PEH:Oil and Gas Processing
Petroleum Engineering Handbook
Larry W. Lake, Editor-in-Chief
Volume III – Facilities and Construction Engineering
Kenneth E. Arnold, Editor
Copyright 2006, Society of Petroleum Engineers
Chapter 1 – Oil and Gas Processing
Oil or gas wells produce a mixture of hydrocarbon gas, condensate, or oil; water with dissolved minerals, usually including a large amount of salt; other gases, including nitrogen, carbon dioxide (CO2), and possibly hydrogen sulfide (H2S); and solids, including sand from the reservoir, dirt, scale, and corrosion products from the tubing.
For the hydrocarbons (gas or liquid) to be sold, they must be separated from the water and solids, measured, sold, and transported by pipeline, truck, rail, or ocean tanker to the user. Gas is usually restricted to pipeline transportation but can also be shipped in pressure vessels on ships, trucks, or railroad cars as compressed natural gas or converted to a liquid and sent as a liquefied natural gas (LNG). This chapter discusses the field processing required before oil and gas can be sold.
The goal is to produce oil that meets the purchaser’s specifications that define the maximum allowable water, salt, or other impurities. Similarly, the gas must be processed to meet purchaser’s water vapor and hydrocarbon dewpoint specifications to limit condensation during transportation. The produced water must meet regulatory requirements for disposal in the ocean if the wells are offshore, reservoir requirements for injection into an underground reservoir to avoid plugging the reservoir, and technical requirements for other uses, such as feed to steam boilers in thermal-flood operations, or in special cases, for irrigation.
The equipment between the wells and the pipeline, or other transportation system, is called an oilfield facility. An oilfield facility is different from a refinery or chemical plant in a number of ways. The process is simpler in a facility, consisting of phase separation, temperature changes, and pressure changes, but no chemical reactions to make new molecules. In a refinery, the feed-stream flow rate and composition are defined before the equipment is designed. For a facility, the composition is usually estimated based on drillstem tests of exploration wells or from existing wells in similar fields. The design flow rates are estimated from well logs and reservoir simulations. Even if the estimates are good, the composition, flow rates (gas, oil, and water), pressures, and temperatures change over the life of the field as wells mature and new wells are drilled. Facilities have a design rate that is a best-guess maximum flow based on the number of wells, production profiles, and total oil or gas that can be produced from the reservoir. The actual production rates for a facility increase as the wells are completed up to the design rate. This rate will be maintained as long as possible by drilling additional wells; then, oil and gas rates will decline, water rates will increase, and flowing pressure will decrease as the reservoir is depleted. The equipment must be designed to operate over a range of flow rates with uncertain compositions and temperatures.
Definition of Terms
The following definitions are used in this section of the Handbook.
Crude oil is a liquid hydrocarbon produced from a reservoir. Condensate is liquid hydrocarbon that condenses from the gas as pressure and temperatures decrease when the gas is produced from the reservoir up the tubing and out the wellhead choke. Condensate is usually lighter in color and lower in molecular weight and viscosity than crude oil; however, a light crude oil could have properties similar to a condensate.
Hydrocarbons are composed of many different "components" or molecules of carbon and hydrogen atoms. Starting with the lightest molecular weight, they are methane (CH4), ethane (C2H6), propane (C3H8), butane (C4H10), pentane (C5H12), hexane (C6H14), and so on. As the ratio of carbon to hydrogen atoms increases, the molecules become "heavier" and have a greater tendency to exist as a liquid rather than a gas.
An oilfield facility is a collection of equipment that is used to separate the fluids that come out of an oil or gas well into separate streams that can then be sold and sent to a gas plant or refinery for further processing.
A process simulation is a calculation, usually done with a computer program that predicts how the components that make up the well fluids react to changes in pressure and temperature as they are processed through the facility. This is not a chemical reaction, but rather a simple phase change as liquids flash to vapor or vapors condense into liquid. As the pressure is reduced or the temperature is increased, the lighter molecules, such as methane and ethane, tend to boil off into the vapor phase, taking some of the midrange components with them. The remainder of the midrange and most of the heavier molecules stabilize as liquid.
Basic sediment and water (BS&W) is the percent by volume of water and solid impurities in the oil. Oil pipeline specifications range from 0.1 to 3%, with a typical Gulf of Mexico pipeline requirement of 1% by volume.
The bubblepoint, or true vapor pressure, is the point at which gas first appears within a liquid sample as the temperature is raised or the pressure lowered. The bubblepoint of a hydrocarbon liquid is a function of pressure, temperature, and the composition of the liquid.
Reid vapor pressure is the pressure at which a hydrocarbon liquid will begin to flash to vapor under specific conditions. It can be measured in the field according to a specific American Society for Testing and Materials standard and results in a pressure lower than the true vapor pressure.
The hydrocarbon dewpoint is the point at which hydrocarbon liquid first condenses from a gas sample when the temperature is lowered or the pressure is increased, and it depends on the composition of the gas. The water dewpoint is often specified for gas pipelines for hydrate and corrosion control. Depending on the history of the hydrocarbon fluid (i.e., the processing that has occurred upstream of the point in question), the hydrocarbon and water dewpoints may not be the same.
Hydrates are crystalline, ice-like solids that form in the presence of hydrocarbon gas and liquid water. Hydrates can form at temperatures significantly higher than the freezing point of water and can plug equipment and pipelines.
Function of a Facility
The main function of an oil facility is to separate the oil, gas, water, and solids; treat the oil to meet sales specifications (e.g., BS&W, salt content, vapor pressure); measure and sample the oil to determine its value; and deliver it to the transportation system (i.e., the pipeline, truck, ship, or railroad car).
The gas must be treated for sales or disposal. In the past, disposal sometimes meant flaring or venting, but now gas that can’t be transported is usually compressed for reinjection into the reservoir. Gas treating may involve only separation from the liquids, or it may include additional processes such as compression, dehydration, removing H2S and CO2; or gas processing to condense heavier components that can be transported as a liquid.
In addition to processing the oil and gas for sale, the produced water and solids must be treated for disposal. For produced water, treating usually includes removal of dispersed and dissolved hydrocarbons and, in addition to separation or oil skimming, may include filtration, deionization, or pumping.
If treating of solids is required, it may include water washing and agitating the solids to remove the oil and then separating the water from them.
In addition to the process systems, auxiliary process heating and cooling may be required. Process heat is usually needed for oil treating and superheating fuel gas for use in gas turbine generators or compressors. Process cooling is usually required for gas compression.
While, if necessary, facilities can be run without electric power, power generation and electrical systems will usually be included for a facility that is large or complex or for living quarters that are provided for personnel.
All facilities require safety systems, including safety instrumentation and shutdown system; fire and gas detection; fire-fighting equipment; a means of evacuation, such as life rafts and escape capsules for offshore; and other equipment, depending on the location and complexity of the facility and whether it is manned.
Example Oil Facility
Fig. 1.1 is a block diagram of a simple oil facility. Each of the blocks is described here, except for gas dehydration, which is covered in Sec. 1.5, Gas Facilities.
SeparationThe first step in the process is separating the gas from the liquid and the water from the oil. This is usually done in a separator—a pressure vessel into which the wellstream flows to allow the gas, oil, and water to separate because of gravity. Separators may contain inlet diverters, outlet vortex breakers, buckets, weirs, and mist extractors to aid separating the streams. See the chapter on Oil and Gas Separators in the Facilities and Construction Engineering section of this Handbook for a more detailed description of separator design.
A separator may be two-phase, separating gas from liquids, or three-phase, separating gas, oil, and water, which are removed through three outlets. The first separator in a facility that receives fluid from the wells is called a production, or high-pressure (HP), separator. If the production is at high pressure, (e.g., 500 to 1,200 psig) and if the oil from the separator is put directly into a pipeline, gas will flash as the pressure decreases owing to friction losses in the pipeline. Gas takes up a much larger volume than its equivalent mass of oil, so a pipeline sized for liquid flow will be undersized if some of the liquid flashes into gas, resulting in excessive velocities and pressure drop. For this reason, oil pipeline owners generally specify a maximum vapor pressure allowed to prevent the lighter components in the oil from flashing into gas. The process of reducing the vapor pressure in the oil to meet oil-pipeline specifications is called "stabilization."
For the simplest form of stabilization, the oil is put into an atmospheric tank for storage. This allows the gas to flash from the liquid in the tank when the pressure is reduced to atmospheric. This process would get the true vapor pressure of the oil down to atmospheric, or even lower if some heating were added in addition to the pressure reduction, and could be used to make the oil meet pipeline specifications for vapor pressure. The gas that flashes in the tank must then be compressed back to the original pressure of the separator and combined with the separator gas.
If the oil is sent to an intermediate pressure (IP) separator instead of going directly into an atmospheric tank, the gas that flashes in the IP separator will be at a higher pressure, requiring less compression horsepower. In addition, the total amount of oil stabilized in the atmospheric tank is greater with an intermediate separation stage than with a single flash to atmospheric pressure. This is because of the gas/liquid equilibrium for the higher-pressure flash and the altered composition of the oil that is flashing in the tank.
While there still would be gas flashed as the liquid flowed from the IP separator to the tank, the quantity would be much smaller than in the first case in which liquid goes directly from the HP separator to the tank. Thus, adding a second stage of separation has two benefits: first, the horsepower required to compress the gas is lower because some of the gas flashes at higher pressure, and second, more stabilized oil will be produced. If we add a third, low-pressure (LP) stage of separation, the total liquid in the tank increases even further, with additional gas flashing at a higher pressure, reducing compressor horsepower. Fig. 1.2 shows a typical three-stage separation with flash-gas compression. Adding additional stages of separation and compression would increase liquids and reduce compression horsepower further; however, at this point, the capital cost of adding additional separation stages is generally not worth the small increase in hydrocarbon value.
A typical separation train might have a well producing into an HP separator at 1,100 psig, with the oil to an IP separator at 450 psig, an LP separator at 150 psig, and possibly an oil treater at 50 psig (see next section) before storage in an atmospheric tank. The separator pressures are chosen so that the flash gas from each stage of separation feeds into a stage of compression with reasonable compression ratios for each stage of the compressor. See the chapter on Compressors in this volume of the Handbook for a discussion on compression ratios and calculation of compressor horsepower.
No separation is perfect, there is always some water left in the oil. Water content can range from less than 1% water to more than 20% water in the oil by volume. The lower the API gravity (i.e., the higher the molecular weight and the oil viscosity), the less efficient the separation.
To get the last of the water out of the oil, the oil is processed through an oil treater or a treating system, as described in the chapter on Emulsion Treating in this section of the Handbook. A treater is similar to a separator, but with special features to help separate the water from the oil. Treaters or treating systems usually provide heat to reduce oil viscosity and large settling sections to allow the water time to settle from the oil, and may provide an electrostatic grid to promote coalescing of the water droplets. Conventional treaters usually have a front section with a heater in which the emulsion is heated and initial separation of the "free water" takes place. The oil then flows to a second section of the vessel, where additional coalescence and settling of the water droplets takes place. Gas is flashed (i.e., liberated) from the emulsion as the pressure is lowered and the temperature is raised from the upstream separator. For a conventional treater with a heater, free-water knockout section, and settling section, the water content in the oil can be reduced to less than 1%. An electrostatic treater, which is a conventional treater with an electrostatic grid in the settling section, can reduce the water content to 0.3 to 0.5% by volume.
The contract between the oil seller, who is normally the producer, and the purchaser, who may be a pipeline company, specifies the allowable water content, and may specify the maximum salt content in the crude oil. High water content can make corrosion problems worse in pipelines and other transportation systems and can cause problems with downstream processing. High salt content, which is caused by the salinity of the produced water left in the oil, may cause a refining problem when the water is boiled off in the refinery distillation unit.
The oil from the treater is usually sent into a dry oil tank, from which it is pumped through a sales meter for custody transfer, and then into a pipeline for transportation. For additional information, see the chapters on Storage Tanks, Pumps, and Instrumentation and Controls in this section of the Handbook.
As mentioned previously, separation is not perfect, and the amount of oil left in the water from a separator is normally between 100 and 2,000 ppm by mass. This oil must be removed to acceptable levels before the water can be disposed of. The regulatory requirements for oil-in-water content for overboard water disposal vary from place to place, and some locations do not allow any discharge of produced water. As an example, in the Gulf of Mexico outer continental shelf (U.S. federal waters), producers are limited to a maximum measurement of 42 ppm for any one sample and no more than 29 ppm average for a given month. In contrast, on shore, no discharge of produced water is permitted. In the case in which discharge is not permitted, produced water is usually injected into disposal wells.
Various types of equipment for water treating are described in the chapter on Water-Treating Facilities in Oil and Gas Operations in the Facilities and Construction Engineering section of this Handbook. Equipment types used in this case include water skimmers, plate coalescers, gas flotation devices, and hydrocyclones. Additional equipment, including desanders and filters, may be needed to remove solids before injection, as also described in the chapter on Water-Treating Facilities in Oil and Gas Operations.
Hydrocyclones require a pressure drop in excess of 100 psi to work well and would usually be placed between a separator and its water-level control valve. In addition to removing oil from the water, hydrocyclones have a tendency to coalesce the remaining oil droplets in the water streams, making the droplets easier to separate with the downstream equipment. Water skimmers use gravity separation to remove the remaining oil from produced water and are usually placed downstream of separators or hydrocyclones.
A good rule of thumb is to use two types of water-treating equipment for a gas facility and three types for an oil facility in which the oil may be more difficult to separate. For example, a water-treating system might consist of a hydrocyclone, followed by a water skimmer and a gas flotation cell.
Fig. 1.3 is a block diagram of a simple gas facility. Each of the main blocks is described here.
Gas wells are often high pressure with a shut-in tubing pressure of 5,000 to 15,000 psig and a flowing tubing pressure in excess of 3,000 psig. This pressure must be reduced to the appropriate pipeline pressure at the point at which the gas flows through a wellhead choke. When gas pressure is reduced, the gas cools, liquids can condense, and hydrates can form. Hydrates are crystalline solids made up of hydrocarbon and water molecules and form in the presence of hydrocarbon gas and liquid water at temperatures significantly higher than the freezing point of water. These hydrates can plug the choke and flowline, so high-pressure gas wells usually require a line heater that contains the flowline and choke inside a hot water bath to keep the well from freezing. See the chapter on Phase Behavior of Water/Hydrocarbon Systems in General Engineering, Vol. I of this Handbook, for a more complete discussion of hydrates.
Hydrate formation can be inhibited by injecting a solvent, such as methanol, into the flowline. This is done for subsea and other wells in which a line heater is not possible. For most wells with high flow rates, the expense of the methanol makes a line heater the better choice.
The separator provides a place for any liquid to settle out from the gas. The separator pressure is set higher than the pipeline pressure so that the gas can go through the required cooling, treating, dehydration, and gas processing—each with some pressure drop—and arrive at the required pipeline pressure.
If the gas flowing temperature is high, the temperature downstream of the choke may be high enough so that it will not be necessary to install a line heater upstream of the HP separator. If the flowing tubing temperature is even higher, the hot gas leaving the HP separator could cause process and corrosion problems with the downstream treating system. In addition, the hot gas will carry more water vapor, which makes the dehydration system larger and much more expensive than if the gas were cooled first. Thus, it is sometimes necessary to install a gas cooler downstream of the first-stage separator.
The cooler may be an aerial cooler or a shell-and-tube exchanger that uses either direct seawater or a contained cooling-water loop, which is cooled by seawater or some other water source.
Natural gas may have a number of impurities, such as H2S and CO2, which are referred to as "acid gases." Natural gas containing H2S is called a sour gas; if the gas contains no H2S, or if the H2S has been removed, it is "sweet gas." The process of removing the H2S, and possibly CO2, is referred to as "sweetening."
H2S gas is highly toxic. CO2 forms a strong acid that is highly corrosive in the presence of water. Combined, they are corrosive; if the corrosion results in a leak, they can be deadly.
A common way to remove H2S and CO2 from natural gas is with an amine system, which uses a contact tower with trays or structured packing to pass the sour gas through the amine liquid, absorbing the H2S and some of the CO2. The amine is then regenerated in a stripping tower in which the H2S and CO2 are removed.
There are also several licensed physical solvent and batch processes (chemical or adsorption) available commercially.
For a more detailed description of gas treating, refer to the chapter on Hydrocarbon Testing in the Engineering Data Book.
To avoid water condensing in the gas pipeline with resulting corrosion and hydrate-formation problems, pipeline specifications usually limit the amount of water vapor in the gas. A standard pipeline specification in most of the southern U.S. is 7 lbm of water per million standard cubic feet of gas (lbm/MMscf). This corresponds to a water dewpoint of approximately 32°F at 1,000 psi. In northern areas, or in very deep water in which temperatures outside the pipe could be much lower, it is common to see a specification of 4 lbm/MMscf (approximately 0°F dewpoint at 1,000 psi).
Water is often removed from gas with a glycol dehydration system, as described here. Other methods include solid-desiccant adsorption, refrigeration, and membrane permeation.
Glycol dehydration systems commonly use triethylene glycol to absorb the water vapor from the gas. This is done in a contact tower in which the lean, or dry, glycol flows by gravity from the top of the tower through trays or structured packing. The gas flows countercurrent up through the tower so that the driest gas contacts the driest glycol.
The dry gas exiting the tower is used to precool the lean glycol before it enters the tower. The gas then continues to sales or to further processing to remove natural-gas liquids (NGLs).
The rich, or wet, glycol exiting the bottom of the tower is regenerated in a continuous process. First, the rich glycol goes to a separator to remove any condensed hydrocarbons; then it is preheated and filtered before being sent to a "reboiler" or "regenerator."
The rich glycol is heated in the regenerator up to 390 to 400°F, and the water is boiled off. This vapor is either discharged directly to the atmosphere or is cooled and condensed to separate the small amount of hydrocarbon vapors from the water.
The resulting hot, lean glycol is then cooled through a cross exchanger with the cool, rich glycol coming from the contact tower. The cross exchanger makes the process more efficient and preheats the glycol going to the reboiler, which reduces the overall energy requirements. The reboiler may be heated by a gas-fired heater, electric heating elements, or a heat-medium system. For a more detailed description of gas dehydration, refer to the chapter on Dehydration in the Engineering Data Book.
The dry gas may be further processed to recover liquid hydrocarbons in the form of NGLs, LNGs, or liquefied petroleum gas (LPG). NGLs are hydrocarbon liquids, such as ethane, propane, butane, and natural gasoline, that can be separated from a natural-gas stream after the heavier hydrocarbon components have already been removed by separation at ambient temperatures. LPG is a mixture of hydrocarbons—principally butane and propane—that can be transported as a liquid under pressure, or at very low temperatures. and converted to gas on release of the pressure. LNG is a liquid composed of mostly methane that is liquefied to make it easy to transport if a pipeline is not feasible.
The most common processes used to separate NGL or LPG are lean-oil absorption, refrigeration, or turbo-expander plants. The lean gas remaining can be used as fuel, reinjected into the reservoir, or put into a pipeline.
Stabilization removes the light hydrocarbons from the liquid stream, either by reducing the pressure and letting the lighter components flash, as discussed previously, or by a combination of pressure reduction and heating. Most of the water will be removed during separation. The resulting stable condensate has a low vapor pressure so it can be stored in tanks for shipping at atmospheric pressure by truck, train, barge, or ship without excessive vapor venting. Often, there are vapor-pressure limitations that require liquid stabilization for pipeline shipments as well.
The water removed in the separation/stabilization process must be treated and disposed of, as described in the previous section on water treating.
The lighter components removed in the gas phase during the stabilization process will be at a lower pressure than the main gas stream. These components must be compressed to the HP-separator pressure so they can be processed with the rest of the gas.
A separator operates through a continuous, rather than a batch, process. This means that the inlet stream constantly flows into the separator and that the gas and liquid must be removed at the same rate. For liquids, this is done by means of a level controller and level valve. The traditional level controller consists of a float on a spring. As the liquid level in the separator rises, the float rises until it closes a switch, which then opens the level valve to let out some liquid. When the level falls back down to the normal operating level, the switch opens again and drives the level valve closed. A two-phase separator uses a single liquid-level controller and level valve; a three-phase separator will have both an oil outlet with an oil-level controller and level valve and a water outlet with a water-level controller and level valve.
If the level valves control the liquid coming out of the separator, how is the gas controlled? Because the liquid is incompressible and the liquid level in the separator remains fairly constant, the gas is contained in an approximately constant volume. As more gas enters the separator, the pressure rises. A pressure controller is mounted on the separator-gas space or on the outlet-gas piping. The controller sends a signal to the pressure-control valve in the gas-outlet piping telling it to open when the pressure is higher than the set point. Pressure-control valves are usually modulating, which means that they gradually open wider as the pressure rises to a value higher than the set point and close as the pressure falls to a value lower than the set point.
In short, whatever amount of liquid comes into the separator, an equal amount must exit through the level-control valve. The level controller senses whether the liquid level is high or low and adjusts the level valve accordingly. Whatever amount of gas that comes in the inlet of the separator, an equal amount of gas must exit through the pressure-control valve. The pressure controller senses pressure in the separator, opening the pressure-control valve if the pressure gets higher than the desired set point and closing it if the pressure gets lower than desired. If the inlet stream shuts off, the outlet valves would all close, maintaining the pressure and level in the separator.
Detailed information on instrumentation and controls, including control-valve selection, is presented in the chapter on Instrumentation and Controls in this section of the Handbook.
If the process-control system operates correctly, operators use all manual valves correctly, and nothing breaks, there is no need for a safety system. However, controllers malfunction, valves leak, and operators make mistakes. The safety system is there to prevent overpressure and possible rupture of equipment, leaks, pollution, fire, injury to personnel, and damage to equipment. RP 14C provides a systematic way to ensure that all necessary safety equipment is in place. Two levels of protection normally exist in a safety system: primary and secondary.
The primary protection is usually a sensor or switch on the equipment that detects the undesirable event. For example, equipment may have a pressure, level, or temperature switch to detect values that are too high or too low, based on the normal operating ranges. Once the undesirable event is detected, a safety shutdown system is required to shut down flow into the affected equipment.
In the event the primary protection fails to operate or operates too slowly to correct a problem, there is secondary protection consisting of a pressure safety valve (PSV) to prevent overpressure. A PSV is designed to open, relieving overpressure in a vessel or piping through "relief header" piping that directs the relieved fluids to a safe place for retrieval or disposal. Alternatively, secondary protection may consist of redundant sensors or switches, such as those used for primary protection, which may be located on downstream equipment or on the equipment in question.
A separator with a given operating pressure will have a "design" pressure or "maximum allowable working pressure" (MAWP) sufficiently greater than the operating pressures to prevent small fluctuations in the process from causing overpressure of the pressure vessel. As an example, in the staged-separation process, the operating pressure of each downstream separator will be lower than that of the separator flowing into it. This allows the system-design pressure to be reduced as well. When a higher-design-pressure system flows into a lower-design-pressure system, there is potential for overpressuring the downstream, lower-pressure-rated system. With multistage separators, the different operating pressures often lead to a different design pressure for the HP, IP, and LP separators and their associated piping. This introduces a hazard commonly referred to as "gas blowby." For example, if the liquid-level valve were to stick open, the liquid would flow out of the separator and the gas would "blow by" the liquid-control valve until the pressure equalized between the upstream and downstream separators. This equalized pressure could be higher than the design pressure of the downstream separator.
Safety systems must be designed to protect the lowest-pressure system in situations like the one outlined previously. Relief valves are normally provided on pressure vessels to protect against overpressure caused by "blocked discharge," which occurs when all outlets to the vessel are closed because of blockage or system shutdown. Relief valves must also be adequately sized to protect against overpressure caused by blowby. The gas-blowby rate may exceed the HP-system inlet flow rate for a short time because the HP separator is being blown down, in an uncontrolled manner, to the lower-pressure system. The flow rate must be calculated based on the upstream pressure, the control valve capacity at full open, any other flow restriction in the piping, and the downstream-vessel relief-valve set pressure. The calculated flow can then be used to adequately size the relief valve.
If the pressure difference between the two vessels is very large, the blowby rates will be correspondingly large. Consider, for example, an HP separator with a 1,480-psig MAWP in which the liquid flows to an atmospheric storage tank. The absolute pressure in the HP separator is 100 times that in the atmospheric storage tank (14.7 psia). Gas blowby from the HP separator expands to 100 times the original gas volume when it goes to atmospheric pressure. If the liquid-control valve from the separator has a 2-in.-diameter opening (3.14 in.2), the vent on the tank must have 100 times the area to pass the same amount of gas (3.14 in.2 or a 20-in. diameter vent). It is not a good idea to have an HP vessel dumping liquid to an atmospheric tank. This demonstrates yet another advantage of staged separation—reducing the amount of gas blowby possible between any two pressures.
In addition to primary and secondary protection for the process, an emergency support system is used to minimize the effects of escaped hydrocarbons. This system includes combustible gas detectors, fire detectors, smoke detectors, a containment system to collect leaking liquid hydrocarbons, and an emergency shutdown system to provide a method for the process-control system to initiate a platform shutdown. An in-depth discussion is presented in the chapter on Safety Systems in this volume of the Handbook.
SI Metric Conversion Factors
- Conversion factor is exact