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  Attachment B Citation Summaries Refinery NEP
Data as of June 2008


Proposed Citations: 1910.119xxxx Text (Paraphrased from Citations)
c 1     The employer did not develop a plan of action for employee participation in process safety management.
c 1     Employee Participated, Operators are not consulted on how often operator refresher training is need.
c 1     The employer did not develop a written plan of action regarding the implementation of employee participation:
The plan states that employees will participate as member of the PHA teams but does not define their involvement.
The plan does not address how the employer will consult with employees on the frequency of refresher training.
The plan does not explain how contract employees are to be trained in known potential fire, explosion, and toxic release hazards related to job and process and the applicable provision of the emergency action plan, and the means to be used to verify that the employees understand the training.
c 3     The employer did not ensure that the employees and their representatives had access to all action items resulting from audits, process hazard analyses and incident investigations that require tracking, as these are placed into an electronic system which can not be accessed by the employees or their representatives.
d 2 1 d The employer did not develop safe operating pressures, temperatures, or levels for absorber stripper, debutanizer, and
C3/C4 splitter columns, or safe operating pressures for a surge drum.
d 2 1 e The employer did not develop consequences of deviation if safe upper and lower limits were exceeded, including for
absorber stripper, debutanizer, and C3/C4 splitter columns, and a surge drum.
d 3 1   Process safety information pertaining to the equipment in the process did not include the elements specified in 29 CFR
1910.119(d)(3)(i)(A) through (H):
Information related to the materials of construction and to design codes and standards was not available for:
Acid storage
Caustic Storage
Depropanizer
Reflux Drum
Depropanizer Reboiler/Exhaust Steam
After Condenser
Desalted Crude/LGO Pump-around Exchanger
Desalted Crude/VT Bottoms Exchanger
Desalted Crude/HGO Pump-around Exchanger
Crude Heater
Vacuum Heater
d 3 1 b The process safety information pertaining to the equipment in the process did not include an updated and accurate
piping and instrumentation diagram.
d 3 1 b The employer failed to develop P&IDs which accurately represented equipment for the process:
Inlet block valve for a safety valve was chained closed while the P&ID indicating that it was car sealed open
Butterfly valve shown car sealed open but was missing the car seal in the field.
Hot relief high temperature alarm was listed as critical instrumental on the P&ID but was not in the critical instrument
program.
Exchanger ID's were not clearly marked on the unit.
Safety valve marked with the wrong number and pressure on the P&ID
Only one hydrogen trailer hook-up shown on the P&ID but two trailers were connected in the field
MOVs were not listed on the P&ID
Missing P&ID tag for safety valve
d 3 1 b P&ID's for at least one process are inaccurate.
d 3 1 b The employer's piping and instrument diagrams (P&ID's) were not current and accurate ( 9 instances in 3 units).
d 3 1 b The employer does not ensure that the piping and instrumentation diagrams in Alkylation were updated and accurate.
d 3 1 b P&IDs reviewed had discrepancies including:
The Degas Recirculation line for the Debutanizer charge pumps was disconnected but was shown in service by P&ID
A ¾" bleeder valve was not shown on the P&ID.
For two surge drums there are a series of valves that are not on the P&ID.
d 3 1 b P&IDs did not accurately reflect the equipment in De-Coker unit, such as but not limited to high and low alarms for 3 temperature points.
d 3 1 b P&IDs inaccurate:
TI in field not shown on P&ID
Valves on P&ID not found in field
Valves in field not on P&ID
Carr Sealed valves not shown as such on P&ID
Wrong valve sizes on P&ID
d 3 1 b The Employer did not ensure that this process safety information for P&IDs was maintained accurately. Instances
include, but are not limited to:
PSV sizes inaccurate
Wrong type of relief valves shown.
Relief block valves shown as locked open when the field valves were not.
Relief block valves not shown as locked open when they should be.
PSV tag numbers inaccurate.
Line sizes inaccurate and inconsistent.
d 3 1 c Process safety information in respect of electrical motors in use in Class 1 Division 2 hazardous locations did not include information as to whether these motors were of a kind appropriate for use in such locations.
d 3 1 c The employer failed to ensure that PSI was accurate for a heat exchanger in that the original U1 form indicated 4 nozzles while 5 were documented by inspection records and field verification.
d 3 1 c The employer failed to ensure that PSI was accurate for the P&ID in that a relief valve is shown as a 1-½" F 2" when it is actually a 1-¼" x 1-½" relief valve.
d 3 1 d Process safety information from the equipment in the process did not include the design and design basis for the Dewaxing Unit blowdown vent stack that relieves flammable vapors to the atmosphere from the blowdown drum.
d 3 1 d PSI for blowdowns in the HCU do not reflect changes made to the blowdown relief system design during the 2005 turnaround.
d 3 1 d Process safety information pertaining to the equipment in the process did not include the relief system design and design basis, including:
Relief system pressure valves
Fractionator stripper pressure safety valve (Removed)
Crude Unit blowdown system
Coker Unit blowdown system
Cat Unit blowdown system
d 3 1 d Process safety information pertaining to the equipment in the process did not include the relief system design and design basis:
The employer did not have PSI including, but not limited to the exit velocities of gasses/vapors released from two vent stacks, the design basis for the vent stacks related to exit velocities, the design residence time of vapor and liquid in the drums the design basis for vapor-liquid separation for the drums, and the design basis/worst-case scenario for maximum liquid-vapor release to the blowdown systems.
The employer did not have PSI including, but not limited to, the exit velocities.
d 3 1 d Process safety information pertaining to the equipment in the process did not include the relief system design basis for system prior to 2006.
d 3 1 d Process safety information pertaining to the equipment in the process did not include the relief system design or design basis; specifically, for 10 safety relief valves, the employer did not have the design calculations and/or the superimposed back pressure calculations.
d 3 1 d Process safety information for the equipment in the process did not include the design and design basis for the Dewaxing Unit blowdown vent stack that relieves flammable vapors to the atmosphere from the blowdown drum.
d 3 1 d PSI did not include the relief system design and design basis for:
Relief valves
Removal of fractionator PSV
Crude unit blowdown system
Coker unit blowdown system
Cat unit blowdown system
d 3 1 d Set pressures were listed incorrectly on P&IDs for 8 reliefs in two units.
d 3 1 f The employer did not include design codes and standards employed in PSI for equipment, including:
The crude unit blowdown system
Coker unit blowdown system
Cat unit blowdown system
d 3 2   The employer did not document that the equipment in the process complies with RAGAGEP, in that the operators control room was identified in a facility siting analysis as being unprotected against an explosion.
d 3 2   The employer did not document that the equipment in the process complied with RAGAGEP:
The employer failed to protect employees inside the operator shelter which was potentially exposed to overpressure hazards of up to 3 psi as a result of a vapor cloud explosion
The employer did not comply with API 753 Section 3 when it failed to protect employees inside a wooden trailer being used as an operator shelter that was placed within the 1 psi overpressure zone.
The employer did not comply with ASME Boiler and Pressure Vessel Code, Division 1 (BPVC) Section VIII. UG-135(d) when it failed to provide adequate controls to ensure that the block valve for a safety valve in the open position.
The employer did not comply with NFPA 496 Section 7.4.1 in that a air curtain door was measured at negative 342 feet per minute (FPM). A minimum reading of 60 FPM must be maintained through all openings. In addition air curtains on two doors were disabled and not functioning.
Illumination of means of egress as required by NFPA 101 Section 7.8.1 was not adequately maintained throughout the unit.
The process sewer including the catch basin and lateral piping under a drum were damaged. In case of a release, C4 would pool in the area.
d 3 2   The employer did not comply with RAGAGEP when it failed to protect employees inside structures exposed to explosion, fire, and high pressure hazards as a result of a release of highly flammable materials. A facility siting study found deficiencies that needed correction in the Auxiliary Control Room, Central Control Room, and Laboratory.
d 3 2   The employer did not document that the equipment in the process complied with RAGAGEP including:
Controls are not adequate to ensure that intervening valves on 3 vessels remain in the open position.
The design of blowdown quench water systems does not include accurate information on the initiation or quantity of quench water required when the system is activated.
Type D Emergency Block Valves (EBV) exposed to destructive heat are not fireproofed to mitigate the spread of fire.
d 3 2   Critical valves were tagged open with a "Do not close this valve" administrative procedure but not physically locked open ( 6 instances).
d 3 2   The employer did not document that the equipment in the process complied with RAGAGEP, in that:
An RV was evaluated to be undersized in regards to the external fire case scenario (3 instances).
An RV was evaluated to be discharging at an elevation below the flare header, which could allow condensation to damage the relief device and related piping.
A knock-out drum was evaluated to not be able to provide adequate retention time to prevent liquid carryover to the flare.
Valves that are part of the quench recycle gas stream piping circuit(s) for reactor vessels do not comply with RAGAGEP.
The valves stick when closed and must be manually struck with a sledgehammer to open. The pneumatic mechanism (the actuator) for opening the gate valve does not have the ability to reopen the valve without the assistance of portable hydraulic jacks placed on the actuator and the manual force of the sledgehammer on the exterior valve housing.
The employer did not document that PHA credited safeguards comply with RAGAGEP in that piping circuits did not receive adequate mechancial intergrity inspections.
Non-destructive testing by profile radiographic technique was only preformed at one thickness measuring location.
The employer did not document that PHA credited safeguards comply with RAGAGEP in that a piping circuit did not receive adequate mechanical integrity inspections. This circuit supplies quench recycle gas (hydrogen) for the quench valves.
d 3 2   The employer did not ensure that its mechanical integrity (MI) program was developed, implemented, and met RAGAGEP such as ISA-S84.01, for calibrating, inspecting, testing, and maintaining Safety Instrumentation Systems (SIS) for emergency shutdown and interlocks.
d 3 2   The employer did not document that 6 pressure vessels complied with recognized and generally accepted good engineering practice such as the ASME Boiler and Pressure Vessel Code. These pressure vessels did not have safety relief valves and the pathway to the safety relief equipment had intervening valves which did not have controls to ensure that they would remain in the open position.
d 3 2   The employer did not document that the equipment in the process complied with RAGAGEP including:
Controls are not adequate to ensure that intervening valves on 2 vessels remain in the open position.
The design of blowdown quench water systems does not include accurate information on the initiation or quantity of quench water required when the system is activated.
Type D Emergency Block Valves (EBV) exposed to destructive heat are not fireproofed to mitigate the spread of fire.
d 3 2   At the facility, the employer did not document that equipment in the process complied with RAGAGEP including, but not limited to:
Controls were not in place to ensure valves downstream of PSV's were open.
Crude Unit blowdown system.
Coker Unit blowdown system.
Cat Unit blowdown system.
Valves between two vessels, which depend on a common relief, were not secured open.
d 3 2   The employer did not document that piping circuits complied with RAGAGEP when it failed to compile thickness measurements and other inspection records related to thickness measurements.
d 3 2   The employer failed to ensure that RAGAGEP were followed with respect to the set pressures of relief devices. The relief valve was set at 270 psig on an exchanger with a working pressure of 150 psig. There was also inadequate overpressure protection in the event of a tube leak or rupture.
d 3 2   The employer failed to ensure that RAGAGEP were followed with respect to the set pressures of relief devices. The relief devices on an exchanger were set at 540 and 600 psig while the MAWP for the exchanger was 480 psig.
d 3 2   The employer failed to ensure that RAGAGEP were followed in that PSI did not include the electrical classification of listed pump motors.
d 3 2   The employer failed to ensure that RAGAGEP were followed in that building ventilation system was incapable of detecting combustion products (e.g., carbon monoxide) and stop air intake in the event of a fire, which could result in combustion products entering the ventilation system (e.g., API 752-2003 Sections 4.5.2(e) & 6)
d 3 2   The employer did not follow RAGAGEP in utilizing an FCCU relief system designed for system operation in 1990 at below current operating rates.
d 3 2   First level sections of structural steel supporting process piping were not fireproofed in accordance with refinery specifications.
PSI does not contain a documented review of the conformance of the operator shelters (local control room) to RAGAGEP regarding resistance (personnel protection) in the event of a vapor cloud explosion.(multiple units)
The employer does not fully apply the selected methodology (HAZOP or other equivalent) to all of its covered processes including:
Handling of flammable and toxic gases at the FCC atmospheric.
Handling of flammable gases and liquids at the Crude units atmospheric in the FCC unit.
Historically higher risk scenarios, such as mixing of the contents of the reactor and regenerator, were not evaluated qualitatively and fully documented and were misclassified with lower risk ratings.
The South Flare System.
d 3 2   The employer failed to ensure that pressure vessels, falling under the scope of ASME BPVC Section VIII Division 1, were provided with pressure relief devices for overpressure protection.
The employer failed, at locations throughout the refinery, to provide adequate controls to ensure that intervening valves between pressure vessels and relief device(s) were postitvely controlled to remain in the open postition during operation.
The employer did not comply with RAGAGEP when it failed to protect employees inside control room buildings and other buildings employees congregate in throughout the refinery battery limits:
NFPA 496-2003 Section 7.4.7 in that failure of the positive pressure air system inside the building would not activate an alarm at a constantly attended location.
Employees inside the buildings were exposed to building collapse hazards due to overpressure events.
The employer did not comply with RAGAGEP when it failed to properly classify buildings and areas directily above below-grade unsealed pits, sumps, and trenches (i.e., Class 1, Division 1 Group D locations) in its electrical classification diagrams for hazardous locations in accordance with API RP 500.
Improperly classified areas included, but were not limited to, the control room building, the warehouse building, areas directly above below-grade unsealed to sewer collection pits and the below grade unsealed sewer pump lift vault.
d 3 2   The employer did not document that the equipment in the process complied with recognized and generally accepted good engineering practices.
3 3   Pressure vessel shell temperatures not maintained or tracked for use in evaluating possible temperature related damage in high temperature service for a vessel susceptible to such damage.
e 1     The employer's process hazard analyses did not address:
The effect of sulfur coating of electrical equipment and piping in the storage pit area The installation of external cooling equipment on a column overhead.
e 1     Employer did not fully apply the selected PHA methodology (HAZOP or other equivalent) to all of its covered processes, including atmospheric blowdown drums in the FCC and Crude units, and a flare system.
Historically higher risk scenarios were not properly evaluated in the FCC unit complex.
e 3 1   The employer did not conduct an analysis for fire hazard in a covered process.
e 3 1   The process hazard analysis did not address the hazards of the process by not identifying scenarios where product streams relieving to a blowdown drum and stack could result in the discharge of hot heavier-than-air vapor and/or liquid hydrocarbons and could cause an explosion and/or death.
e 3 1   The process hazard analysis did not address the hazards of the process:
At the facility, the employer did not identify or evaluate all scenarios that might result in the discharge of hot, heavier-thanair, or liquid hydrocarbons, such as relief systems feeding into blowdown systems in excess of the design capacity, when it conducted the process hazard analysis including but not limited to:
Crude Unit blowdown system.
Coker Unit blowdown system.
Car Unit blowdown system.
e 3 1   PHAs did not address how loss of utilities would affect the safety of the unit (cooling water, electricity, steam or sewage disposal capability). There could be a loss of control of the unit with consequent release or accumulation of toxic, flammable, or combustible materials.
e 3 1   No PHA was done on hazards related to loss of control room functions, which could result in loss of control of the unit with consequent release or accumulation of toxic, flammable, or combustible materials.
e 3 2   The process analysis did not identify a previous incident(s) which had a likely potential for catastrophic consequences in the workplace.
The employer failed to identify a 2001 near miss incident in the PHA Revalidation of the Topper unit.
e 3 2   The process hazard analysis did not identify previous incidents which had a likely potential for catastrophic consequences in the workplace, including:
An event where an operator discovered a propane leak at a Propane Condenser.
An event where deresined oil spilled from an open cap on a pipe leading to storage.
e 3 2   The process hazards analysis did not identify previous incidents which had a likely potential for catastrophic consequences in the workplace:
The PHA did not address the cumlative effects of high skin temperatures on thick walled high pressure, high temperature 2-½ chrome, 1 moly vessels.
The 2007 Process Hazard Analysis did not identify the following incidents:
Wrong gaskets were installed in the acid inlet line, effiuent mix outlet line and equalizing line while de-blanking which could lead to potential gasket failure.
124 gallons of flammable alkylation feed released to the atmosphere.
Hydrocarbon release of 700 pounds for approximately 90 seconds due to the lack of procedures to address abnormal conditions in the unit created by a power outage.
Sewers beneath a UPS Battery room having an explosive atmosphere due to a water seal failure in the sewer system.
Loss of a charge pump and seal causing the shutdown of the Alky unit.
A release and the unscheduled shutdown of a process unit due to a pinhole leak that developed from a weld where major corrosion was found.
4,200 gallons of a propane/butane mixture released to atomosphere over 45 minutes from two relief valves.
The Release of 2,100 gallons of butane to the atmosphere due to mechanial failures of 2 pumps.
A Level 1 Flammable release due to the lack of alarms for the cooling water circulation pumps.
e 3 2   The PHA did not address the cumulative effects of high skin temperature on thick-walled, high-pressure, hightemperature alloy pressure vessels.
e 3 2   The PHA did not identify previous incidents with a likely potential for catastrophic consequences in the workplace, including:
Installation of wrong gaskets while deblanking a process vessel.
Release of 124 gallons of flammable alky feed due to high pressure.
Hydrocarbon release due to lack of procedures for abnormal conditions following a power outage.
Explosive atmosphere in process sewers due to water seal failure.
Loss of a charge pump and seal, causing an unscheduled shutdown.
Release and unscheduled shutdown from a weld in a heavily corroded elbow.
C3/C4 release from relief valves to atmosphere.
Pump failures leading to C4 release.
Flammable release due to lack of alarms for cooling water circulation pump failure.
e 3 3   The employer's process hazard analyses for the refinery, including, but not limited to the Fluidized Catalytic Cracking/Gas Concentration Units, did not indentify the specific engineering or administrative controls applicable to the identified hazards and their interrelationships.
e 3 3   The 2004 PHA Revalidation for a Topper unit failed to identify and address the engineering controls that were safeguards to controls the hazards of streams relieving to the blowdown system.
e 3 3   The PHA did not address the lack of fireproofing on pipe rack supports located in close proximity to process equipment such as but not limited to pumps.
The PHA did not address critical instruments that were overdue for inspection.
e 3 3   The PHA did not address fireproofing SHE Critical Type D emergency block valves (EBVs) installed in areas classified as fire zones where approximately nine EBVs and their associated power lines are not fireproofed.
e 3 3   At the facility, the employer did not identify all safeguards applicable to a hot, heavier-than-air, or liquid hydrocarbon release when it conducted the process hazard analysis including but not limited to:
Crude Unit blowdown system.
Coker Unit blowdown system.
Cat Unit blowdown system.
e 3 3   The employer failed to ensure that the PHA included an evaluation of the consequences of "more pressure" and tube leaks (loss of containment) for heat exchangers.
e 3 4   At the facility, the employer did not identify, evaluate, address the consequences of all scenarios that might result in the discharge of hot, heavier-than-air, or liquid hydrocarbons when it conducted the process hazard analysis including butnot limited to:
Crude Unit blowdown system.
Coker Unit blowdown system.
Cat Unit blowdown system.
Closed valve on pressure relief lines.
e 3 4   The PHA did not identify, evaluate, and address the consequences of all scenarios that might result in the discharge of hot, heavier-than-air vapors or liquid hydrocarbons in units including:
Crude unit blowdown system.
Coker unit blowdown system.
Cat unit blowdown system.
Closed valve on pressure relief line.
e 3 5   The process hazards analysis did not address facility sitting:
The PHA did not address the location of a pipe rack containing hydrogen, benzene, naphtha and butane found to be within 22 ft. of the operator shelter.
The PHA did not address the discharge of flammable gasses including but not limited to butane, propane, and naphtha from the stack of an Atmospheric Blowdown Drum which could impact a Furnace and an Operator Shelter located 43 ft. and 91 ft. away, respectively.
e 3 5   The 2004 PHA revalidation for a Topper unit did not address the facility siting of an occupied building in the unit.
Evaluate and/or control hazards identified on the building siting checklist.
e 3 5   PHAs done in 1997, 2002 and 2007 did not address facilitiy siting hazards of the process:
The PHAs did not address the location of a pipe rack above the control room; leakage or major failure of these pipes could expose employees in the control room to the hazards of fires and limit the ability of the employees to properly shutdown the units.
The PHAs did not address the failure of HVAC equipment on the roof of the control room which is designed to maintain an atmosphere in the control room that is free from levels of explosive gases and vapors as well as toxic chemicals.
The PHAs did not address the locaton of vessels located on the Roadway which subjects vessels and equipment to the hazards of being stuck by vehicles which use the aisle on an irregular basis durng maintenace activties.
The PHAs did not address the location and use of sewer systems located in the Poly unit which could result, in the event of an upset condition, in fires or explosions spreading to other units.
e 3 5   The process hazard analysis did not address facility siting including control room air intake location, and change proximity to hazardous process equipment, and the location of the asbestos trailer in proximity to a hazardous location.
e 3 5   The process hazard analysis did not address facility siting:
The employer failed to adequately address facility siting in the Crude Unit, related to the siting of occupied structures including, but not limited to the Old Crude Unit Control Room.
For the HF Alkylation Unit, the employer failed to adequately address facility siting hazards.
e 3 5   The process hazard analysis did not address facility siting:
The employer failed to address siting hazards such as but not limited to potential employee exposures to H2S, flammable vapors, and sulfuric acid gas releases from adjacent plans which could affect the occupants of the office building, where ventilation system was not equipped with H2S, LEL, and sulfuric an gas detection systems.
Potential employee exposures to sulfuric acid gas releases which could affect the occupants of the Control Room, where ventilation systems were not equipped with sulfuric acid gas detection systems.
Potential employee exposures to H2S, flammable vapors, and sulfuric acid gas releases from adjacent plants which could affect the occupants of the Contractor Garage.
Potential employee exposures to sulfuric acid gas releases from adjacent plants which could affect the occupants of the Plant Control Room.
e 3 5   The employer failed to address process hazards related to facility siting including but not limited to location of fire protection, equipment spacing and interaction, maximum expected inventories of flammable chemicals, and vehicle traffic and small piping protection from impact.
e 3 6   he 2004 PHA Revalidation of the Topper unit failed to document the evaluation and/or control of the hazards identified on the human factor checklist.
e 3 6   The process hazard analysis did not address human factors:
The PHA did not address the hazards of operating an isolation valve during emergency conditions. Workers have to climb stairs and/or a ladder to operate the gate valve which is located on the 2nd floor platform.
The PHA did not address the hazards of operating difficult-to-access valves. Workers could be exposed to falll hazards of 23-45 ft. to the ground below when opening/closing noted valves.
The PHA failed to consider unmarked eqiupment on the unit to include exchangers and safety relief valves which could lead to confusion by operators and/or contractors
The PHA did not consider overhead hazards when employees were climbing fixed ladders. An 8 in pipeline, 13 ft. above the ground, was located within 24 inches of the climbing side of the ladder.
The PHA failed to consider the hazard of using machinery such as powered industrial trucks, backhoes and aerial lifts in close proximity to process equipment which can be struck/damaged.
e 3 6   The process hazards analysis did not address human factors.
The PHAs did not address the location of isolation valves in the Polymerization unit. Employees may have to manually operate these valves while wearing protective equipment or climb a caged ladder, possibly wearing SCBA.
In the South Area vessels, piping heat exchangers and other equipment are identified by name, in the North Area numbers are used, possibly causing confusion especially to contractors.
The hazards of overfilling the neutralization basins.
The hazards of misdirecting flare gases and liquid/vapor mixtures from the acid flare header to the neutralization basins via the vent line between the two.
e 3 6   The PHA did not address human factors, such as blow downs where sight glasses on the side of each blow down are not accessible.
e 3 6   The employer did not ensure that the process hazards analyses adequately addresses human factors.
e 3 6   The employer did not ensure that the PHA addressed human factors such as:
The number of alarms and warnings that board operator can handle in an emergency, or
The hazards associated with process operators isolating critical and emergency valves in an emergency.
e 3     The employer did not establish a system to promptly address the process hazard analysis team's findings and recommendations, as shown, for example, in an audit conducted in 2002 in which twenty three findings from a 1996 audit were identified as not resolved.
e 3     The employer failed to establish a system to promptly address the process hazards analysis team's findings and recommendations and to assure that the recommendations were resolved in a timely matter:
Significant risks were not resolved in a timely manner with recommendations not completed within the 3-5 years, depending on risk class, specified by employer's procedures. Furthermore, the time frames developed by the employer do not meet OSHA and industry standards. In addition, PHA recommendations were not completed within their assigned completion dates.
e 3     The employer did not resolve recommendations of the 2000 PHA Revalidation until November 1, 2007.
e 5     The employer did not promptly address and resolve a recommendation on the PHA on heat trace and insulation of Condenser outlet piping to reduce the likelihood of low spots freezing, which could result in overpressure of a Solvent Regenerator.
The employer did not assure that PHA recommendations are resoved in a timely manner, including:
Completing review of limit of operations table for piping systems per LOT program.
Completing updating Limit of Operations Table (LOT) for equipment/vessels per LOT program.
Adding missing information to Unit P&ID's (e.g. equipment design specification, exchanger duty information, line numbers equipment numbers), and of line rating sheets to provide missing or update incorrect process information.
2003 PHA recommendations cited were not completely resolved until August, 2007.
The employer did not promptly address and resolve the node on the initial PHA dealing with review of the design and location of the control building to provide safe haven for control operators in event of a fire or release.
e 5     The employer did not assure that recommendations identified in PHA's for the refinery were resolved in a timely manner and the employer did not document the actions to be taken for resolution of PHA recommendations. Subsequent requirements, such as developing a written schedule for completion of actions and communication the of actions to affected employees, were also not completed as required.
e 5     The employer did not establish a system to complete actions recommended by the process hazard analysis team in a timely manner:
Actions items developed from a 2002 Process Hazard Analysis revalidation were not completed in a timely manner in that an action item to re-rate and/or protect a steam coil had not been completed as of November, 2007.
A finding from the 2002 PHA stated that carbon steel specified for equipment and pipe is not good for below -20 deg F when propane equilibrium temperature is -40 deg F at atmospheric pressure. An action item to review the pipe and equipment specification for low temperature service was not complete as of November 2007.
A finding from the 2002 PHA stated that there was a potential for lack of understanding by unit personnel of valve action upon failure. An action item to determine the failure position of each control valve, inform unit personnel, and include on the unit's P&ID's and this item has not been completed.
e 5     The employer failed to address recommendations related to the siting of occupied structures including, but not limited to:
The Old Crude Unit Control Room.
The Old Alky Control Room.
e 5     The most recent PHA listed items that have not been completed since the previous PHA, possibly resulting in loss of containment or the formation of a vapor cloud resulting in an explosion. These included:
Adding a charge pump suction temperature to the DCS with alarm and local indication to avoid cavitation and pump failure.
Installing an independent low level alarm on a storage tank to avoid hot vapors reaching a storage tank.
Converting a local temperature indicator on a propane vaporizer to local indication plus board indication with alarm and control, and addition to the critical process variable list to avoid liquid propane feed to heater burners.
e 5     The employer had not completed or document actions recommended by the its process hazards analysis teams in an expeditious manner including:
Adding a bypass around the lift stream control valve so that the control valve can be taken out of service.
Indicating the motor amperage of the main and auxiliary air blowers.
Reviewing the current technology of hydrocarbon detectors and considering one for the cooling tower if its is acceptable.
Reviewing the relief valve sizing basis for the Propane Treater to ensure protection during a chemical reaction with HP acid.
Adding a temperature sensor on the external surface of the Iso Treater.
e 5     The employer did not resolve findings and/or recommendations in the PHA conducted for the Hydrocracker. These findings were determined inappropriately to either not be related to safety or were clearly mis-classified under the employers risk matrix to be of such a low priority that no action was deemed necessary to correct the hazards:
Inadequate means to communicate between the control room and outside operator during emergency and routine operation. This issue was designated only an operability issue and not related to safety.
The PHA noted that initial training was insufficient. " Consider completion ( review and publication) of an up to date training manual which includes a description of routine tasks and checklists for field use." The company decided that no action was necessary although such training complies with RIM requirement.
The PHA noted that step-up training is insufficent, with consequences listed as "Operator error, potenital fire, explosion and death"
The PHA noted that recertification training is insufficent.The original intent of asking the operator if they wish retraining and or rotation has been largely ignored. Consequences listed as "Operator error, potential fire, explosion and death." No action was taken because this issue was given a low risk factor.
The PHA note that there are 40 psi relief valves for turbines which discharge in areas where they could strike employees.
The employer did not resolve finding and/or recommendations in the PHA conducted for the Alkylation unit. These findings were determined to be either not related in safety or to be of such a low priority that no action was necessary to correct the hazards.
The PHA noted that, "There is potential to have hydrogen sulfide exposure while changing out the East/West Butane-Butylene Strainers" This issue was given a low risk factor and no action was taken.
The PHA noted that if the Thilex Sand filter was opened under pressure a butane cloud resulting in fire or explosions could be formed. This issue was given a low risk factor and no action was taken.
The PHA noted that if "the setup of the 850 Micron hydrogen strainers is not done properly (e.g. loose connections, filter not tight) This could result in a release of hydrogen to the atmosphere with the potential to have a fire/injury." This finding was given a low risk factor and no action was taken.
In the PHA it was noted that, "If the level taps on the acid settling drum are left blocked in after flushing, a false level will be sent to the level controller. This can cause acid carry over into the effluent treating system and could result in a release resulting in a fire or explosion. This finding was given a low risk factor and no action was taken.
The PHA noted that if a two inch valve is left open after draining a vessel there is a potential for acid backflow.
This could result in corrrosion resulting in damage to piping and vessels and could cause releases of butane/acid and possible fires and explosion.This finding was given a low risk factor and no action was taken.
The PHA noted that it is possible to open up to the flare system rather than opening up to the desired vessel causing corrosion which could cause releases, fires or explosions.This finding was given a low risk factor and no action was taken.
The employer did not resolve a serious hazards identified in the PHA's involving entry by employees into the cooling tower sumps to remove and replace the pumps for repair.
e 5     The employer did not promptly resolve findings that relief devices may not have been designed in accordance with RAGAGEP with respect to having a relief evaluated to be undersized for the external fire case scenario. The recommendation from a hazards analysis was to increase the size of the relief valve from 3K4 to a 3L4 or to add insulation to the vessel.
Also with respect to an RV discharging at an elevation below the flare header, which could allow condensation to damage the relief device and related piping. The PHA recommendation was to raise the relief device above the discharge header and replace the existing piping with larger diameter piping.
And with respect to an RV evaluated to be undersized for several relief scenarios. THe recommendation from a PHA was to increase the size of the relief valve from 3K4 to 3L4.(2 instances)
And with respect to an RV evaluated to be undersized for protection against the loss of cooling and power failure relief scenarios.
And with respect to a KO drum evaluated to not be able to provide adequate retention time to prevent liquid carryover to the flare.
The employer did not promptly address facility siting concerns identified in a PHA that employees working in an office building were not protected in the event of significant overpressure from flammable hydrocarbons gas/vapors/explosions with approriate blast resistant construction or other protective means.
The employer did not promptly address facility siting concerns identified in the PHA for 4 Control Rooms, a contractor garage, and a locker room in that employees working in the buildings were not protected in the event of significant explosive overpressures.
e 5     The employer did not establish a system to promptly address the PHA team's findings and recommendations:
The employer has not resolved an action item to protect a vessel from pump dead-head conditions.
The employer has not resolved an action item to protect a heater from blocked-in damage.
The employer has not resolved an action item from the 1997 and 2005 facility siting analyses, in that occupied facilities, such as but not limited to, the unit control room, have not been addressed.
The employer has not resolved an action item from the 2004 flare study, regarding radiant heat, which can be up to 2320 Btu/Hr-ft2, in the vicinity of the base of the flare stack.
3 6     Process hazard analyses were not updated and revalidated at least every five (5) years.
e 6     The PHA did not address fireproofing critical emergency block valves (EBVs) installed in areas classified as fire zones where approximately nine EBVs and their associated power lines are not fireproofed.
e 6     The employer did not ensure that the process hazard analysis addressed the effect of throughput increases in 1995 and 2000 on pressure relief devices.
e 6     The PHA failed to consider potential constraints on the facility's relief system capacity caused by increased production throughput.
e 6     The employer does not conduct an adequate FCCU PHA revalidation in 2006, in that process safety information relating to relief systems was for a 1990 lower throughput or production rate.
e 7     The employer did not retain PHAs, updates, or revalidations for each covered process, as well as the documented resolution of recommendations for the life of the process, specifically:
The employer did not retain a node addressing a column feed system, including the still preheater, of the initial 1993 process hazards analysis.
Employer did not retain a section of the initial 1993 PHA for the UDEX unit for the life of the process.
f 1     The employer failed to develop and implement operating procedures for emergency operations, emergency shutdown, operating limits, all safety and health considerations and safety systems and their functions for the blowdown system.
f 1     The employer did not develop or implement written procedures that provided clear instructions for safely conducting activates in the covered process including but not limited to:
The use of chains or car seals to ensure that block valves on pressure relief lines were kept in the open position.
The Crude Unit blowdown system in all operating procedures of that unit.
The Coker Unit blowdown system in all operating procedures of that unit.
The Cat Unit blowdown system in all operating procedures of that unit.
f 1     The employer did not develop and implement safe work practices for the control of hazards during operations after the observation that a seal failure indication light was lit on a pump.
f 1     The practice of using a water hose for cooling process equipment did not reflect the operating procedures.
f 1     Procedures were not developed for switching lube oil pumps on a compressor, resulting in the shutdown of the compressor and causing a mechanical integrity incident.
Procedures were not followed when a fan covered by a tarpaulin due to permitted repair work was engaged because additional cooling capacity was needed to prevent a release of hazardous chemicals.
f 1 1   The employer did not ensure that operating procedures were developed for each operating phase in two blowdown drums.
f 1 1 b The employer's written operating procedures (for the unit) did not include the normal operation of three processes to ensure that the operating limits for safe operations were not exceeded.
f 1 1 b Employer's written operating procedures did not address normal operations in units including:
Crude unit blowdown system.
Coker unit blowdown system.
Cat unit blowdown system.
f 1 1 b The employer did not develop detailed written operating procedures for normal and potentially hazardous task in the process units, including tasks such as checking level in the Blowdown Drum and draining off sour water/condensate to the sewer up, mixing corrosion inhibitor with raw gasoline at multiple storage pots, rerouting flow with an elevated bypass valve, hauling acid-soluble oil by tank truck from the HP Alky Unit and manually offloading at the gas oil rack for pumping to storage, operating the dispersion steam horns for preventing the ignition of flammable hydrocarbon chemicals escaping from atmospheric relief valves ( e.g. during lightning storms).
f 1 1 b A procedure was still in the procedure manual while the process had been discontinued.
f 1 1 c No temporary operating procedure for supplemental cooling system.
f 1 1 d The employer did not develop procedures, to address emergency shutdown during situations in which there are upset or emergency operations at the Flare.
f 1 1 d The employer did not ensure that the written operating procedures addressed the conditions under which emergency shut-down is required, and the assignment of shutdown responsibilities to qualified operators to ensure that emergency shutdown is executed in a safe and timely manner.
f 1 1 d Emergency Shutdown Procedures did not designate and assign authority for shutting down the FCC and Gas Concentration Unit.
f 1 1 d Emergency shutdown procedures did not indicate the conditions under which the procedures needed to be implemented.
f 1 1 d Emergency Shutdown procedures did not specify the conditions that require an emergency shutdown.
f 1 1 d For the Crude Unit, the employer did not develop and implement written emergency shutdown procedures (ESPs) that addressed conditions that require emergency shutdown, and the authority and responsibility assignments, including, but not limited to:
Failure of the main flare system.
Plane crash in or near the facility (located near an airport).
A high liquid level in the blowdown system.
ESPs that had been developed did not address operators assigned authority to shutdown a process or qualifications required of operators who were expected to shutdown the process during an emergency.
f 1 1 d Written emergency shutdown procedures did not address the conditions under which an emergency shutdown would be required.
f 1 1 d Emergency shutdown procedures do not assign shutdown authority to a specific operator(s) in the event of an emergency.
f 1 1 d The employer did not specify, in the Emergency Shutdown Procedures (ESP), which qualified operators were authorized to shutdown the units.
f 1 1 d The employer does not ensure that emergency operation procedures were adequate, in that the procedure for loss of power does not include, steps required to verify that a pressure control valve is opened to relieve excessive pressures to the flare, nor does it include steps required to verify the valve is re-closed while preparing process equipment for startup following the power loss shutdown.
f 1 1 e The employer did not develop emergency procedures to address emergency operations during situations in which there are upset or emergency operations at the Flare.
f 1 1 e Written operating procedures did not contain emergency operating procedures.
f 1 1 e Written operating procedures for Main Flare operations did not contain specifications for transition from normal operations to emergency operations when the Main Flare loses flame.
f 1 1 e For the Crude Unit the employer did not develop and implement written emergency operating procedures (EOPs) that identified the initiating or triggering conditions that require emergency operations.
f 1 1 f The employer did not ensure that procedures adequately addressed normal shutdown, including for the wet gas compressor and a bypass procedure for catalyst change.
f 1 1 g FCC startup procedures did not include padlocked-open valves around exchangers; the procedure's identification of a PSV conflicts with the P&ID; the procedure does not reflect that certain equipment has been abandoned-in-place, and a reference to a pad-locked-open valve is duplicated.
f 1 2   The plant's written operating procedures did not address the operating limits.
f 1 2   The employer failed to ensure that the normal operating procedures included operating parameters and consequences of deviation for high flow into the unit, with respect to the potential constraints on the relief system.
f 1 2   The written critical variable procedure was not adequate in that it did not list the following:
The steps required to correct or avoid deviation.
The trigger points from normal to emergency operating procedures.
Acceptable safe operating upper and lower limits for temperatures, pressures, and flow on all equipment listed in the unit.
f 1   The employer did not develop and implement written procedures that provide clear instructions consistent with process safety information that address operating limits.
The procedure for variable limits was not consistent with information lists on the control board/DCS system.
f 1 2 b Operating procedures do not address the steps required to correct or avoid deviation beyond the operating limits, including, but not limited to:
Crude unit blowdown system.
Coker unit blowdown system.
Cat unit blowdown system.
Crude unit emergency operating procedures.
f 1 2 b The employer's written operating procedures did not address the steps required to correct or avoid deviation beyond the operating limits including, but not limited to:
Crude Unit blowdown.
Coker Unit blowdown.
Cat Unit blowdown.
Crude Unit procedures.
f 1 2 c For the Crude Unit the employer did not address the operating limits including, but not limited to:
Emergency operating procedures the entry/triggering point for when the EOPs were applicable or required.
In normal operating procedures operating limits did not identify exit/trigger point for when the NOPs were applicable.
f 1 2 d The employer's written operating procedures did not address the consequences of deviation beyond the operating limits including, but not limited to:
Crude Unit blowdown.
Coker Unit blowdown.
Cat Unit blowdown.
Crude Unit emergency operating.
f 1 2 a Operating procedures do not address the consequences of deviation beyond the operating limits, including, but not limited to:
Crude unit blowdown system.
Coker unit blowdown system.
Cat unit blowdown system.
Crude unit emergency operating procedures.
f 1 3   Many of the employers written operating procedures did not address all of the safety and health considerations, including properties and hazards of the chemicals used in the process, precautions necessary to prevent exposure, control measures for physical or airborne exposure, and special or unique hazards.
f 1 3   An emergency shutdown procedure for loss of cooling water was not reviewed to show operating practices were current in that the procedures sill included a column which was removed from service over one year ago
f 1 3   The person listed as technical manager for approval no longer works for the company.
f 1 3   The employer failed to ensure that the most recently certified normal operating procedure for the unit included operating parameters and consequences of deviation for high product flow into the unit, with respect to potential constraints on the relief system.
f 1 3 a The employer's written procedures containing the steps for each operating phase did not address the properties of, and hazards presented by the chemicals used in the process in that the procedure for "Bypassing for Catalyst Change" the provided section used for cautionary information to operators were not filled out. The "WARNING" and "CAUTION" blocks were left unfilled when they should have included any potential for injury, exposure, or danger.
f 1 3 e The employer did not ensure that its written operating procedures in the De-Coker unit address safety and health considerations of special or unique hazards such as but not limited to the hazards associated with working in the vicinity of the base of the flare stack where radiant heat can be up to 2320 Bru/Hr/ft2.
f 1 4   The employer did not ensure that the written operating procedures addressed the requirements for safety systems and their functions for processes such as atmospheric blowdown quench water systems.
f 3     The employer did not certify annually that the operating procedures were current and accurate.
f 3     Operating procedures were not updated to reflect changes:
An emergency Operating Procedure instructs the Zone Operator to open the chain wheel valve on the emergency dump line to a vessel no longer in service.
Normal Operations steps require the operator to blowdown and take a water sample from the CO Boiler, a unit no longer in service.
An Emergency Operating Procedure's initial explanation information refers to trim coolers shown on the P&ID to be out of service.
f 3     The employer did not review operating procedures as often as necessary to assure that they reflect current operating practice, and did not ensure that the annual certification for operating procedures was adequate, including procedures in the de-coking unit.
f 4     The employer did not ensure that safe work practices were developed and implemented for employees and contractors employees.
The employer did not assess, develop and implement work practices and procedures to monitor traffic going into the crude unit. Employees and numerous contractors travel in and out on a daily basis.
f 4     The employer did not develop and implement safe work practices for controlling the hazards, such as fire and explosions, due to the operation of non-classified vehicles and diesel-powered air compressors in Class 1, Division 2Group D hazardous locations.
f 4     The employer developed but fa br> roadways adjacent to operating units that contain flammable or combustible materials, in that restricted access barricades and signs were missing from roadways used as access into the process unit.
The employer did not develop a safe work practice for contract employees entrance/ exit to/ from the covered process areas in that neither the Safe Work Permit system nor the unit log book accounted for all contract employees working in a PSM covered process unit.
f 4     The employer failed to ensure that safe work permits were obtained and followed contract employees nor were they required to isolate and drain a line they were removing
f 4     The employer failed to ensure reconnecting a temporary process drain line.
f 4     The employer failed to ensure that entrance into process units for contract, maintenance, and other support personnel was controlled. The company did control entrance at the gates of the refinery, but did not control entrance into actual process units.
f 4     Lockout/tagout did not include equipment specific procedures showing employees how to shutdown, remove residual and/or stored energy, and where to isolate each energy isolation point for equipment.
f 4     Ad hoc procedures developed by management personnel at the time of maintenance work were never reviewed prior to the work beginning.
f 4     The employer did not ensure that contractor followed the unit policy for ensuring accountability of contractors in the unit, in that the fugitive emission contractor did not sign in at the proper place on the sign-in board.
f 4     The employer did not ensure that there is a safe work practice for additional PPE and access control to areas around the flare stack where there is a potential for radiant heat of up to 2320 BTU/Hr-Ft2.
f 1 4   The employer did not ensure that the written standard operating procedures (SOP's) listed the safety systems and their functions for pressure vessels.
g 1 1   The employer did not initially train each employee involved in operating the process on the operating procedures, normal limits and upset limits for the crude limits.
g 1 1   The employer did not initially train each employee involved in operating the HCU1 unit on the details of quench water initiation for blowdown in the unit.
g 1 1   The employer did not adequately train employees performing operator daily rounds inspections on the safe work practices to be followed and the hazards associated with pump seal failures.
g 1 1   Operators were not adequately trained on written operating procedures such as emergency operating procedures.
g 1 1   Operators were not adequately trained on written operating procedures that identified who was authorized to shutdown the unit in the event of an emergency.
g 1 1   Operators were not provided training on when to shutdown the HVAC system to prevent the entry of hazardous materials into the (FCCU) Alkylation Control Room.
g 1 1   The employer did not ensure employees working as process operators are initially trained in specific safety and health hazards associated with the process, emergency operations including shutdown, and safe work practices applicable to employee's job tasks.
The employer does not ensure that refresher training is provided to process operators, or include them in determining the appropriate frequency of the refresher training.
g 1 1   The employer did not ensure that employer were trained on the specific safety and health hazards relating to working in the vicinity of the base of the flare stack, where the radiant heat can be up to 2320 BTU/Hr-Ft2.
g 2     The employer did not provide refresher training at least every three years to each employee involved in operating a process to assure that the employee understands and adheres to the current operating procedures of the process.
g 2     The employer did not ensure refresher training relating to operating procedures was being conducted at least every three years in several units.
g 3     The employer did not verify understanding of the operating information in the FCC revamp training packets.
h 2 1   The employer does not evaluate all contractor safety performance and programs, including sub-contractors and some preferred contractors.
h 2 2   The employer did not inform contract employers of the known potential fire, explosion, or toxic release hazards related to the contractor's work and the process contractors performing welding operations ignited flammable gas emitted from a dirty seal oil demister vent.
h 2 2   The employer did not provide health hazard information to a contract employer in that the contractor did not know there had been a hydrofluoric acid release alarm and that the company had not conducted air monitoring to ensure that hydrofluoric acid and hydrocarbon concentrations were within acceptable levels to allow re-entry into the area.
h 2 4   Contractor supervisors were allowed to sign for work permits at unit control houses but individual employees on the work crew remained unaccounted for at process units.
h 2 4   The employer did not ensure that individual contractor employees were accounted for in the event of an emergency in the FCC and Alky units.
h 2 5   The employer did not periodically evaluate contractors to ensure that they were in compliance with process safety management. No contractor audits had been performed in the last 3 years
h 2 6   The employer did not maintain a contract employee injury and illness log related to contractor's work in process areas; in that it did not contain a employee's lost time injury suffered in the Crude unit, a PSM process area.
h 2 6   The employer did not maintain a contract employee injury and illness log related to contractor's work in process areas.
h 3 2   The contract employer did not assure that each contract employee was instructed in the known potential fire, explosion, or toxic release hazards related to his/her job and the process, and the applicable provisions of the emergency action plan. This relating to the ignition of flammable gases by welding operations.
i 1     The employer did not establish and implement written procedures to manage changes to process chemicals, technology, equipment, and procedures; and changes to facilities that affect a covered process; for example, there was no management of change accomplished when the through put quantities changed, as well as when the new crude tower was installed.
i 2 2   The employer did not ensure that safety, operating, maintenance, and emergency procedures were in place and adequate prior to the introduction of highly hazardous chemicals to a process:
Pipelines were not labeled as specified in the pre-startup safety review.
Instrumentation was not labeled as specified in the pre-startup safety review.
Operating procedures were not adequately updated as specified in the pre-startup safety review.
Operating procedures were not completed as specified in the pre-startup safety review.
i 2 3   The employer failed to confirm that the facility siting checklist and human factors checklist from the previous PHA were completed before introducing HHC to the process.
i 2 4   Employees were not adequately trained on a vaporizer in the FCC unit.
j 2     The employer did not develop an inspection procedure to inspect for "corrosion-under-insulation" on pressure vessels.
j 2     The employer had not developed a Mechanical Integrity program for Corrosion Under Insulation inspections for critical piping containing large quantities of flammable materials.
j 2     The employer did not establish and implement written procedures to maintain the on-going mechanical integrity of process equipment, including but not limited to procedures addressing:
Inspecting pressure vessels with integrally bonded liners.
Corrosion under insulation inspections for pressure vessels and piping.
Determining the safe operation of equipmentsuch as pressure vessels and piping after a temporary repair.
Monitoring recommending follow-up inspections on equipment such as pressure vessels or piping that are operating with a deficiency.
Addressing anomalous readings pertaining to metal thickness in pressure vessels and piping.
Updating the mechanical integrity database within a short time frame after a pressure vessel or piping inspection to determine if the equipment has exceeded the retirement thickness or if the inspection interval needs to be reduced.
Inspecting non-metallic linings in pressure vessels.
Inspecting Injection points for corrosion inhibitors, emulsifiers,anti-foam,methanol,and etc, into the refinery piping.
j 2     The employer did not establish and implement written procedures to maintain the on-going mechanical integrity of process equipment, including:
Inspections for non-metallic linings of pressure vessels.
Inspections for integrally bonded linings such as strip plating or plate lining of pressure vessels.
Procedure requiring periodic internal as well as external (on-stream) inspection of pressure vessels with integrally bonded liners.
Thickness measurement frequency for pressure vessels.
Thickness measurement strategy for identifying TML''s on pressure vessels and for determining the representative number of thickness measurements performed for internal and on-stream inspections.
Thickness measurement strategy for identifying TML's on piping and for determining the representative number of thickness measurements on each piping circuit.
Procedure for anomalous data related to thickness growth recorded in piping.
Identifying person(s) permitted to conduct re-rating of pressure vessels.
Information on alterations of vessels including welding qualifications and certifications for adding a nozzle to a heat exchanger.
j 2     The employer did not write procedures to maintain the on-going mechanical integrity of process equipment in the refinery such as, but not limited to:
Inspection procedures for non-metallic linings of pressure vessels.
Inspection procedures for integrally bonded liners such as strip or plate lining of pressure vessels.
Procedure requiring the next scheduled inspection after on-steam inspection to be an internal inspection for pressure vessels with integrally bonded liners.
Thickness measurement frequency for pressure vessels.
Condition monitoring strategy for pressure vessels and for determining the representative number of thickness measurements performed to satisfy requirement for internal and on-steam inspections.
Thickness measurement strategy for the frequency of measuring each thickness measurement location (TML) on piping circuits.
Procedure for anomalous data related to thickness growths recorded in piping with criteria as to what would be considered an increase from a previous thickness measurement.
j 2     The employer did not establish and implement written procedures to maintain the on-going mechanical integrity of process equipment:
The employer did not have procedures that identified and documented critical equipment to ensure that proper spare parts and/or spare equipment were available.
The employer did not implement a written mechanical intergrity inspection program that included relief devices.
The employer had not established and implemented a written program procedure for establishing thickness measurement locations (TML) for injection points and mixing points on piping.
The employer had not established and implemented a written procedure for managing permanent repair and replacement information related to the mechanical integrity of piping circuits in the risk based mechanical integrity program. Work processes have not been established and implemented to capture, document and maintain material specifications, installation related information (welding processes, personel documentation, qualification,certifications, etc) and physical location for the repair.
The employer did not implement local and corporate policy regarding identified equipment deficiencies for fixed equipment and had not established and maintained written procedures, work practices and job duties to track temporary repairs, track completed repairs, modify inspection plans and follow modified inspection plans.
The employer had not established and implemented a written procedure for the analysis of incoming data from inspection and testing reports for fixed equipment. Inspection and testing reports must be analyzed to identify and disposition rejectable indications, such as thickness monitoring locations with data below minimum thickness levels.
The employer had not established and implemented a written procedure for managing the temporary repair of piping circuits, such as the use of the pipe clamps for leak control, which is common at the refinery.
The employer had not established a written program for implementing and managing TMLs for piping circuits and pressure vessels.
The employer had not implemented a system for TML identification, designation, and reference on isometric sketches for use in field.
j 2     The employer did not ensure that mechanical integrity inspection procedures for relief devices were implemented at the facility. Multiple instances of relief valves were found that were past their individual inspection intervals for inspection and testing in the Hydrocracker and Alkylation Units.
j 2     Written mechanical integrity program procedures were not developed for process instrumentation and controls including, but not limited to, monitoring devices and sensors, alarms, interlocks, emergency shutdown systems (i.e. safetyinstrumented systems, safety shutdown systems, protective instruments systems, and safety interlock system), such as:
Emergency steam to the riser control valve and associated equipment.
The spent catalyst slide valve.
Non-destructive evaluation (NDE) written procedures for pressure vessel and piping inspections.
j 2     The employer did not have written procedures for inspections and tests of critical instrumentation in accordance with RAGAGEP in the DeCoker and Alkylation units, such as, but not limited to, inspections and tests procedures for critical instrumentation that did not follow RAGAGEP. ISA S84.01 was referenced in the MI program, but was not being followed.
j 3     The employer did not train inspectors involved in maintaining the on-going integrity of the process piping and pressure vessels in the employer's mechanical integrity program and procedures applicable to the employees' job tasks.
j 3     The employer did not train vibration analysts involved in maintaining the on-going integrity of rotating and reciprocating equipment in the employer's mechanical integrity program and procedures applicable to the employees' job tasks.
j 3     Each employee, including operators, supervisors, coordinators for contractors, and contractor's employees involved in a line break were not adequately trained on specific lockout/tagout procedures to ensure that each employee performed their job tasks in a safe manner.
j 4 1   A hot relief high temperature alarm on a disengaging drum was mistakenly removed from the critical instruments program. The critical instrument had not been inspected since 2003.
j 4 1   The employer does not ensure that thickness monitoring for process equipment including, a piping circuit, is conducted in accordance with the MI inspection program.
j 4 1   Crude/vacuum unit pressure vessels had not received an inspection at the frequency required by the employer's mechanical integrity inspection program.
j 4 1   The employer failed to ensure that inspection testing was conducted on a heat exchanger on a five year inspection interval, as indicated by the vessel inspection plan.
j 4 1   The employer failed to ensure that ultrasonic testing was conducted on a heat exchanger nozzle.
j 4 1   Inspections and tests were not performed on process equipment to maintain its mechanical integrity:
The employer did not ensure that relief devices and systems including the blowdown drums and vent stacks were included in a mechanical integrity inspection program. There was no inspection plan for the drum/stack and there had not been any non-destructive testing since 1992.
The employer had not performed radiographic or ultrasonic testing for internal corrosion inspections on piping circuits in corrosive service.
j 4 1   The employer does not ensure comprehensive thickness readings were being conducted for an FCCU reactor.
j 4 1   The employer did not perform tests in the De-Coker and Alkylation units to maintain their mechanical integrity such as but not limited to control valves and process critical instruments, including critical alarms, critical indicators, and critical controls.
j 4 2   Inspections ports on insulated piping were not adequately plugged after inspections were performed. Excessive corrosion could occur due to the open inspection ports.
j 4 2   The employer did not follow RAGAGEP such as API 510 and API 580, when they established a 10-year inspection and testing interval for twenty safety relief valves.
j 4 2   Inspections and testing procedures did not follow RAGAGEP:
Safety valve failed to pop at its set pressure due to fouling. The valve was repaired and returned to service with the same 6 year inspection frequency. API 510 6.6.2.3 requires that the inspection interval shall be reduced when a pressure relieving device is heavily fouled.
j 4 2   The employer did not follow RAGAGEP by not ensuring an adequate number of TMLs and not conducting a representative number of thickness measurements for internal and on-stream inspections.
j 4 2   The employer did not follow RAGAGEP by not ensuring an adequate number of piping TMLs and not conducting a representative number of thickness measurements.
j 4 2   The employer did not follow RAGAGEP when it failed to resolve anomalous data for pressure vessels and piping, such as increasing thickness measurements over previous readings.
j 4 2   The employer did not follow RAGAGEP when it failed to compile necessary and complete piping inspection records and other inspection records related to thickness measurements for piping circuits.
j 4 2   In the (FCCU), the employer did not follow RAGAGEP when it failed in conduct thorough pressure vessel inspections.
In the Alkylation and FCCU, the employer did not follow RAGAGEP when it failed to conduct thorough piping inspection by not testing at designed thickness measurement locations (TML) each time.
In the Alkylation and FCCU, the employer did not follow RAGAGEP when it failed to resolve anomalous data for piping.
Throughout the refinery, the employer did not follow RAGAGEP when it failed to inspect and test emergency shutdown systems and controls, such as but not limited to monitoring devices, sensors, alarms and interlocks. A program was not in place for Identification, testing and documenting the results of the tests for safety systems.
In the Alkylation unit, previous condition monitoring required inspection of the recycle cooler in 2005, which did not occur.
j 4 2   The employer did not follow RAGAGEP when it failed to inspect a pressure vessel at the designated thickness monitoring locations (TML) and in the number of thickness locations in the inspection plan.
The employer did not follow RAGAGEP for piping inspections when it failed to compile necessary and complete piping inspection records related to repairs and replacements for 3 piping circuit.
j 4 3   Pump vibration analysis was not performed according to the frequency established by the employer's mechanical integrity program procedure.
j 4 3   Thickness measurements were not performed according to the frequency established by the employer's mechanical integrity program procedure.
j 4 3   The frequency of inspections and tests of process equipment was not conducted as specified by the employer's master plan to maintain mechanical integrity; such as but not limited to: a cathodic protection system, and process analyzers.
j 4 3   The employer did not ensure that relief devices were inspected on a frequency consistent with the company's mechanical integrity program and with RAGAGEP (liquid propane, butane service).
The employer had not performed a piping inspection at the interval required by the risk based mechanical integrity (RBMI) database.
j 4 3   The employer did not meet its set inspection frequencies and determine and adjust its frequency of inspections and tests base on findings from prior operating experience.
Relief valves inspected beyond their set date based on a four year cycle:
The FCC Complex Blowdown Drum per the frequency set by operating experience.
The Crude Units Blowdown Drum per the frequency set by operating experience.
j 4 3   The employer did not ensure that inspections and test of process equipment occurred with the necessary frequency such as but not limited to:
The employer did not ensure that inspections and testing were being conducted for critical valves and pressure safety valves (PSV) at the Boiler House and at the De-Coker unit.
The employer did not ensure that the frequency of inspection and the testing of 2 Alkylation unit piping circuits were being maintained.
The employer did not ensure the frequency of inspection and tests for 2 piping circuits De-Coker unit.
j 4 4   The employer did not adequately document the inspection and test of interlocks in the FCCU in that the records did not identify the person who performed the test, the serial number or other identifier of the equipment.
j 4 4   Critical Piping circuit Item #1 did not have any inspection data established since the line was installed in 1972.
j 4 4   The employer did not document an internal inspection for two HF acid storage drums.
j 4 4   The employer did not document each inspection and test that had been performed on process equipment to maintain its mechanical integrity.
For profile radiographic testing performing in conjunction with an amine leak. The employer did not adequately document the information in the RBMI database.
The employer did not adequately document guided ultrasonic longwave (GUL) testing performed on piping circuit during the 2004 Crude unit turnaround. There are no inspection results, the testing data has not been captured and entered into the risk based mechanical integrity database and there is no information in the asset file for this piping circuit.
Historical piping inspection results and descriptions are not available prior to 2001, which does not provide the information needed to estimate accurate corrosion rates.
Profile radiographic testing performed on piping circuit was not documented.
j 4 4   The employer did not ensure that thickness readings were documented for an FCCU.
j 4 4   The employer did not ensure that inspection and testing documentation for function tests of emergency shutdown systems and safety critical controls were maintained.
j 4 6   The employer did not ensure that inspections and tests were adequately documented. Inspections and tests to determine if a leak had been repaired were not adequately documented or not documented.
j 4     The employer continued to use an undersized Blowdown drum for high volume relief of hot liquid/vapor hydrocarbons.
The employer also continued to use the blowdown drum after isolating the quench water system in late 2004 and did not use other means to assure safe operation.
j 4     The Employer did not correct deficiencies in the equipment that were outside acceptable limits including:
Gage glasses were not maintained in a clean/readable condition.
Exchanger supports were visibly deteriorated with concrete spalled off exposing reinforcing steel.
Fireproofing insulation removed from conduits powering EIVs in LUU4 was never replaced, and continued to fail critical instrument inspections.
j 4     The employer did not correct deficiencies in equipment that were outside acceptable limits, including:
Piping with thickness reading below the recommended minimum thickness ( 3 instances).
j 4     The employer did not correct deficiencies that were outside acceptable limits before further use or in a safe and timely manner:
Poly Charge Drum had heavy scale corrosion between the shell and support saddles with no determination as to the extent of the corrosion.
Toxic and flammable gas detectors located in duct work and the control room for H2S, and LEL were not in working order.
The relief valve for a depropanizer reboiler was set at 270 psi for protection of the tube side that has a maximum allowable working pressure of 150 psi. There was also inadequate over pressure protection in the event of a tube leak or rupture scenario.
The relief devices providing over pressure protection for a heat exchanger had set pressures of 540 and 600 psi, while the maximum allowable working pressure for the exchanger was 480 psi.
j 5     The employer did not correct deficiencies that were outside acceptable limits before further use or in a safe and timely manner, including:
Chains missing on chain operated valves.
TI not functional.
PI pegged at max.
PI damaged.
Sulfur mist control system not functional.
Corroded piping not repaired.
j 5     The employer failed to correct deficiencies in equipment to ensure safety in operation and maintenance before further use or in a safe and timely manner:
Three pressurized enclosures for electrical equipment did not have an alarm or did not have an alarm monitored at a constantly attended location.
Broken bolts in a flange connection on the Splitter Reboiler Exchanger were not repaired.
j 5     The employer did not correct deficiencies in equipment that were outside acceptable limits before further use or in a safe and timely manner:
A relief valve was evaluated to be undersized in regards to the external fire case scenario.
A relief valve was found to be discharging at an elevation below the flare header, which could allow condensation to damage the relief device and related piping.
A relief valve was evaluated to be undersized for several relief scenarios.
A relief valve was evaluated to be undersized for protection against the loss of cooling and power failure relief scenarios.
The Hydrocarbon Relief K.O. Drum was evaluated to not be able to provide adequate retention time to prevent liquid carryover to the flare.
j 5     The employer did not correct deficiencies in equipment that was outside of acceptable limits, in that, the employer had not resolved ultrasonic thickness data below minimums for the hydrocracker pretreater and profile radiographic thickness measurements below minimums for four circuits.
The employer did not correct deficiencies in equipment that was outside of acceptable limits, in that "illegal type bushings" were not identified and replaced when the facility was made aware of insufficient metal thickness after both OD and ID threading of the reducer through corporate instruction and findings of an incident investigation.
j 5     The employer did not correct deficiencies in its process equipment prior to continued operation, including:
The Crude Unit Blowdown Drum was documented with uncorrected mechanical deficiencies.
The FCC Unit complex Blowdown Drum was documented with uncorrected mechanical deficiencies.
The FCC Unit complex Blowdown Drum flare header piping sections were documented with uncorrected mechanical deficiencies (missing support shoes).
In the Crude Units and the FCC Unit complex, relief system piping including flare header and blowdown header piping, was documented with uncorrected mechanical deficiencies (exterior corrosion and degraded protective painting).
The old/secondary Flare stack was documented in poor mechanical condition (structural integrity concern).
j 5     The employer did not ensure that a heat exchanger was provided with proper safety relief for the dead heading condition.
The employer did not ensure that a heater was provided with proper relief for a blocked discharge condition.
The employer did not ensure that the HDPE underground piping for the HF mitigation system was designed properly, in that the designed pressure for the underground piping was less that the pump discharge pressure.
j 6 2   The employer did not check to ensure that the blowdown quench water systems could provide the design quantity of approximately 12,00.gpm of quench water when required.
j 6 2   Employer did not perform timely checks and inspections; specifically, positive material identification tests on adjacent piping circuits in similar service were not performed following failure of a piping system component.
j 6 3   The employer did not assure that replacement valves were suitable for applications including use of wrong materials for replacement valves on heaters.
j 6 3   The employer failed to ensure that the correct gaskets were used on various pieces of equipment, including vessels and compressors.
k 2     Safe work permits had vague descriptions of hot work and did not specifically identify the location and type of work to be done, increasing the likelihood that work could be performed on wrong or in-use equipment.
k 2     Safe work permits had vague descriptions of hot work and did not specifically identify the location and type of work to be done, increasing the likelihood that work could be performed on wrong / in-use equipment.
l 1     The employer failed to complete an MOC when the quench water system for a blowdown drum was taken out of service.
The employer failed to complete an MOC when normal startup procedures were changed requiring operators to startup at lower pressure.
l 1     A MOC was not established to asses all potential safety and health hazards associated with increasing the process throughout beyond the original design rate.
l 1     The employer did not ensure that a written MOC procedure is completed and implemented for changes including, but not limited to,
The 1994 rerate of reboiler.
l 1     The employer did not implement the management of change procedures to identify and evaluate all scenarios that might result in the discharge of hot, heavier-than-air, or liquid hydrocarbons from blowdown systems when changes to process chemicals, technology, equipment, and procedures were made that impacted the system. Including, but not limited to:
Crude Unit blowdown system.
Coker Unit blowdown system.
Cat Unit blowdown system.
Installing an engineering clamp around the asphalt to storage control loop.
l 1     An MOC covering the equipment, procedures, and P&ID was not written and implemented to remove a process column from service.
l 1     The employer did not perform an MOC for installation of Arkansas water coolers on the Splitter/Reboiler heat exchangers.
The employer did not perform an MOC for replacement of a check valve with a straight piece of tubing during
maintenance.
l 1     Management of change were not implemented when revisions were made to emergency shutdown procedures.
l 1     The employer did not implement written procedures to manage changes to a process including Temporary piping patches and at least one pipe clamp installed on blowdown header piping.
Changes were implemented without confirming that the pre-startup safety review (PSSR) had been performed prior to closing out the MOC procedure.
Modifying the fuel gas knock-out drain pipe.
Installing piping to an FCC feed preheater.
Installing a temporary compressor tube system in the FCC unit.
Installing larger trim on a stripper level control valve to address increased feed demands.
A special projects employee was working out of a Motor Control Center (MCC) building, reviewing written operating procedures. Temporary siting of this non-essential personnel did not consider positive air pressure, HC/HF gas detection, and blast resistance prior to performing the work.
l 1 1   An MOC was not performed for spectacle blinds modified on exchanger shell side block valves.
An MOC was not performed for fireproofing insulation removed from conduits powering EIVs.
An MOC was not performed when procedures changes to stop opening bypasses on regulators during reactor regeneration procedures.
An MOC was not performed when the hot relief header high temperature alarm on the water disengaging drum was removed from the critical instrument program.
The employer did not implement procedures addressing time limitations on temporary changes.
l 2 2   The employer did not perform management of change on changes that might result in the discharge of hot, heavier-thanair, or liquid hydrocarbons.
Management of change for capacity increase did not consider the potential increased load on the pressure safety valves.
Management of change for modifying the fractionator stripper did not cover the removal of the pressure safety valve.
Management of change with impact on Crude Unit blowdown system.
Management of change with impact on Coker Unit blowdown system.
Management of change with impact on Cat Unit blowdown system.
l 2 3   The employer did not ensure updated operating procedures were in place prior to implementing an MOC.
l 2 4   An MOC was not completed and resolved according to the timeline indicated on the MOC. Work was not begun until after the original completion date.
l 2 5   Employer made process changes without final review sign-off (authorization).
l 4     Process safety information not updated when changes made to relief systems, including:
Relief system pressure valves.
Removal of fractionator stripper PSV.
Crude unit blowdown system.
Carbon steel valves replaced with 590 Cr valves.
l 4     P&ID's were not updated to reflect the addition of a new PSV and changing the size of another.
The employer did not update process safety information (P&ID) when high and low alarms were added to temperature points in the control system.
l 5     The employer did not update operating procedures and practices when an alternative source of liquid hydrogen was connected to the unit.
m 1     The employer did not ensure that incident investigations were conducted for 30 incidents that could reasonable have resulted in a catastrophic release of chemicals in the workplace. Examples include, but are not limited to:
Pump seal fires (multiple).
Emergency Alerting System; Alarm not sounding.
Hydrocarbon liquid and vapor release (multiple).
Lost level.
Acid leaks (multiple).
Motor winding fire.
Pump fire.
Over pressure and release to flare.
Corrosion.
Pump tripped.
Packing blown out of pump.
Unit upset.
Tubing leak.
m 1     An incident which occurred in a Unit that could reasonably have resulted in a catastrophic release of highly hazardous chemical in the workplace was not investigated in that:
A pressure relief valve and the pipe around it developed a build up of ice due to propane leaking out of the pressure relief valve.
A process tower experienced a rapid pressure rise causing the pressure to be unstable which resulted in propane being vented to the flare for several hours.
m 1     The employer did not investigate each incident which resulted in, or could have resulted in, a catastrophic release of a highly hazardous chemical, including:
Product leaking from threaded area on level float chamber.
Sulfur fire.
Exchanger leaks.
Slide flange fire.
Heater leaks.
Acid/Isobutane leak.
FCCU fire.
Acid sampler acid release.
Injection line rupture.
Pipe rack butane release.
OVHD receiver leak.
m 2     The employer did not initiate an incident investigation within 48 hours for an HF acid leak in a nitrogen hose. The incident was not investigated until at least 27 days later.
m 2     The employer did not initiate an incident investigation within 48 hours for a leak found on the shell of a feed preheater.
This incident was not investigated until 12 days later.
m 3     The incident investigation team did not consist of at least on person knowledgeable in the process involved, including a contract employee, for:
An HF acid leak due to a bad weld fabricated by contractor.
Escape of C3 and C4 vapors during removal of reactor effluent piping by contractor.
An HF acid and hydrocarbon release when contractor loosened bolts on a flange to remove a blind.
A release of HF acid/hydrocarbons when contractor was removing temporary drain piping.
m 4     Incident investigations were not conducted, were incomplete, or did not contain required information, including incidents in the alky and crude units:
No investigation conducted on incident.
No causes determined, no action items, no description of repairs.
No causes determined/listed, no action items identified, no description of how this and similar incidents have been corrected.
No determinations of how cross-contamination occurred or how it was corrected.
No determination as to cause of failure and no corrective/preventative actions listed to prevent future occurrences.
No causes determined, no corrective actions identified.
m 4 2   Reports prepared at the conclusion of investigations of incidents which resulted in, or could reasonably have resulted in a catastrophic release of an HHC in the workplace, did not include the date the investigation began (6 instances).
m 4 2   The employer did not ensure that the date incident investigations is recorded on the incident investigation reports.
m 4 4   The employer did not ensure that the report prepared at the conclusion of the investigation of an incident which resulted in or could reasonably have resulted in a catastrophic release of HHCs in the workplace, included the factors that contributed to the incident.
Conditions/factors that resulted in 2 crude heater tube leak fires were not identified in the incident investigation report.
m 4 4   Reports for incidents which resulted or could reasonably have resulted in a catastrophic release of HHCs in the workplace, did not include the factors that contributed to the incident:
Incident report addressing smoke in a substation.
Incident report addressing operations exceeding design temperatures on a reactor and associated piping and equipment.
Incident report addressing fan shaft breakage.
Incident report addressing accidental shutdown of extractor reflux pump.
m 4 4   The report prepared at the conclusion of an incident investigation did not include the factors contributing to the incident, including, but not limited to, that the quality control procedure was not adequate or effective in assuring that contractor welding was acceptable.
m 4 4   The report prepared at the conclusion of an incident investigation did not include the factors contributing to the incident, including, but not limited to, that piping inspections, evaluations, and recommendations were not adequate or effective in detecting internal corrosion on a piping weld.
m 4 5   Recommendations were not established in a crude heater tube leak fire investigation report.
m 5     At least six reports did not have the corrective actions and resolutions documented.
m 5     An incident investigation report did not adequately document resolution to action items.
n       The employer did not establish a system to promptly address and resolve incident investigation report findings and recommendations, including:
Failing to evaluate all recommended pumps for back-up equipment/parts.
Failing to identify and remove all inappropriate threaded reducing bushings.
Not including specifications for gasket types on all blank lists.
n       The Refinery emergency action plan did not have an assembly point for level 1 evacuations to account for the employees in the affected unit(s)).
n       Employer's emergency plan did not instruct employees on how to distinguish between small and large releases and spills, and what employees' actions are required in both.
n The company had not planned for providing protection to employees from severe weather hazards including, but not limited to lightning and tornados.
n       The employer's emergency action plan (Integrated Contingency Plan) does define small releases but does not have procedures for handling small releases of hazardous substances other than crude oil.
The ICP requires Level One, Two, and Three Drills that have not been conducted since 2004.
Three (3) windsocks along roadways in process areas were observed during the walk around in torn and spent condition.
n       The employer did not ensure that its emergency action plan includes procedures to handle small releases and spills of hazardous materials.
o 1     The employer did not evaluate compliance with the provisions of 29 CFR 1910.119 at least every three years to verify that the procedures and practices developed under the standard were adequate and were being followed.
o 1     The employer did not audit pressure vessel inspection procedures & practices during compliance audits to verify that the vessel inspection procedures are adequate and are being followed.
o 1     The audit process is designed to satisfy NJ TCPA requirements and does not necessarily meet OSHA compliance audit specifications.
Accuracy of P&IDs was not adequately addressed during the compliance audit with numerous deficiencies noted by OSHA.
The audit did not adequately cover a review of hot work permits.
The audit did not adequately cover operating procedures with inaccuracies.
o 1     The employer did not audit or certify that they had evaluated compliance with the provisions of 29 CFR 1910.119 at least every three years for any of the identified safety systems in a poly unit.
o 1     The employer had not conducted timely and complete compliance audits within its required maximum three year interval of its March 2004 audit.
o 4     Refinery PSM audits failed to find programmatic mechanical integrity deficiencies in the facility in that the piping associated with pump seal flush lines is not inspected under any program.
Refinery PSM audits failed to find programmatic deficiencies with process hazard analyses findings that were not properly categorized per company's Risk Factor Matrix.
Refinery PSM audits failed to find programmatic mechanical integrity deficiencies in that blowdown drums and vent stacks were not adequately inspected as required in the mechanical integrity inspection program.
o 4     The employer did not determine and document an appropriate response to each finding from the June 2002 audit.
o 4     Pre-start up safety reviews/management of change tracking and approval not completed as identified in the last two compliance audits.
Incident investigations not promptly addressed as identified in the last two compliance audits.
Compliance audit finding that operating procedures were not being updated nor adequately addressed.
o 4     The employer did not determine and document an appropriate response for compliance audit recommendations, to ensure that all operating and maintenance procedures are updated.
o 4     The employer did not promptly address deficiencies indentified during the 2004 Compliance Audit namely:
That process technology information including safe upper and lower operating limits does not consistently exist for all covered processes.
That PHA revalidations for the covered processes were not performed in a timely manner.
That more than three years had elapsed since the previous compliance audit and audit findings from previous audits were not completed in a timely manner.
That documented maintenance procedures did not exist for all maintenance activities.
o 4     Appropriate responses to compliance audit findings not determined and documented:
Ventilation system designs for control rooms not available.
Process safety system information not available.
Equipment test and inspection frequencies not consistent with applicable manufacturers' recommendations and good engineering practices.
o 4     The employer did not ensure that PSM compliance audit findings were resolved prior to closing the action item as completed. Multiple relief devices were found to be past due for inspection/testing during the 2003 and 2006 compliance audits, however, the action items were closed out without ensuring that all relief devices were properly inspected, or that the management system was adequate to ensure that relief devices would not go past their inspection due date again.
The employer did not specifically document correction for the deficiencies in the compliance audit related to development of a management system for RBMI.