov.uk/foi/internalops/hid_circs/technical_general/spc_tech_gen_18.htmFor more information, see www.linkedin.com/pulse/corrosion-under-insulation-cui-peter-marsh/
How many years in service? Which was the normal operating temperature of the line? And had Coryton any CUI inspection program?
SAFETY: On 09-Oct-19, Peter Marsh attended the CompEx 25th Year celebration at the Palace of Westminster. Dr Paul Logan (Director of the UK regulator’s Chemicals Explosives and Microbiological Hazards Division) was a guest speaker at the event. He highlighted a worrying rise in the number of explosions, fires and flammable liquid releases over the last 2 or 3 years in major hazard facilities in the UK which are subject to the Control of Major Accident Hazards (COMAH) regulations. He recommended leaders at COMAH sites increase their focus on competence management to help arrest this trend. He has witnessed several examples of unconscious incompetence where individuals participating in process hazard assessment (PHA) studies have been over-confident and unaware of their own limitations and, as a result, been unaware of some potentially low probability, high consequence process safety hazards. Partial competence can be a dangerous thing!
Experience is a key element of competence but many organisations have lost experienced employees through mergers, restructuring and downsizing. The combined effects of voluntary redundancy schemes and limited recruitment have inadvertently created a demographic shift (ie. an ageing workforce) in some organisations, thereby increasing the risk of additional un-managed loss of expertise in future years through a wave of retirements.
Why not share some good practices used by your organisation to assure the competence of its employees and contractors and offset the loss of experience? Your shared knowledge may just help save someone’s life one day.Never a truer word spoken and put far more diplomatically than I would have.
Keep the process safety flag flying, Pete!
Good line 'unconscious incompetence'.
SAFETY: Could you pass the “beer truck” test? Who would do your safety-critical work if you were hit by a beer truck? Would your refinery be able to maintain safe, efficient, reliable and compliant operations?
Many refiners have high-level plans in place to deal with business interruptions caused by extreme weather, fire, cyber-attack, etc. But few have detailed plans in place for assuring knowledge retention and transfer for safety-critical roles at all levels of the organisation (manager, engineer, operator, plant inspector, maintenance planner, etc). Engineers have a responsibility to build a legacy of engineering excellence and to document and share their knowledge and experience. Operators have a responsibility to use their knowledge and skill to maintain and enhance procedures to ensure the plant always operates within its safe operating limits.
Refiners are under relentless pressure to reduce costs to maintain or improve margins. Many have already lost experienced employees through mergers, restructuring and downsizing. The combined effects of voluntary redundancy schemes and limited recruitment have inadvertently created a demographic shift (ie. an ageing workforce) in some organisations, thereby increasing the risk of additional un-managed loss of expertise in future years through a wave of retirements. Consequently, organisations are typically running lean with engineering functions having minimal spare capacity to share knowledge and build expertise. Furthermore, many refineries are now achieving longer runs between turnarounds (fewer startups and shutdowns) and better safety and reliability performance (fewer emergency shutdowns). As a result, operations teams have fewer opportunities to learn from abnormal operations where rapid and correct action can be critical for avoiding escalation to a major process safety incident.
These risks can be mitigated by 1) organisational management of change (MoC) reviews and 2) competency assurance management programmes.
A pre-emptive organisational MoC review conducted on all safety-critical roles in an organisation helps identify critical tasks and define clear roles, responsibilities and accountabilities. The review should include mapping of critical tasks to roles to ensure none are overlooked and should formalise what safety-critical information is to be shared and how. It should also include scenario assessments to ensure that abnormal events and emergencies are adequately covered and that individuals are properly qualified and trained. Mapping safety-critical roles to individual incumbents provides a robust basis for succession planning activities designed to maintain and enhance the skillset of the organisation.
Competency of workers in high hazard industries such as oil refining is critical to process safety performance. Personnel in all safety-critical roles should receive plant-specific initial and refresher training on process hazards, their potential consequences and barriers/safeguards for mitigating these risks. Operators should also receive pertinent training on process chemistry, process variables, control schemes, automatic trip systems, emergency procedures as well as “on the job” training in the field to familiarise themselves with the process equipment on the plant they are responsible for. Gun drills and dynamic training simulators are excellent methods for promoting retention and enhancement of operators' knowledge.Thanks Sean. I normally manage to limit my work blogs to a max of 2 or 3 paragraphs but failed miserably this time!
Setting aside for a moment how much I miss Adnam’s, I totally agree. Other than my time at Coryton, I’ve never worked for a refiner that valued knowledge retention and organizational MOC
Long post but all important...
INTEGRITY: Corrosion under insulation (CUI) is typically caused when insulation gets wet due to water ingress beneath the weather barrier (jacketing), or moisture condensation from steam tracing leaks, cooling tower drift or ambient air in humid and windy climates. CUI occurs where the underlying metal surfaces are not hot enough to keep insulation dry during normal operation and is therefore most prevalent on equipment with metal skin temperatures in the range -4 to 121 Deg C (25 to 250 Deg F). It can be a particular problem at the top sections of carbon steel distillation columns, particularly if the column has external stiffening or insulation support rings which can provide a collection point for water.
There are a wide range of measures available to mitigate CUI. Stiffening and insulation support rings should incorporate drain holes to prevent water accumulation. Carbon and low alloy steel piping and equipment with metal skin temperatures below 60 Deg C (140 Deg F) should be painted with a shop-applied inorganic zinc (IOZ) primer. Where higher temperatures are expected, more specialised coatings such as epoxies or thermal spray aluminium can be used. Impermeable insulation materials such as closed cell foam glass can be selected rather than the more traditional calcium silicate or mineral wool. Joints in insulation jacketing (typically fabricated from aluminium sheet) should be carefully sealed with caulking or mastic. Steam tracing joints should be located outside the jacketing with tracing pipework entering and leaving at the bottom of the jacket section.
CUI generally occurs as pitting corrosion and can be quite localised. It is difficult to detect as visual inspection of the top sections of distillation columns is typically not included in operator’s daily rounds and, in any case, corrosion damage is hidden by the insulation. Inspection ports can be cut into the insulation to enable periodic on-line inspection, but it is important to ensure repairs to damaged jacketing are made with the same jacketing type and that any perished caulking or mastic sealants are replaced to avoid water ingress (photo). Unfortunately, inspection ports only reveal a tiny fraction of the potentially-affected metal service, so periodic stripping, abrasive blasting, re-painting and re-insulating may also be required.SAFETY: Flow-induced vibration can lead to fatigue failures of thermowells. Such failures typically occur at the base of the thermowell stem where it attaches to the mounting flange (photo). Since thermowells are an integral part of the pressure containment envelope for process plants, this type of failure can result in a loss of primary containment (LOPC) and potential fire, explosion or toxic release incident.
Process plant debottleneck projects typically include process system hydraulic checks, equipment rating checks, pressure relief system checks, mechanical design temperature and pressure limit checks, etc. Unfortunately, checks for potential flow-induced vibration of thermowells are sometimes overlooked.
Flow-induced vibration occurs because of vortex-shedding when a process fluid flows past an obstruction in its flow path. Calculation of the natural (resonant) frequency for a thermowell and its vortex-shedding frequency at various operating conditions is complex and requires the process engineer and instrument engineer to work together closely. These calculations should be included in the project work scope for any scenarios that may result in higher process stream velocities where thermowells are present (this applies to transient conditions such as catalyst regeneration as well as steady-state conditions). Refer to ASME PTC 19.3 TW for details of the calculation method.
Best practice requires the vortex shedding frequency to be at least 20% below the resonant frequency for the thermowell to avoid fatigue failure. If the thermowell is found to violate this limit, it should be replaced. Historically, this has meant installing a shorter, heavier (thicker) thermowell as this tends to stiffen the thermowell and increase its resonant frequency. A taper profile results in different vortex shedding frequencies over the immersed length thereby reducing the amplitude of vibration. Note, however, that heavier, tapered thermowells have increased thermal mass which will slow response time and shorter thermowells have lower accuracy. The good news is that new thermowell designs are now available which enable vortices to form on both sides of the thermowell, cancelling each other out and virtually eliminating flow-induced vibration (eg. Rosemount Twisted Square, OMC VortexWell, etc). -
Insights
Delivery of safe, reliable and compliant refining operations starts with teamwork, role clarity and training.
