Rotating Equipment Integrity and Protection

In the ammonia industry, steam turbine driven process compressors are critical to production. Breakdown of this equipment can result in millions of dollars of property damage and significant production downtime. Effective asset integrity programs as part of process safety can reduce the frequency and severity of steam turbine driven compressor breakdowns to improve integrity and reliability. Adequate protection including equipment safety devices and fire protection in combination with loss prevention engineering solutions can reduce the equipment breakdown exposure and potential loss of containment that can result in a fire and/or explosion.

Mark Jackson

FM Global

Stephen McGhehey FM Global

Introduction otating equipment in the ammonia indus-try creates critical process bottleneck ex-posures which impact the availability and continuity of operations. A compressor

and/or driver (steam turbine, gas turbine, motor) breakdown can result in a production shutdown with extended downtime until the equipment is repaired or replaced and put back into service. This rotating equipment includes synthesis gas, ammonia, air and refrigeration compressor trains. A breakdown of these compressor trains can also result in a loss of containment and release of oil and/or process gases, resulting in a fire and/or ex-plosion, damaging the equipment and building, including adjacent compressor trains. This expo-sure can be mitigated through a combination of effective asset integrity programs including con-dition and performance monitoring to reduce the frequency of a breakdown; Adequate safety de-vices to monitor equipment and alarm and/or trip

to reduce the severity of operating conditions outside the equipment and process integrity op-erating windows; Fully trained operators to standard and emergency operating procedures; Viable equipment contingency planning and sparing to reduce the breakdown severity; and Adequate sprinkler protection to control the fire due to loss of containment. The effectiveness of these loss prevention solu-tions to reduce the impact of a breakdown to maintain plant availability, reliability and resili-ence is demonstrated by loss history.

Loss History FM Global and industry loss history demon-strates that steam turbine compressor train break-downs can result in significant business interrup-tion with the potential for loss of containment resulting in a fire. The following loss example and loss history illustrates this trend.

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A 1,600 tonnes per day ammonia plant suffers loss production for 9 months due to a mechanical breakdown of the synthesis gas steam turbine driven compressor resulting in a lube oil fire. The compressor train (22MW – 29,000 hp) had a mechanical breakdown of a geared coupling be-tween steam turbine stages (intermediate and high pressure) due to loss of lubrication. The geared coupling failed catastrophically, severing the lube oil lines. The intermediate steam turbine went into an overspeed condition. The overspeed protection system tripped the turbine. The re-leased lube oil ignited after contact with the hot steam turbine surfaces, resulting in a large, three-dimensional fire that spread from the oper-ating floor down to the basement, where a pool fire formed. The fire continued to burn out of control for 35 minutes as the lube oil pumps con-tinued to operate, feeding fuel to the fire. By the time the pumps were manually shutdown, the en-tire oil holdup in the main lube oil tank (10,000 liters – 2,641 gallons) was consumed in the fire. The compressor trains received lube oil from a common, single lube oil system. Physical damage was sustained to the steam tur-bine, compressor, building structure and roof, electrical switchgear and associated support sys-tems. There was no sprinkler protection on the synthesis compressor train or the adjacent trains in the compressor building. There was sprinkler protection around the lube oil skid, which had to be manually tripped as it did not operate. The critical path for restoring operations was inspec-tion and repair of the compressor train which had to be shipped out for repairs. Adjacent com-pressor trains required inspections for damage. Dedicated lube oil skids for each compressor train reduce the single point of failure exposure created by a single lube oil system for multiple trains. The ability to remotely isolate lube oil sys-tems in the event of a fire reduces the fire expo-sure present by shutting off the fuel source. Gross loss - $136,000,000 (Property damage and business interruption)

An analysis of FM Global’s compressor loss his-tory from a recent 10-year study showed the fer-tilizer industry represented 10% of the loss fre-quency (number of losses) and 34% of the gross loss severity (property damage and business in-terruption). Mechanical breakdown was the leading loss driver with over 50% of the loss frequency (Fig-ure 1). From these losses, over 32% resulted in a fire following due to the release of lube oil and/or process gas.

Component Damage Mechanism

Failure Mode

Blading/ Impellers

Surge Fatigue/ Cracking

Bearing/Shaft Vibration/ Thrust

Cracking

Coupling Misalignment Cracking/ Fatigue

Figure 1 – Compressor Mechanical Breakdown Loss History (1) An analysis of FM Global’s steam turbine loss history from a recent 10-year study showed the fertilizer industry represented 1% of the loss fre-quency and 11% of the loss severity. Mechanical breakdown was the leading loss driver from a fre-quency and severity according to this loss history (Figure 2).

Component Damage Mechanism

Failure Mode

Blades Fatigue /Corrosion/

Stress

Blade failure /Material

loss Rotor/

Stationary elements

Radial vibration

Rub/Misa-lignment/ Imbalance

Bearings Loss of lubrication

Bearing rub/ wiping

Figure 2 –Steam Turbine Mechanical Break-down Loss History (2)

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Process Hazards Elements of process safety are to be leveraged to mitigate rotating equipment hazards based on the process. Process knowledge determines equipment design, integrity operating windows, damage mechanisms, failure modes and safety devices. The process hazard analysis (PHA) is performed to identify, evaluate and control process risks, in-cluding potential causes and consequences of scenarios and the mitigating measures. This in-cludes risks from normal and emergency operat-ing modes to keep the equipment and process within the integrity operating window. Steam turbine compressor train key hazards in-clude;

• Surge, Vibration and Thrust • Misalignment • Loss of Lubrication/Rub • Temperature/Pressure Excursions • Corrosion/Erosion/Fouling • Fatigue/Stress • Overspeed

Equipment Protection Safety devices to trip dynamic compressors based on equipment manufacturer and industry standards can include the following (Figure 3). Protective Function Surge High differential pressure across process gas inlet filter Low process gas intake pressure at each stage High discharge temperature from each stage and/or compressor High vibration High temperature in thrust bearings pads or high axial deflection (reduced thrust-bearing clearance) High temperature at bearing oil drain or in journal bearing metal

Low lube-oil pressure at lubricated equipment bearing High oil temperature leaving oil cooler (to bearings) Low level for each seal-oil overhead tank or low seal oil differential pressure for each seal oil level.

Figure 3 –Dynamic Compressors Trips (1) Safety devices to trip steam turbine based on equipment manufacturer and industry standards include the following (Figure 4). Protective Function Overspeed Thrust and journal bearing axial/radial position Thrust and journal bearing high temperature Low oil pressure – Emergency lube oil pump Low oil level in the tank High temperature in thrust and journal bear-ings High and high-high boiler drum water levels Condenser low vacuum

Figure 4 – Steam Turbine Trips (2) Asset Integrity The asset integrity program is a process safety el-ement that plays a crucial role in ensuring rotat-ing equipment integrity and reliability through-out the life cycle. Effective asset integrity programs verify that the equipment and associ-ated systems are adequately designed, installed, operated, maintained and protected for the in-tended service. From the PHA, the equipment design, including integrity operating window and safe operating limits are established. Damage mechanisms and failure modes the equipment can experience through the life cycle are identi-fied based on the process. The inspection, testing and maintenance program at the core of asset integrity is developed to detect and evaluate the anticipated equipment damage mechanisms. Equipment is prioritized based on criticality to the process and the level of risk.

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Condition and performance monitoring com-bined with trended inspection data are analyzed and deficiencies are effectively managed. Fitness for service and remaining life are evaluated as the equipment is service aged. Key elements of the inspection, testing and maintenance program include but are not limited to the following;

• Safety devices/Protection systems • Surge systems • Vibration • Instrumental/Controls • Lube oil/Seal oil/Control oil systems • Stationary and rotating elements • Shafts/Couplings/Bearings • Steam turbine overspeed system • Steam admission and extraction/Non-re-

turn valves • Intercoolers/Aftercoolers • Stator guide vanes (axial) • Control/Isolation valves • Piping systems • Installation/Mounting

Surge protection systems, including anti-surge / control, bypass, bleed/vent valves and associated controller are recommended for inspection and testing every two years. This time based interval should be evaluated based on operating data in-cluding condition monitoring results, operating history, process parameters and equipment man-ufacturer recommended practices. Hydraulically controlled surge system valves require close at-tention including testing of the hydraulic fluid as degradation of this fluid can have a negative im-pact on valve operation. Annual calibration of in-strumentation, including pressure/temperature transmitters as part of the surge control system is recommended. Lube oil system pumps are recommended for test-ing quarterly. Systems with a separate emergency lube oil pump should be tested in accordance

with the equipment manufacturer’s recommen-dations based on the system configuration, but at least quarterly. As part of this testing, pump op-eration is confirmed by checking the outlet pres-sure, motor amperage or other means as appro-priate. Pressure sensors and low level alarms in the reservoir require testing and calibration in ac-cordance with the equipment manufacturer’s rec-ommendations at least annually. Where a pres-surized or gravity-type rundown tank(s) is used to supply emergency lube-oil, tank low-level alarm should be tested at least annually. For steam turbine overspeed protection systems, electronic systems have a higher degree of relia-bility as compared to mechanical bolt systems. Depending on service aging, operating condi-tions and maintenance history, mechanical bolt systems can be more susceptible to not function-ing as designed. Part of the risk reduction strat-egy for this equipment includes evaluating up-grading mechanical bolt systems to electronic. Electronic overspeed systems are recommended to be tested annually by a simulated test. For me-chanical bolt overspeed systems, annual func-tional testing is recommended to verify opera-tional integrity. Given the potential hazards with shutting the process down and de-coupling the steam turbine from the compressor to conduct a functional overspeed test for mechanical bolt systems, including stresses on the turbine impact-ing remaining life, condition based solutions are recommended to be fully implemented to reduce the risk. This includes; Compressor train safety devices are installed, maintained and functioning properly; Condition and performance monitoring (including steam purity monitoring) with results trended to demonstrate operations are within the equipment/process integrity operating windows; Favorable operating history, conditions and envi-ronment for the equipment; Effective asset integ-rity programs with acceptable inspection, testing and maintenance results trended over the equip-ment life cycle; Adequately trained operators to documented standard and emergency operating procedures; Viable contingency planning and

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sparing for key components. Upgrading mechan-ical bolt systems to an electronic overspeed sys-tem based on a redundant, failsafe 2oo3 voting logic design will improve reliability. Exercising of steam admission valves (i.e. throt-tle trip valves) and non-return valves (where so equipped for exercising) verifies operational in-tegrity of these safety devices. Weekly exercising is recommended, considering condition monitor-ing results. All overspeed system testing is to be performed to documented procedures by adequately trained personnel, with results trended. Dismantling, in-specting and refurbishing of steam turbine emer-gency stop (steam shut-off) valves, governor (throttle) valves, and steam extraction line non-return valves is recommended on a 5-year inter-val, or as necessary based on historical valve op-eration and operating conditions/results from the condition and performance monitoring. Steam turbine and compressor dismantle inspec-tions for time based programs are as recom-mended by the equipment manufacturer. Time based intervals are recommended at 7-years (or equivalent operating data). Condition and per-formance monitoring results require evaluation to fully assess dismantle inspection scope and in-tervals. For any dismantle inspection a foreign material exclusion program needs to be fully im-plemented and strictly enforced. Condition and Performance Monitoring As part of the asset integrity program, condition and performance monitoring evaluates process parameters as compared to the equipment manu-facturer’s guidelines to detect and trend degrada-tion. Monitoring includes evaluation of the op-erating conditions such as starts/stops, load, capacity and efficiencies. By detecting and trending deficiencies as they occur, conditions that lead to adverse operating conditions and breakdowns can be prevented.

Compressor train condition and performance monitoring is focused on the process parameters that are leading indicators of degradation. Mon-itoring typically includes operating conditions such as stops/starts, load, capacity and efficien-cies. Pressure, temperatures, gas composition, power, lube oil/seal oil, steam temperature, pres-sure, flow and purity are trended. Flows and speeds (corrected for inlet temperature and pres-sure) and pressure-ratios should be plotted on the compressor map with surge margins trended. Steam turbine thermal performance and steam path conditions can identify the factors contrib-uting to deterioration. This includes corrosion, deposits, solid particle erosion, increased clear-ances and/or internal damage. Steam purity monitoring provides data on steam impurity concentrations. This is an indicator of steam quality which must be sufficiently con-trolled to prevent turbine component damage such as pitting, stress corrosion cracking, and corrosion fatigue on stationary and rotating ele-ments. Steam samples should be taken and ana-lyzed daily and at each startup. Continuous mon-itoring systems include sodium and silica monitoring. Fixed vibration instrumentation measurements at critical points on the compressor train and/or manual readings are taken and trended to develop a vibration signature for the train. This data is an indicator of the process impact on equipment conditions, including loading profiles. Lube-oil/seal oil inspection, testing, and mainte-nance program include oil analysis quarterly to semi-annually (adjusted based on trended re-sults). Analysis includes detection of the pres-ence of excess moisture, metallic particles and contaminants with results trended. Operators Operators with adequate system and equipment knowledge who are well-trained to established standard and emergency operating procedures

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can significantly reduce the frequency and sever-ity of rotating equipment breakdowns. An effec-tive training program supported by management as part of the safety culture will help ensure op-erators are adequately trained to reduce the po-tential for errors to occur in response to normal and/or emergency/ upset conditions. As demon-strated by loss history, operator competency and the actions they take are critical to ensuring the safe operation of equipment and processes. Op-erator actions can make the difference between minor and major damage to equipment resulting in the shutdown of operations and significant business interruption (3). Only qualified operators should operate the equipment they have been specifically trained on. This is particularly true if the safety system de-sign is inadequate to allow operator actions to contribute to a breakdown. An example of the impact of operators is demonstrated by the loss example below. A 770 tonnes per day ammonia plant suffers lost production for 4 months due to a mechanical breakdown of the motor driven synthesis gas com-pressor. This was one of two ammonia plants on-site which was operated only when the ammonia market was favorable. The synthesis gas compres-sor train (15MW – 20,000 hp) suffered a thrust event due to the improper operation (closing) of the equalization (balance) valve between compressor stages as part of a startup procedure after a maintenance turnaround. The pressure differential created by the improper valve operation (estimated at over 1,000 psi – 69 bar) resulted in the thrust event. The axial move-ment of the train and resulting vibration caused the breaking of a synthesis gas piping, release of gas with a jet fire following. The fire burned until the gas could be de-inventoried and isolated. The lack of clear communication between field and control room operators during the startup procedure re-garding operation of the equalization valve was a contributing factor. Due to the sporadic operation of the plant, training and retraining of operators was not to the same level as the main plant on site.

In addition, no thrust protection or sprinkler pro-tection was installed on the compressor train. Damage was sustained to the compressor, motor, building and auxiliary systems. The plant down-time was reduced to 4 months (from a 9 month re-pair lead time) due to sparing which allowed the plant to return to operation at a reduced rate. Gross loss - $35,000,000 (Property damage and business interruption) Equipment Contingency Planning and Sparing The ability to recover from an unplanned outage of rotating equipment and restore operations is vital to maintaining the resilience of site pro-cesses. As demonstrated by loss history, viable equipment contingency planning and sparing can reduce production downtime in the event of a breakdown. Developing an equipment contin-gency plan is a documented process to prepare in advance to respond to and recover from a break-down and reduce downtime to an acceptable level. The scope of sparing as part of the plan can include complete spares (on or off site), crit-ical spare parts (on or off site), and/or built in re-dundancy. In order to be considered viable, spares require proper storage and maintenance as part of the asset integrity program to ensure via-bility and availability of the spares when needed. The equipment contingency plan should be re-viewed annually and/or when there is a signifi-cant change including use of the spares, spares not being stored/maintained as viable, changes in processes, change in revenue flows, etc. This is to manage change in exposures, maintain viabil-ity and confirm efficacy of the plan. Fire Hazard Analysis Given the exposure created by loss of contain-ment in the event of a rotating equipment break-down and release of oil and/or flammable gases, part of the solution to mitigate this hazard is to

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assess the fire risk. To assess this risk, an oil fire hazard assessment (OFHA) is conducted. The OFHA evaluates the compressor train oil fire/flammable gas fire hazard case by case to de-velop solutions to mitigate the hazard. An OFHA is a detailed engineering review of the oil sys-tems, building/construction features, potential re-lease, fire scenarios, corresponding fire protec-tion and emergency response planning. The OFHA is performed on each compressor train to address any unique hazards requiring customized solutions. This approach can be leveraged during initial design of new facilities as well as for the evaluation of existing installations. Effective design for fire prevention and damage mitigation requires a thorough understanding of the specific fire hazards present (Spray fire; Three-dimensional fire; Pool fire) created by the equipment breakdown resulting in the release of oil in the lubricating, seal, and/or control-oil sys-tems of rotating equipment. Fire Hazards Several separate and distinct fire hazards expose compressor trains. Each type of fire hazard has different attributes. These, in combination with differences in types of equipment, construction features and potential fire areas present unique equipment damage potentials, downtime conse-quences and fire hazard, exposure and protection challenges. To understand the oil fire hazard and develop solu-tions, a comprehensive series of tests were con-ducted at the FM Global Research Campus. A mock turbine pedestal and lube oil tank skid were constructed and three oil fire scenarios were tested; Spray fire; Three-dimensional fire; and Pool fire. The fire tests were performed utilizing a range of sprinkler protection design options and oil flow rates to determine to best solutions for the risk. Mineral oils typically used for lubrication and control in compressor trains have flash points from 300 to 450 °F (149 to 232 °C) and auto-

ignition points from 500 to 700 °F (260 to 371 °C). The heat of combustion for mineral oil is ap-proximately 18,000 BTU/lb. (4.1 MJ/kg). The most common and obvious oil ignition source is steam piping. Typical steam temperatures can reach 800 to 1200 °F (427 to 649 °C) (4). Oil Spray Fire – Potentials for oil spray fires from high pressure lube, control, or seal oil systems ex-ist for most compressor trains. Although oil spray fires can develop at pressures as low as 20 to 30 psig (137 to 207 kPag) FM Global uses 50 psig (345 kPag) as the lower threshold for spray fire potential (4). Typically the control oil pressure for a compressor train is well above 50 psig (345 kPag) and does present a spray fire potential. Lube oil pressures are typically lower and as a result may not present a spray fire potential. The heat release rate for a spray fire can be very high in comparison to a pool fire as nearly all of the atomized oil can be consumed. A 15 gpm (57 L/min) spray fire can have a heat release rate as high as 1,960,000 BTU/min (34.5 MW). Oil spray fires are the most intense and difficult to control of all the types of oil fires (Figure 5) (5).

Figure 5 - Oil Spray Fire Test

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Three-Dimensional Oil Spill Fire –Three-dimen-sional spill fire hazards (oil falling through the air while burning) exist from the oil piping systems. Heat release rates based on the flow of the oil leak, are usually a fraction of that of a spray fire. Oil not consumed in this fire can collect at the floor level forming a pool fire (Figure 6) (5).

Figure 6 – Three-Dimensional Oil Spill Fire Test Oil Pool Fire – Oil leakage from piping, tanks, or compressor train collecting on the ground or op-erating floor presents a pool fire potential. Pool fire areas are defined by the boundaries of any con-tainment features. A 100-sq. ft. (9.3 m²) mineral oil pool fire will produce approximately 950,000 BTU/min (16.8 MW) (Figure 7) (5).

Figure 7 - Oil Pool Fire Test This testing found that deluge sprinkler systems can be effective in controlling spray fires and in controlling or extinguishing oil pool fires. Certain sprinkler arrangements were found to be effective in reducing the maximum gas temperature of an oil spray fire at roof level to below 430 °F (221 °C). Another hazard is syngas which is composed pri-marily of hydrogen and is flammable. The heat of combustion ranges from approximately 240 to 320 BTU/cu. ft. (8.942 to 11.92 MJ/m³) in com-parison, the heat of combustion of pure hydrogen is 325 BTU/cu. Ft. (12.11 MJ/m³). Synthesis gas jet fire - There is a potential for this flammable gas to leak at high pressure from process piping system and/or compressor. Igni-tion is relatively easy, resulting from self- ignition as well as static discharge, sparking, friction, and other low energy ignition sources. The jet flame can extend for many feet/meters depending on the pressure and characteristics of the opening. Synthesis gas explosion – Delayed ignition of a syngas release inside of a building can result in an explosion. Extinguishing a syngas fire without

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stopping the gas flow may create a building ex-plosion.

Emergency Shut Down Procedure During a Fire.

The single most important emergency procedure during a compressor train fire is to promptly shut off the fuel source. Emergency shutdown pro-cedures should address both syngas and all oil sources. Shut down initiating controls should be remote from the compressor train fire areas. There are some arrangements where controls for lube oil pumps are only located in compressor buildings which is not recommended, as the build-ings may not be accessible during a fire scenario due to intense heat and smoke. Common rundown times for steam turbine driven compressors can be only a few minutes depend-ing on the equipment design. Soon after oil pumps are turned off the spray fire will decrease in intensity as the oil pressure decreases. Once a spray fire dies out from lack of pressure the fire may continue as a three-dimensional spill fire. The three-dimensional spill fire can be fed from oil in piping and any rundown tank(s). Typically, a pool fire will exist after oil spillage stops until the pool burns out, drains away, and/or is ex-tinguished. The type of seals (dry vs. wet) impacts the emer-gency shutdown procedure. Machines with wet seals have to have the system in service longer until the syngas loop is depressurized. Use of dry seals allows for quicker shutdown of the lube oil system. Training and drills for personnel involved in the shutdown process to documented proce-dures are recommended. Even with proper training and drilling, success in shutting down oil and syngas sources may not be prompt enough to prevent significant fire damage.

Detection

Heat detection is the least expensive and most

reliable form of fire detection suitable for a com-pressor building or train. Spot or line type detec-tor systems are typically used. UV/IR flame de-tectors are also common. These can detect a fire much quicker but are limited to line of sight, tend to be more expensive and have a reputation for nuisance alarms. Smoke detection is typically not used due to the harsh conditions found in compressor buildings. Highly sensitive smoke de-tection systems can provide extremely fast noti-fication, detecting smoldering fires other systems may not. Remote cameras can be used to assess the magni-tude of smaller fires and decide on the course of action in unattended compressor houses. Large, fast developing, smoky fires could cause camera vision to be obscured relatively quickly.

Containment and Emergency Drainage

Emergency drainage is effective in reducing the oil fire hazard area to the minimum possible and re-ducing the magnitude and duration of any pool fire in the contained area. Emergency drainage should be considered for solid operating floors and ground floors where oil accumulation is possible. Floor slope should be continuous under compressor trains. Drains, which can become clogged with debris, floor low points, or sumps should not be placed under compressor trains as this can create an extended oil pool fire in an undesirable loca-tion. Drainage should accommodate the antici-pated fire protection water application plus a safety factor. Usually the oil volume is insignifi-cant in comparison to the water discharged. Containment alone is inferior to emergency drain-age. Although it will limit a fire area, containment creates an opportunity for a longer duration pool fire. Sprinkler protection can be used in com-bination with containment. However, even with sprinkler protection a developed pool fire will take several minutes to be controlled or extinguished. A foam-water sprinkler system is the recom-mended option when containment is present in

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lieu of emergency drainage. Additionally, with containment alone the potential for over flowing should still be considered. Fire protection water with lube oil floating on top of it will flow beyond the containment area if overtopped. This flow needs to be anticipated and directed to a safe loca-tion away from equipment and buildings.

Fixed Water Based Protection

There is no better way to provide quicker, more accurate, effective, and reliable application of fire protection water than with an automatic sprin-kler/water spray system. Manually activated fixed sprinkler/water spray systems are a less desirable alternative as they are subject to human error re-sulting in delay of activation and potentially de-creased effectiveness as a result. Other forms of automatic fire protection systems such as gas extinguishing systems, dry chemical systems, high expansion foam systems, oxygen reduction systems, are either expensive, not as reliable, and/or present personnel safety hazards and are not viable alternatives to water based systems. A combination of directional water spray protec-tion and conventional automatic sprinklers is the best arrangement. Directional water spray nozzles should be arranged to protect bearings where an oil fire is likely to originate. Conventional automatic sprinklers are provided beneath the operating floor to protect the oil pool fire scenario that can develop below the compressor train. Directional water spray nozzles protect structural steel, both for the building and any cranes. Roof level automatic sprinklers may not be needed depending on the building. Directional water spray protection installed on deluge systems is ideal for protection of bearings for compressor trains. Water spray systems are not designed to extinguish or control fires but ra-ther prevent the temperatures of protected objects from reaching damaging temperatures by applica-tion of a specific density of fire protection water di-rectly to the surface of an object while the fire is

being extinguished by other means. Conventional ceiling level building sprinkler sys-tems can be effective in controlling and sometimes extinguishing oil pool fires, combustible building fires, and ordinary combustibles fires. The best application for a conventional sprinkler system is under the operating floor of a machine where a pool fire is most likely to develop. This type of protection is not considered to be effective in con-trolling syngas fires, oil spray fires, or three-di-mensional oil spill fires but may provide some cooling of objects depending on arrangement. Another application for automatic protection are lube oil reservoirs and pumps, with directional wa-ter spray or conventional automatic sprinklers. Two areas of design concern exist that could ren-der this type of protection ineffective. Auto-matic sprinkler systems are usually designed for only a portion of the installed sprinkler heads to operate, typically 2,000 to 5,000 sq. ft. (186 to 465 m²). For larger buildings oil and syngas fires can open more sprinkler heads than the sprinkler systems was designed to have operate. Protection would be compromised and a fire would not be expected to be controlled. Ceiling height is also an important factor. Larger clearances compromise sprinkler system effectiveness, and greater dis-charge densities are required for pool fire extinguish-ment. Open (deluge) sprinkler systems provide area protection like automatic sprinkler systems. The key difference is that all sprinklers discharge at once, actuated by a fire detection system, rather than one at a time. As actuation is not dependent on a sprinkler fusible element, sprinklers need not be located near the ceiling. Instead, sprinklers can be located closer to the hazard allowing for opti-mal fire to sprinkler head clearance. Water Mist Water mist systems are special protection sys-tems for protection of enclosures for specific haz-ards including process equipment. Examples in-clude combustion turbines and machinery in

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enclosures. The effectiveness of water mist must be proven by fire testing on the specific hazard. Water mist systems should be approved or listed for the intended application. Foam Water Systems A sprinkler system can fairly easily be adapted into a foam water sprinkler system that will deliver aqueous film forming foam (AFFF) directly onto a fire. Although not effective on spray or three-di-mensional spill fires, AFFF can extinguish an oil pool fire significantly quicker and more reliably than a system delivering water only. A drawback is that foam water systems are designed with a limited foam supply, usually 20 to 30 minutes. If the fire is not extinguished within that time protec-tion may not be entirely effective. A solution is to design the foam water system to deliver AFFF at the same density as a conventional or deluge sprinkler system would be designed. If the AFFF concentrate supply runs out sprinkler protection can continue in its place. A foam water system is recommended where containment is provided in lieu of emergency drainage or where the water sup-ply capacity is limited.

Manual Fire Fighting Capabilities

Different levels of manual firefighting capabilities are appropriate for different cases. The minimum necessary capabilities and systems include a reli-able fire protection water supply satisfactory for firefighting hose streams, well-spaced fire hy-drants and monitor nozzles, a properly trained and equipped firefighting team, and an effective pre-fire plan. Effectiveness of manual firefighting ef-forts is greatly influenced by the presence of full buildings ( walls and roof), proximity of other equipment and buildings, arrangement of equip-ment, and other access issues.

Equipment Arrangement

A well designed layout/arrangement of equipment in compressor buildings can limit fire damage. Support systems and equipment should be located

as much as possible outside of defined fire areas. Oil reservoirs and rundown tanks can be located in fire areas separate from the compressor trains and other important equipment by containment/drain-age features and fire rated partitions. Adequate space separation should be provided between compressor trains so that a fire affecting one will not severely affect the other. The separation distance needed will depend on containment and drainage features as well as the presence of any sprinkler or water spray protection. Water on Compressor Trains Damage to hot steam turbine or compressor by properly designed automatic sprinkler or deluge sprinkler system is not considered a significant hazard. FM Global loss history shows no signif-icant losses where fire protection water applica-tion to steam turbines or compressors has been a contributing factor. Conclusions

Steam turbine compressor trains represent criti-cal process bottlenecks for the ammonia industry. Understanding the process hazards as part of pro-cess safety to develop effective asset integrity programs and condition and performance moni-toring; Adequately designed, installed, main-tained and functional safety devices; Fully trained operators to standard and emergency op-erating procedures; and viable equipment contin-gency planning and sparing will reduce the fre-quency and severity of a breakdown. Adequate sprinkler protection reduces the fire exposure to equipment and buildings in the event a break-down results in loss of containment. This com-bination of loss prevention engineering solutions are part of a successful risk management strategy for this equipment to maintain resiliency. Com-pressor train equipment that is resilient delivers reliable service to ammonia production.

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References

(1) FM Global Loss Prevention Data Sheet 7-95 – Compressors, September 2000

(2) FM Global Loss Prevention Data Sheet 13-3 - Steam Turbines, July 2014

(3) FM Global Loss Prevention Data Sheet 10-8 – Operators, April 2016

(4) FM Global Loss Prevention Data Sheet 7-101 - Fire Protection for Steam Tur-bines and Electric Generators, July 2013

(5) Fire Protection for Steam Turbine Driven Syngas Compressors Robert Elizeus, FM Global – 2007 AIChE Safety in Ammo-nia Plants and Related Facilities Sympo-sium

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