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3 VAPOR CONTROL TECHNOLOGY . ... Attaining the emission reductions proposed in several state implemen- tation plans to meet the ozone deadlines in the National Ambient Air Quality Standards would require substantial investments by the operators of marine vessels and terminals. Special vapor handling systems would be needed at loading terminals and aboard vessels. Compartments on both tankships and barges would need to be closed to the atmosphere during loading (with appropriate automated gauges to prevent overfilling and overpressuring). Vapors would need to be collected and piped to recov- ery or disposal systems such as flares, incinerators, refrigeration systems, carbon adsorption beds, or lean-oil absorption units. The essential technologies for these measures are available commer- cially. They are used routinely in tank farms and tank truck terminals, although the scales of these systems are often smaller than those re- quired to control vapor emissions during tank vessel loading or ballasting. Vapor control technology is used at marine terminals mainly for handling highly toxic or noxious cargoes with volatile vapors, such as ammonia, chlorine, acrylonitrile, and epichlorohydrin. Applying these technologies more widely, particularly to the high volumes and loading rates typical of gasoline and crude oil, will challenge the ability of vessel and terminal operators to maintain safe operating practices. Operations throughout the industry will need to be raised to the level of subchapter O cargo handling. Communications must be fail-safe, procedures must be consistent and thorough, and equipment must be well maintained. The modest skills required of the barge-trained tankerman, especi- ally in smaller operations/ports, should be taken into account in devising technical solutions and management approaches. Coincidentally, the Coast Guard is in the process of revising and upgrading tankerman certification requirements for a number of safety oriented purposes. Among the technical challenges is the gauging of closed tanks on barges as they are loaded. In loading some tankships and most barges, the practice generally is to gauge the height of the cargo by eye, through open hatches. With vapor recovery systems, tanks will be loaded with hatches and vents closed to the atmosphere, so that accurate gauges will be needed. The closed gauging requirement is particularly impor- tant since overfilling can result in spills, ruptured tanks, and 58
59 damaging mechanical shocks to vapor handling equipment, with possible subsequent fires and explosion. In addition, detonation arrestors adequate for the sizes and flow rates of vapor pipelines will need to be developed and tested. MAXIMUM CONTROL OF EMI S S IONS Loading and ballasting emissions from vessels carrying crude oil and gasoline can be reduced by over 90 percent, using components that are commercially available. However, since few complete systems of the appropriate scale have been constructed and used, some engineering challenges would have to be met to ensure a safe and cost-effective solution to the regulatory requirement for such control. The following sections describe the available options and comment on the technical uncertainties. Closed Loading of Tank Vessels Controlling vapors from tank vessels, obviously, will require load- ing with all hatches and ports closed. Closed loading departs from barge practice, but it is routine on most tankships . I t presents cer- tain problems not confronted when loading with open hatches, but the practice does not present any unusual risk if the vessel is properly outfitted and operated. Liquefied gas carriers, specialty vessels carrying certain hazardous chemicals, and most tankships have been closed loaded for many years with very good safety records. The installation of inert gas (IG) systems on the majority of tankships during this decade has resulted in a great increase in closed loading experience, since closed loading is necessary to maintain the legally required minimum inert gas pressure above the cargo. Equipment for closed loading falls into three categories: (~) protection from tank overpressurization, (2) final (custody transfer) gauging and sampling, and (3) level monitoring and alarms. With some greater risk, closed loading could be done without specifically address - Two possibilities for eliminating volatile organic compound (VOC) emissions from tank vessels were not deemed appropriate for further con- sideration by the committee. The first was to construct the cargo tanks of all tank vessels as pressure vessels, to retain the VOC in the tank- ships. This was considered to be too expensive. The second possibility was to equip vessels so that VOC loading emissions would be transferred to the segregated ballast or clean ballast tanks and eventually dis- charged at sea. This would require changing or abrogating U.S. and inte**national regulations, which was judged impractical. The term "closed loading" does not necessarily imply the capture of vapors. Closed loading today is generally carried out with tank vents open to the atmosphere.
60 ing each of these, but each category should be given careful considera- tion to determine the degree of risk an operator is willing to assume. Tank overpressure protection should especially be considered for barges, since the installed pressure/vacuum (PV) relief valves are not normally designed to pass the full volume flow rate of liquid during loading. Three types of protection are available: spill valves, rup- ture disks, and full-flow relief valves in conjunction with proper piping aeslgn. Spill valves are high-volume, quick-acting relief valves that are closed when gas is being exhausted and open when liquid is present. Their principal disadvantages are the very large size and high cost of valves that handle high-loading rates (more than 5,000 bbl per hour). Rupture disks are devices with carefully machined carbon or metallic disks that rupture at a preset level below the design pressure of the vessel tank structure. Their major disadvantage is that, when actuated, they provide a free path from the atmosphere back to the cargo tanks, with the associated fire hazard. The main purpose of either device is to prevent rupturing the vesselts hull. If practical, the spill valve or rupture disk should be piped to a tank or enclosure to prevent oil from spilling into the water. Even if this is not possible, the spill that might result from the operation of one of these devices could be expected to be much smaller than that from a hull rupture. PV valves are available on the market in a variety of configura- tions. These valves, however, are designed to vent gas rather than liquid at full-loading rates. The limitation can be overcome with a piping design, so that any liquid overflowing one tank and entering a gas exhaust header can flow down into a tank that is not being loaded. Even if this contaminates one cargo with a different one, the cost of reprocessing the contaminated cargo should be considerably lower than the costs of potential damages and cleanup of a major spill. Final manual gauging and sampling of cargo is a routine practice in ship and barge operations. Cargo quantity and quality are verified for both the cargo owner and the transporter, and this practice can be expected to continue as an accepted standard for some time. Manual gauging and sampling on close-loaded vessels, however, cannot be carried out in the same manner as on open-loaded vessels. Whether or not a vessel is inerted with a pressurized inert gas, residual pressure in the tank could present a hazard to the gauger and create inaccuracies in measurement. Several methods are available to overcome these problems and should be included in the design of the gauging and sampling system. On noninerted vessels, when loading is stopped and there is no pressure in the tank above the cargo, a restricted ullage cover in the tank top may suffice. As an alternative, many operators use a standpipe Such piping designs employ vapor headers equipped with valves to permit selection of an empty versus a full tank for possible overflow. The very presence of such valves carries with it the risk of shutdown against a stream of vapors and therefore tank overpressuring, a major risk of closed loading.
61 extending from the deck to just above the bottom of the tank. Measure- ments taken in the standpipe will always be higher than the actual level, if there is pressure in the tank ullage and there are no pressure-equalizing ports. However, if pressure-equalizing ports are provided, gas can flow into the vicinity of the gauger. (Monitoring of the unequalized standpipe level during the first 70-80 percent of loading can be useful, in that the positive ullage pressure will provide a conservative indication of the tank level.) Samples and accurate level readings can be taken from pressurized tanks using a vapor lock and valve. This device consists of a length of pipe extending above the deck to a ball valve, with an additional length of pipe above the valve terminating in a fitting that mates with the gauging tape. The fitting height is set to a datum for which the tank is calibrated. A special ullaging tape in a vapor-tight reel can be mated to the fitting on the end of the pipe, the ball valve opened and measurements taken without releasing tank pressure (Figure 3-1~. Sam- ples, water interface measurements, and temperature readings can also be taken with attachments to the tape. At least two companies make these devices. One consequence of closed loading is there may not be the opportu- nity to observe the cargo level directly, as done with open loading. Indirect determination of cargo levels has generated concern about know- ing the "true" cargo level. Before the transition to closed loading aboard inerted ships, many operators feared that cargo levels would not be reliably known and that overfilling of tanks and spill incidents would increase significantly. While there has been very little reported on recent closed loading experience, the absence of casualty reports suggests not only that there has been no serious increase in overfill incidents, but that the incident rate has actually decreased. Virtually all the cargo level measuring and indicating systems for closed loading incorporate some redundancy. Simple systems may have two independent passive devices. More sophisticated ones may have multiple active and passive devices, independent alarms, and remote repeaters. At the simple end of the spectrum is an unpowered tank barge with a tank viewing port and one other unpowered device to provide warning of nearly full tanks. Among the most complex systems are those of chemical car- riers, which by regulation are required to have a full-range, level- measuring instrument and two independent, high-level alarm instruments. One large domestic operator, which loads all of its 20 operating tankships closed, modified five ships of its fleet from 1980-1981 for use with a vapor recovery system at an offshore facility in the Santa Barbara Channel. Each of these tankships is equipped with a full- length, float-and-tape gauge and a magnetic float-with-reed-switches gauge for the top 10 ft of each tank. In addition, two independent dual-float alarms and a vapor lock for manual ullaging are installed in each tank. Because the vessels are of the older two-houses design, there is no cargo control room and all cargo operations must take place on deck. To provide visual indication of high-level warning and alarms, mimic dis- plays are mounted on the fronts and backs of the midships houses. This arrangement has been very successful. None of the vessels has had a
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63 cargo spill during the 6 years since the system was installed. In fact, this company has had no cargo overflow spills in its entire fleet since converting to closed loading. In contrast with these complex systems, some operators of barges carrying benzene and other hazardous chemicals regularly load closed with nothing more than a glass viewing port for observing the cargo and ma restricted standpipe for final gauging. Even with this arrangement, there was no evidence of cargo overflow incidence rates in excess of open-loading experience. If anything, the overflow incidence of close- loaded barges is lower than that on open-loaded barges' perhaps because of the higher degree of operational control that is necessary in closed loading. Level-monitoring equipment can be conveniently categorized by actua- tion method and display technique, as done by Southwest Research Institute in a study (Johnson et al., 1981) for the Maritime Administra- tion. Of more practical interest to the operator, however, is whether a device is active (requires external power) or passive (can stand alone). Active devices most commonly use electric or pneumatic power, and have the ability to actuate visual and audible alarms and to provide remote indication. The most common electric instruments measure the liquid level by means of magnetic floats sequentially operating reed switches, radar or sonar impulses bounced off the liquid surface, or hydrostatic pressure transducers located in the tank. Alarm indication may be centralized or distributed, and remote readouts may be single or multiple. At least two manufacturers offer hand-held radio receivers that allow an operator on deck to monitor levels and receive alarms from all tanks regardless of location. Since an external source of electricity is needed, this type of monitoring instrument is suited mainly to ship installations. Several manufacturers do offer instruments that are solar powered and could be installed on unpowered barges. The solar-powered devices cannot, however, provide an alarm, owing to the low power available from their photovoltaic collectors. Pneumatically operated level detection systems have found only limited application aboard ships and barges. In most cases, the reasons have been the limitations on supplies of clean, dry air and the poten- tial for creating an explosive mixture by admitting oxygen into an otherwise safe atmosphere in the tank. The most common passive level monitors found on barges are simple visual, mechanical/magnetic, or purely mechanical types that require monitoring by the operator. The simplest of these monitors is a glass viewing port that can be mounted either in the deck or in the expansion trunk hatch cover. More elaborate versions of this device can have a hand-operated wiper for clearing condensation from the underside of the glass, a stepped and calibrated scale that can be viewed through the glass, and a second port to allow a light to be directed into the tank. Another simple but effective device for monitoring the top 4-6 ft of the tank consists of a nonmagnetic tube that penetrates the tank with a float and magnet outside the tube (Figure 3-2~. The float magnet inter- locks with a magnet at the bottom of the lightweight stick inside the tube. As the float rises, the coupling of the magnets causes the stick
64 Blue or Orange Band-" Engaged'' Green Band Deck ~ .~ ~'~ZZZ FIGURE 3 - 2 Indicating stick. - ~ l - a Magnet ~ I me: ~.. Indicating Rod Deck Flange J ~ lo\ \ ~ . Stainless Steel Tube (sealed well) J ~' 1 Stainless Steel Float Follower Magnet r Float Stop Cargo Level
65 to rise with the liquid level, providing a reliable and reasonably accurate indication of tank level. With green, yellow, and red bands on the stick, the tanks can be monitored at reasonable distances if the deck is not too cluttered. A variation on this principle has the stick attached to the float and rising in a tube that projects above the deck. A magnet at the top -of the stick causes magnetic flags to flip over as the top magnet passes them, changing the visible color of the column from white to red. The range of indication on each of these types is limited by the weight of the stick and the vertical clearance above the barge deck. A more complicated but effective full-length gauging instrument uses a wire-guided float, which unreels and retracts a calibrated tape from a spring-loaded drum as the float falls or rises with the tank level. This instrument may be supplied either unpowered or powered to drive a remote gauge and alarms. Independent, power-operated, high-level alarms should be considered for tank vessels that have neither redundant cargo level monitoring systems nor level monitors with built-in alarm capability. Any alarm system should have a means of checking the complete alarm operation before loading and, if electrically powered, should have intrinsically safe circuitry. The most common type of alarm in marine use has a mag- netic float that holds a reed switch closed. When increasing cargo level lifts the float above the switch, the switch opens, breaking the circuit and sounding the alarm. A mechanical or magnetic link is normal- ly included to lift the float to check for float freedom or proper electrical function. In addition to the float-actuated type, several manufacturers offer capacitance or optical alarm devices that might be adapted to marine use. Functional testing of these types, however, might be more difficult. While each operator will have ideas about acceptable risk, the possible consequences of a cargo overfill incident are severe enough to require very careful consideration of the vessel's need for additional equipment prior to converting to closed loading. As a minimum, a full- depth level monitor with an alarm, an independent high-level alarm, and a closed gauging and sampling connection should be fitted on ships with IG systems. Unpowered barges should have at least a means of monitoring the top few feet of the tank, a restricted standpipe, and, because of their lower design pressure rating, a rupture disk, spill valve, or high-capacity relief valve with intertank overflow capability. The logical next step for barges is to provide a system that reads level warning and alarm signals aboard the barge and actuates alarm and control devices at the terminal. A practical method of doing this can be realized by installing currently available sensors aboard the barge, explosion-proof alarm and control enclosures routinely fabricated for refineries, and intrinsically safe circuitry, also currently available, between dock and barge. The configuration of the connection between the barge and the dock cable, presumably a plug and socket arrangement, would need to be accepted as an industrywide standard to ensure that any barge can connect to the alarm system at any marine terminal.
66 Hydrocarbon Vapor Recovery and Disposal Systems Several established processes can be used to reduce the hydrocarbon vapor emissions from crude oil and gasoline loading. The control pro- cesses fall into two broad categories: combustion and recovery. Combus- tion processes include flares and incinerators. Recovery processes include lean oil absorbers, refrigeration systems, and carbon-bed absorbers. The optimal process for one vapor control application may not be optimal for another. In selecting a process for a given situation, the most important decision is whether or not to recover the hydrocarbon. This decision depends primarily on · the nature of the vapor stream, specifically, its expected variability in flow rate and hydrocarbon content; and · locational factors, such as the availability of utilities and the distance from the tankship or barge to the vapor control facility. To prevent flame flashbacks, each hydrocarbon-containing line that feeds the flare needs to pass through at least one detonation arrestor. This is especially important for the line between the cargo compartments and the combustion or recovery equipment. When Combustion Is Preferable to Recovery Compared to hydrocarbon recovery systems, flares and incinerators are inexpensive to install and easy to operate. They will probably be more economic at low-volume terminals that are located far from existing utility hookups. This is especially true if the vapor vented from tank- ships and tank barges is lean, and the potential value of the recovered hydrocarbon is low. When Recovery Is Preferable to Combustion It may be economic to recover hydrocarbon from large, relatively rich streams at high-volume terminals that have adequate space and easily accessible utilities. Recovery equipment costs more to install and operate, but the value of the recovered hydrocarbon makes recovery cost-effective, especially at terminals with adequate space and easily accessible utilities. Recovery Followed by Combustion Most recovery processes can recover 80-95 percent of the hydrocarbon with moderate installation and operating costs. However, it becomes prohibitively expensive to remove much more because the operating condi- tions become too severe (e.g., temperatures below -200°F, pressures above 250 psia).
6_ 7 If further reduction is needed, a small flare or incinerator should follow the recovery unit to polish the outlet stream. A polishing com- bustor can be designed small, since it will see a lean, steady feed. Combustion Processes Flares and incinerators combust hydrocarbon-containing vapors as they arrive from the vessel or from intermediate vapor recovery equip- ment. The combustion products are mainly CO2 and H2O; small amounts of NOx and CO are also produced. Both flares and incinerators are more than 98 percent efficient if operated properly. They can perform reliably as the sole hydrocarbon control process; and even more reliably as polishing units. The primary drawback is that they do not recover the hydrocarbon. The value of unrecovered hydrocarbon can be significant when crude or gasoline is being shipped. Another potential drawback is that combustion devices can be rela- tively unsafe, simply because they are potential ignition sources. This concern is especially important if the displaced vapors are not inerted. Vapors from vessels with inert gas systems will have oxygen contents below 11 percent--too low to support combustion. The lack of oxygen will greatly reduce the risk of explosion. It will also require the combustion system to draw in additional air (to raise oxygen levels to the point where the mixture will burn). Diluting the vapors will increase the size of the combustor and the amount of supplemental fuel needed to maintain minimum combustion temperatures. Open Flares Open flares have been used by refineries and chemical plants for decades. Almost all were installed as plant protection and safety devices. However, during the past 5 to 10 years, an increasing number have been installed specifically to reduce hydrocarbon emissions. The vapors ignite as they pass through one or more burners. Several different burner head designs are available to maximize combustion. They vary in size and shape depending on the design flow rate, the design hydrocarbon content, and turndown requirements. To maintain a flame at all times, every flare needs a pilot burner in case the main flame goes out. The pilot burner is much smaller than the primary burners. Advantages Open flares are the least expensive control option. They require little operator attention and will sustain burning on their own as long as the incoming vapors contain enough hydrocarbon. As long as the combustion zone stays properly lighted, they are usually more than 98 percent efficient.
68 Disadvantages If the hydrocarbon content drops too low, supplemental fuel will be needed to prevent significant drops in efficiency (poten- tially to zero if the flame goes out). In shipping applications, supplemental fuel will probably be needed until the end of the loading cycle, unless the cargo is exceptionally volatile. Although flares are effective hydrocarbon removal devices, it is difficult to demonstrate whether or not they achieve the commonly be- lieved 98 percent efficiency level. Industry and the EPA have conducted numerous tests and have agreed that efficiency of more than 98 percent is typical. Nonetheless, lack of demonstrability may limit applications in areas where state and local regulators want proof in the form of rigorous field tests. The radiative heat given off by flares is a concern, but not a major one. Flares, especially open ones, need to be located away from people and equipment. By comparison, location of an incinerator is somewhat less of a concern, since its combustion zone is enclosed. Noise and visual impact are other minor disadvantages of flares, particularly open flares. These factors do not affect performance or safety, but may affect an operator's chances of getting permits for equipment. Enclosed Flares An enclosed flare is essentially an open flare with a protective cylindrical shroud around the burners. The shroud helps increase natural draft and aerate the combustion zone. The shroud also helps minimize the impact of wind and other disturbances. Enclosed flares are open to the atmosphere on top. On the bottom they have louvers to help control the inflow of combustion air. The louvers increase the efficiency somewhat by reducing the excess air. However, louver adjustment is usually performed manually and is not very accurate. On some enclosed flares the louvers are not adjustable. Advantages Enclosed flares are somewhat easier to test for compliance than open flares. Flue gas samples can be drawn from within the stack. Thus, even though it is difficult to determine how much air enters through the louvers, measurements are more likely to be accurate than those around open flares. Enclosed flares also radiate less heat and are less noisy than open flares, especially when designed large enough to contain the combustion zone within the stack. Disadvantages Enclosed flares are more expensive than open flares. They are also subject to capacity limitations.
69 Incineration Incinerators, when properly run, are at least as efficient as flares. Combustion is carried out in a confined chamber under con- trolled conditions (Figure 3-3~. Vapors enter the reaction chamber, ignite, then exit through the stack. Supplemental combustion air and fuel are added to the reaction mixture to maximize combustion effi- ciency. Combustion air is added to maintain a slight excess of oxygen. Supplemental fuel is added to maintain the desired operating tempera- ture. Process control for both systems is achieved through use of temperature sensors in the stack. The inside of the incinerator's reaction chamber is lined with refractory material, to help seal in the heat and maintain the operating temperature. This minimizes use of supplemental fuel. To further increase combustion efficiency, the reaction chamber is sized so the vapors spend at least 1 second in the chamber under all operating conditions. The operating-temperature window is chosen to destroy the maximum amount of the hydrocarbon without forming unacceptable amounts of NOx. (The incinerator hardware can usually tolerate temperatures well above the desired operating temperature.) Incinerators have quench air supplies to control high-temperature excursions. If the temperature of the flue gas rises too high, a high- temperature alarm will warn the operators and a quench air fan will blow air through the reaction chamber. Advantages Incinerators are easier than flares to test for compliance, since both the inlet and outlet flow rates and compositions can be measured. This fact will be increasingly important in the future if state and local regulators insist on compliance demonstrations. Incinerators may be slightly more efficient than flares. If oper- ated properly they can achieve more than 98 percent hydrocarbon destruc- tion over larger ranges of flow rates and hydrocarbon contents. Incinerators can be designed to recover heat. The heat can be used to generate steam and heat tanks at the loading facility, thus partially offsetting energy costs. (It may or may not be economic to do so.) Disadvantages Compared to flares, incinerators are more costly and complex to install and operate. Recovery Processes Compared to combustion processes, recovery processes are complex to design and operate. Nonetheless, in some cases the value of the recov- ered product may be worth the extra expense.
70 Supplemental Fuel Lean Vapor to Atmosphere Split Range 1 HO ~ - TRC 'l ~ b PCV Flame Arrestor 1 O2}~__ Rich Vapor from the Vessel . ~ ,, Incinerator/ Thermal Oxidizer Pilot Fuel Combustion Air mu. = . ,¢ Cat Quench Air . , . ~ Variable Speed Air Blowers FIGURE 3-3 Hydrocarbon combustion by incineration. The controls shown are for normal operation. Additional controls may be needed for startup, shutdown, and emergency operation.
71 Several commercially proven vapor recovery processes are used in a variety of marketing and refining applications, and would lend them- selves to tankship- and barge-loading applications: · lean oil absorption, · refrigeration, and · carbon bed adsorption. Lean Oil Absorption Lean oil absorbers use condensation and cooling under pressure to transfer hydrocarbons from a rich vapor into a lean oil (Figure 3-4~. Lean oil absorption processes are very efficient at recovering hydro- carbon from rich streams, but much less efficient at removing hydro- carbon from streams that contain little hydrocarbon. Lean oil absorbers usually operate at pressures of 100 to 200 psia. To further reduce the exiting vapor's hydrocarbon content, some absorp- tion units also cool the lean oil. Typically, an absorber can remove 80-90 percent of a vapor's hydrocarbon by pressure increase alone. Effi- ciencies up to about 95 percent can be achieved by also lowering the operating temperature. At temperatures much below 60°F hydrate formation may cause freeze- up problems. If the system is under pressure, water can also freeze, even at temperatures above 32°F. Antifreeze (e.g., ethylene glycol) can be used to lower the liquid hydrocarbon's freezing point. Unless they are inerted, the vapors vented during loading are often explosive. Since potential spark sources exist in the compressor, absorber, and other processing equipment, it is important to overenrich the vapors. Overenriching can be accomplished by sending the vapors through a saturator. (Inerting of noninerted vapor at the dockside is an undesirable alternative. All nonhydrocarbon gases will leave the absorber saturated. Hydrocarbon emissions will increase if additional inert gas flows through the absorber carrying equilibrium amounts of hydrocarbon with it.) A vapor bladder should be installed upstream of the compressor. The bladder will help dampen variations in vapor flow rate and hydrocarbon content and thus allow a smaller absorber to run for longer, lined-out periods, yielding vapor with a low, predictable hydrocarbon content. Any hydrocarbon liquid with sufficiently low vapor pressure can be used as the lean oil; the decision is an economic one. Marketing terminals use gasoline. Tankship- and barge-loading facilities could use crude, product, or another specially designated lean oil supply. The recovered hydrocarbon could either be incorporated and sold as part of the lean oil or stripped from it and dealt with separately. When possible, it is less expensive to use the stock being loaded, then return it to a storage tank or to the vessel being loaded. The limitations on this alternative are as follows: · The recovered light ends may cause the stock to become off- specification, owing to an increase in vapor pressure or air content.
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73 (This is often a problem if refined oil is used, but is rarely a concern if crude is used.) · The recovered light ends may increase the lean oil's vapor pressure, thus limiting its ability to absorb additional light ends. -Advantages Absorption units are effective at recovering 80-95 percent of a vapor stream's hydrocarbon, if significant amounts are present. Disadvantages Absorption processes can only reduce a vapor's hydro- carbon content to 1-3 percent (volume) economically. Lower emissions would require excessively high pressures and/or excessively low tempera- tures. This performance limitation could limit the usefulness of lean oil absorbers in shipping applications, since vented vapors are likely to be lean during most of the loading cycle. (If the incoming vapors contain less than the absorber's equilibrium hydrocarbon content, say 2 percent, then the absorber will actually enrich them.) These problems can be solved in two ways. First, if lower emissions are needed, one can route the absorber off-gas to a small polishing flare or incinerator. Second, to avoid enriching the vapors, one can use an on-line hydrocarbon analyzer upstream of the absorber to bypass vapors if they contain unrecoverable amounts of hydrocarbon. Direct Refrigeration Direct refrigeration systems remove hydrocarbon by cooling the vapors through a series of low-temperature heat exchangers. -No lean oil is used (Figure 3-5~. These systems are best suited to vapors from non- inerted product carriers--vapors that do not contain as much CO2, light ends, or corrosion-causing contaminants, such as H2S. Most direct refrigeration systems use sea or river water to cool the vapors to around 60°F. This step removes most of the water (humidity) and heavy hydrocarbons. Next, as many as four refrigeration loops cool the remaining vapor to somewhere in the -100°F to -150°F range. The number of loops needed and the intermediate operating temperatures depend on the hydrocarbon species present and the percentage recovery desired. Usually the first exchanger drops out water at around 32°F, the second cools to below 0°F for intermediate-weight hydrocarbons, and so on. To further improve hydrocarbon reduction, it is useful to compress the vapors, thus further reducing the equilibrium hydrocarbon content. Compression is usually done after the first or second exchanger, when most of the easy-to-recover water and heavy hydrocarbons have been removed. After the vapor has passed through the low-temperature exchangers, it is expanded down to ambient pressure as it is vented to the atmos- phere. This expansion lowers temperature further and drops out addi- tional hydrocarbon. If the expansion is done through an ordinary control valve (i.e., isenthalpically), the vapor's outlet temperature
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75 will drop 5-15°F. However, if the expansion is done through a turbo- expander (i.e., isentropically), the temperature will drop 50-70°F. Thus, outlet temperatures below -200°F are achievable. Advantages Since very low temperatures are possible, direct "refrigeration can sometimes remove more than 99 percent of a stream's hydrocarbon. Disadvantages Below 60°F hydrates may form and plug heat exchange sur- faces and lines. One way to avoid this is to inject ethylene glycol or other antifreeze, but this gets very expensive at low operating tempera- tures. Another solution is to operate the unit intermittently to allow periodic thawing. This approach, however, requires overdesign and may impose limited loading rates on tankships and barges. Inerted vapors contain about IS percent CO2 by volume. Therefore, as a practical limitation, refrigeration systems that handle inerted vapors should not be operated below -150°F (the freezing point of co2 ~ Refrigeration systems also tend to corrode if they contain species such as H2S. To minimize corrosion, crude vapors should be pretreated with caustic before they enter the refrigeration unit. Carbon Bed Adsorption Carbon bed adsorbers use activated carbon or a similar adsorptive medium to adsorb hydrocarbon selectively. Air and very light hydro- carbons pass through the medium, while heavier hydrocarbons are adsorbed to the medium's surface (Figure 3-6~. After the capacity of the medium is used up, that is, after most of the adsorptive sites are already holding hydrocarbon, hydrocarbon will "break through" and appear in increasing amounts in the exiting vapor. At this time, the medium needs to be recharged, or the existing vapor will eventually contain as much hydrocarbon as the untreated vapor, and the pressure drop may become unacceptable. Although disposal of spent carbon is an option, most shipping appli- cations are large enough for regeneration to be cost-effective. The best approach is to use a vacuum pump to desorb hydrocarbon (Figure 3-6~. The alternative, steam stripping, generates an oily wastewater stream that needs to be disposed of. In addition, a source of steam is needed. Carbon beds are sometimes used as polishing units downstream of ab- sorption or refrigeration units. They do this very effectively as long as the hydrocarbons are not too light (e.g., ethane or propane). Such light species tend not to adsorb, and even if they do, the adsorption is not very strong; slight temperature increases may drive them off. Alter- natively, when heavier, more strongly attracted species pass through the bed, they will simply displace the lighter species from the active sites.
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77 Carbon beds may also be used upstream of absorption units. In such systems, hydrocarbon-rich vapors are first passed through the carbon bed. Then, when regeneration becomes necessary, a vacuum pump sucks the hydrocarbons from the bed and sends them to a high-pressure absorber for recovery (Figure 3-6~. Carbon beds operate effectively whether or not the vapors have been inerted. Advantages Carbon bed adsorbers can be more than 99 percent effective at removing hydrocarbon. Disadvantages Carbon beds do a poor job of recovering light ends, such as ethane and propane. H2S and other contaminants permanently poison activated carbon. Therefore, in crude and other dirty services regeneration becomes impos- sible and carbon replacement costs become prohibitive. The poisoning problem can be avoided by upstream treatment with caustic, but this adds to cost. H2S contamination is not a concern for vessels that trans- port gasoline. Vacuum Resorption requires an absorber to recover the desorbed vapors. This makes them more complex than absorption by itself because the two processes are interwoven. (The only reason for combining the two is to achieve very high efficiencies without the use of a flare or incinerator.) Carbon beds would need to be very large to handle the high flow rates and hydrocarbon loadings generated by most shipping applications. To be practical, each bed would need to be large enough to handle at least one full-loading cycle before regenerating. Alternative and Emerging Technologies Several alternative technologies have been suggested as ways to help reduce vapor emissions. Catalytic combustion, it has been proposed, could substitute for flares and incinerators now used to burn vapors. Evaporation-retardant chemicals could be used to blanket cargoes, reduc- ing evaporation and thus lowering the amount of hydrocarbon in vapor. Biofiltration and semipermeable membranes also may offer promise in decomposing or recovering vapors in the future. Catalytic Combustion Catalytic combustors are an alternative to thermal combustors. Their main applications include combustion of vapors from solvent and paint dryers. Such vapors are dilute, relatively stable in flow rate and composition, and contain few, if any, contaminants. Catalytic combustion does not, however, appear to be a practical process for controlling hydrocarbon emissions from crude and gasoline
78 loading; the vapors are far too rich and contain too many contaminants. Recovery or thermal combustion (using a flare or an incinerator) is much more practical. This is true even if the displaced vapors pass through a vapor recovery unit first. Vapors displaced from vessels will contain 0-30 percent or more hydrocarbon. After recovery they will contain 0-3 percent hydrocarbon. In either case, the hydrocarbon concentration will often be several times the 0.1-0.5 percent level that is optimal for catalytic combustion. In addition, crude and heavy product vapors invariably contain H2S and many other contaminants. These species will quickly reduce the catalyst's activity, often irreversibly. Catalytic combustors rely on an active catalytic surface (usually noble metals on a silica or alumina base) to lower the activation energy and time needed for combustion. For this reason, they can combust low-hydrocarbon~content vapors with more than 95 percent efficiency at low temperatures, typically only 600-900°F. Ideally, the feed vapors contain between 0.05 and 0.75 percent hydrocarbon, corresponding to hydrocarbon concentrations between 5 and 75 percent of the lower explo- sive limit (typically around 1 percent hydrocarbon in air). Thermal combustors rely on a homogeneous gas-phase reaction. They need to operate in the 1,200-1,800°F range to achieve more than 95 per- cent efficiency since they do not have the benefit of a catalyst. As long as vapors contain enough hydrocarbon they will sustain combustion on their own without catalyst, but at lower concentrations, supplemental fuel may be needed to keep the reaction going. This is very expensive for large, dilute streams, and makes catalytic combustion attractive for such streams. If the hydrocarbon content rises over 1 percent, the catalytic com- bustor's temperature will rise above 1,000°F. This accelerates sinter- ing (also referred to as thermal aging); the finely dispersed noble metals become liquid, migrate within the catalyst pores, and meld together into much larger droplets. This melding reduces the active catalytic surface area, in extreme cases by orders of magnitude. Catalytic combustors are very sensitive to contaminants. Particu- lates and char foul the catalyst surface and plug the bed. Heavy hydrocarbons, silicone compounds, and some oxides mask the catalyst by forming a filmy deposit on the surface. Still other contaminants, expecially H2S, chlorides, and most metals, inhibit combustion by poisoning the catalytic sites. Gross fouling can be reversed by physical cleaning. Masking can be reversed by washing with an aqueous solvent or, sometimes, by controlled overheating. These regenerative processes degrade the catalyst slightly each time, but usually restore it adequately the first few times. Poisoning is a greater problem. With some poisons it may not be possible to regenerate the catalyst. Many manufacturers recommend keeping the concentration of poisons in the feed stream below about 0.25 parts per million (ppm).
79 Vapor-Suppressing Foams Vapor-suppressing foams may be an attractive alternative to onshore vapor control (Canevari and Cooper, 1974~. Companies that market these foams believe they could be used to seal in the light hydrocarbons that normally vaporize during both loading and unloading. The foams are aqueous-based and biodegradable. After about 24 hours they collapse, form a waterlike solution, and sink to the bottom. For the foams to achieve a high degree of vapor control, vessel operators would need to generate them on board, then spread and maintain a 2- to 6-in. layer on the liquid hydrocarbon's surface throughout the off- loading and loading cycle. Refiners have used vapor-suppressing foams for many years. They retard fires and inhibit evaporation of most hydrocarbons on which they are sprayed. To date, however, they have been demonstrated only in firefighting and spill-control applications. As a result, the following issues need to be resolved before the use of foams can be considered a viable control measure: o What hydrocarbon control efficiency can the foam offer? The foam layer would need to be maintained at all times. This could rule out crude oil washing (COW) and similar tank cleaning, since these opera- tions would tend to collapse the foam and saturate the vapor space. Some foam manufacturers have discussed the feasibility of using foams during loading to control emissions and to maintain tanks in gas-free condition. However, much of the vapor emitted is generated by volatili- zation during offloading, and further saturation during compartment washing. Unless the foam is also maintained during off-loading and compartment washing is discontinued, overall efficiency would be low. · How can one make sure the foam is spread deeply enough in every part of each compartment? If any cargo is exposed to the vapor space, the efficiency of the overall system will drop. o Would spray nozzle systems be needed on each ship? COW nozzles could be used, but they might need to be resized and aimed properly. o Will the flow of fluid through the foam sprayer cause static electricity generation and buildup, and thus increase the risk of an explosion? Sprayers should probably be used only on inerted vessels. e Is the foam corrosive? It will be necessary to check compati- bility of the foam with PV relief valves, control valves, deck under- coatings, and so on. o Will the foam affect product specifications, form emulsions down- stream, or cause operating problems in downstream processing equipment? Such hidden costs would need to be quantified. (The emulsion problem may be avoided by using protein-based foams instead of surfactant-based foams.) o Will the collapsed foam cause cargo measurement problems?
80 Molecular Layer Vapor Barrier A patent granted to the Exxon Corporation (Canevari, 1980) describes a method of lowering vapor losses by spraying a thin (350 monolayer) film of evaporation-inhibiting material on the cargo. The patent states that a field test was conducted during the unloading of light Arabian crude from a commercial tankship, and that 2 hours after discharge the tank so treated contained 44 percent less vapor than a similar untreated tank. If this material were sprayed on a crude or gasoline cargo shortly after the start of loading in a gas-free tank, and the surface of the cargo were quiet, it might reduce the normal evaporative loss substan- tially. The patent says that only about 3.5 gallons of the material would be needed to treat the cargo in a 90,000-dwt tankship. The use of this material shows promise, but further shipboard test- ing will be necessary before it can be considered safe and effective. Biofiltration Biofiltration requires cultivation of bacteria that can oxidize hydrocarbons from contaminated air. The bacteria needs to be grown on moist medium (e.g., on the wet surface of a gravel bed). Then the con- taminated air passes through the medium, the hydrocarbon will diffuse into the liquid film and oxidize to CO2 and water. These products will then diffuse back into the gas stream. Membrane Separation Membrane separation relies on a semipermeable membrane to screen out hydrocarbon selectively. Oxygen, nitrogen, and other gaseous species normally present in air will pass through. Hydrocarbon, H2S, and other undesirable species will be held back. VAPOR BALANCING AS AN ADJUNCT TO VAPOR CONTROL The technique known as vapor balancing can be used as an adjunct to vapor control to reduce instantaneous processing rates, or for other reasons. For example, at Exxon's offshore Hondo Field in California, loading emissions are pumped into a large tank vessel where they are retained for subsequent burning. The vessel acts as a buffer, permit- ting loading rates higher than could otherwise be accommodated by the vapor treatment facilities at the site. Vapors are drawn from the holding tanks at a constant rate, not dependent on instantaneous loading rates. But vapor balancing should not be regarded as a standard procedure. The roofs of many modern storage tanks are designed to float on the surface of the liquid, leaving no space for vapors. There may be appli- cations for vapor balancing at specific sites.
81 OPERATING PROCEDURES TO REDUCE EMISSIONS FROM TANKSHIPS Hydrocarbon vapors are heavier than air, hence tend to lay in a con- centrated layer just above the liquid surface. By short-filling compart- ments, vessels that load crude oil or gasoline can retain most of the hydrocarbon vapors onboard while in port, and then later release them to the atmosphere at sea. This approach will reduce in-port emissions from tankships substantially, but its economic application and environmental acceptability would be highly site-specific. Ballasting Emissions Ballasting emissions of volatile organic compounds (VOCs) already have been significantly reduced by regulations requiring most tankships of 20,000 dwt or more to use segregated ballast tanks (SBTs) or clean ballast tanks (CBTs) and to retain ballast vapors from cargo tanks aboard the tanker, where feasible. In the future all new crude tank- ships over 20,000 dwt (30,000 dwt for product carriers) in U.S. waters will eliminate all VOC ballasting emissions, because they will be equipped with SBTs. Existing crude oil tankers, if fitted with COW facilities, may not have sufficient SET or CBT. However, U.S. Coast Guard regulations now require that "each tank vessel having a COW system--without sufficient SBT or CBT--must have a means to discharge hydrocarbon vapors from each cargo tank that is ballasted to a cargo tank that is discharging crude oil." This transfer of vapors is accomplished using IG vent lines. Using this arrangement, VOC emissions from ballasting are eliminated. Loading Emissions Hydrocarbon vapors are denser than air. Recent safety guidelines for the tankship and marine terminal industry (International Chamber of Shipping et al., 1984) state that As . . . cargo enters an empty gas free tank there is a rapid evolution of gas. Because of its high density the gas forms a layer at the bottom of the tank which rises with the oil surface as the tank is filled. Once it has been formed the depth of the layer increases only slowly over the period of time normally required to fill a tank, although ultimately an equilibrium gas mixture is established throughout the ullage space. Above this layer the atmosphere originally present in the tank persists almost unchanged and it is this gas which in the early stages of loading enters the venting system. In an initially gas free tank, there- fore, the gas vented at first is mainly air (or inert gas) with a hydrocarbon concentration below the Lower
82 Explosive Limit (1 percent HC). As loading proceeds, the hydrocarbon content of the vented gas rises. . . . iT]he gas layer depth will be taken as the dis- tance from the liquid surface to the level above it where the gas concentration is 50 percent by volume. . . . tG]as will be detectable at heights above the liquid surface several times the layer depth defined in this way. Most high vapor pressure cargoes give rise to a gas layer with a depth in these terms of less than 1 meter. The 83 tons of emissions that result, on average, from loading a 100 percent crude-oil-washed VLCC have been analyzed as shown in Table 3-1 (Uhlin, 19849. Atmospheric emissions while loading cargo are minimized by filling each compartment as rapidly as possible, to reduce the amount of evapora- tion into the ullage space (an exception to this is at the start of load- ing when rapid rates may cause splashing, which increases evaporation). Loading into Gas-Free Cargo Tanks Table 3-1 shows that gas-freeing of cargo tanks on the ballast pas- sage combined with loading into the gas-freed tanks would reduce VOC vapor emissions by about one-third. TABLE 3-1 Atmospheric Emissions Loading 250,000-dwt Crude Carrier (all tanks COW) Vapor Emissions Vapor in empty tanks before loading Evaporative loss during loading and gauging Subtotal In ullage space after loading and gauginga Atmospheric emissions during loading and gauging Initial gauging Emissions during loading and final gauging Tons 35 58 93 86 3 83 aThe ullage space after loading eventually reached equilibrium and registered 50 percent hydrocarbon equal to 15 tons on arrival at the discharge port.
83 Gas-freeing all the cargo tanks on the ballast passage would in- crease bunker fuel costs. In addition, it might delay crude oil washed tankships at the discharge port. Loading to 70 Percent of Capacity Loading each gas-freed cargo tank only 70 percent would retain most of the vapors in the ullage space. To minimize sloshing at sea, the cargo could later be transferred to fill most of the tanks to capacity. This technique could reduce carrying capacity by 30 percent; thus its economic acceptability would need to be evaluated. HYDROCARBON VAPOR CONTROL SYSTEMS: ASSUMPTIONS FOR PURPOSES OF ASSESSMENT Since vapor control systems are not widely used in maritime applica- tions, the committee found it necessary to set some ground rules for analyzing cost estimates. The resulting hypothetical system is intended to meet all likely regulatory requirements and incorporate all safety features. It uses available technology and would be capable of reducing loading and ballasting emissions at terminals by more than 99 percent. The assumptions that underlie the system are: · Vapors will be inert or overrich prior to being treated or trans- ferred any significant distance. · Incineration is the control process in all estimates. It has low capital cost and universal application. · Detonation arrestors will be placed in vapor pipelines near the treatment system, at the dock manifold, and at the tank vessel's mani- fold. Flame arrestors are not considered to be an acceptable substi- tute. · Redundant tank gauging and alarm systems will be used for closed loadings. · Shoreside loading facilities will have provisions for automatic shutdown (using contact signals from the alarm systems). · Loading at terminals will remain at current loading rates. · Tank vessels loading at docks that serve only tankships and large inerted tank barges will have onboard systems for closed loading with redundant gauging and alarm capability and an inert gas system designed for less than 7 percent O2. · All tank vessels will be outfitted with vapor collection headers sufficient to accept vapors at full-loading rates. · All cargo tanks that are inerted will be fitted with vapor locks for use with sonic gauging tapes. If not inerted (as with most tank barges), cargo tanks will be fitted with restricted standpipes extending to just above the tank bottoms. · Docks at terminals serving only tankships and large inerted tank barges will be designed to accept inerted vapors coming from the vessels.
84 · Except as noted above docks at terminals serving smaller, non inerted tank vessels will provide a means for inerting vapors coming from the vessels as they enter the vapor transfer system. · For smaller tank vessels without onboard inerting equipment, the vapor stream may be inerted during loading. Vapor Collection Headers For most tankships fitted with IG systems, the installed inert gas headers can, with a few modifications, be used as vapor collection headers. Noninerted tankships and tank barges will require the installa- tion of one or more deck headers to collect vapors from the tanks and carry them to the vapor hose connections located in way of the cargo- loading manifold. Figure 3-7 shows a typical vapor connection header for a tank barge. The vapor collection header will be of steel construction. Internal coating must be compatible with the products to be carried. Tank PV valves should be set for the highest pressure consistent with tank design. If tanks are fitted with individual PV valves, one additional PV valve should be installed on the vapor collection header. This valve and its header should be sized for the maximum loading rate to all tanks served by the header. A rupture disk or spill valve should be installed in the vapor header to limit tank pressure to the hydro- static test pressure of the tanks in case of overfill. Such a device should relieve liquid to a cargo tank or another enclosure. The vapor collection header should be designed to allow for 1.0 psi (0.5 psi for harges) back pressure at the vapor hose flange during maximum-rate load- ing with tank pressures below the PV valve setpoint. If multiproduct loading of cargoes susceptible to cross-contamination is expected, tanks should have individual PV valves. Line blinds or valves should be pro- vided at the vapor connections to the tanks. A detonation arrestor should be located as near as possible to each vapor hose connection and installed to be easily removed for cleaning and maintenance. A shipboard pressure control system should be consid- ered to allow the ship to control the cargo tank pressure independent of the shore facility. A drip pan, wide enough to accept a reducer, should be located under each vapor hose connection to catch any condensate during hose removal. The vapor hose connection may be of either bolted or cam lock type and should accept both standard 125 pound or 150 pound flanges from the hose. * An alternative method of rendering the vapors nonexplosive would be to enrich them. Enriching would minimize the quantity of vapors to be processed.
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86 Tank Gauging and Alarms for Inerted Tank Vessels Inerted tank vessels are assumed to have two independent tank gaug- ing and alarm systems, one to measure the full tank depth, the other to measure the top 6-10 ft below deck. A single gauging system may be used if it is inherently redundant by design. In this case, however, a sepa- rate and redundant alarm system should be installed. The gauging and alarm systems are assumed to have an accuracy of bet- ter than 0.5 in., and two alarm setpoints, each redundant. The system includes a high-level warning at about 12 in. below the top of the tank and a high-level alarm at 4-6 in. below the top of the tank. If loading is conducted from a cargo control room, level indication and alarms are displayed in the room with audible and visual alarm indications on deck. If cargo operations are carried out on deck, level indicators are located at the tanks, with audible and visual warning and alarm indica- tions placed where they will be heard and seen from anywhere on deck. The alarm system provides a means for supplying pump shutdown contacts at the tankship's rail for use by the terminal's emergency shutdown system (where available). Special Considerations for Tank Vessel Inert Gas Systems Either flue gas or independent IG systems are acceptable if the vapor mixture leaving the tank vessel has an oxygen content of less than 8 percent at all times. The system should therefore be designed to pro- duce inert gas with as low an oxygen content as possible, but no greater than 7 percent. The tank vessel's IG system must have sufficient instru- mentation and a recorder to allow the terminal to verify the proper inerting of the tanks during the prior discharge. Dockside Tank Level and Alarm System for Tank Barge Loading Each cargo tank is assumed to be fitted with a reliable high-level alarm and shutdown sensor. Each has a fail-safe method for checking the instrument and circuit prior to each loading. Each instrument provides two separate, normally closed contacts to initiate the high-level warn- ing and high-level shutdown independently. Each instrument has two setpoints: a high-level warning at 12 in. below the top of tank and a high-level alarm at 4-6 in. below the top of tank. Warning and alarm/shutdown signals are both audible and visual and easily detected from both the loading manifolds and the barge dock. Instruments are connected through intrinsically safe cable to weath- ertight nine-pin connectors near the loading manifolds. Each connection serves the instruments of four tanks. All instruments and cables out- side the dockside enclosure are intrinsically safe. The dockside enclo- sure may be either explosion-proof or intrinsically safe. The main connecting cables from the dock to the tank barge allow connections for the maximum number of tanks expected in barges that utilize the dock.
87 Two lights for each tank are located on the dockside enclosure. Large (4-6 in.) lenses with dimmer controls ? arranged to represent the layout of the tank barge deck and visible from the barge manifold, are preferred. The system sounds alarms of distinctly different pitch for the high- level warning and high-level alarm/shutdown. Contacts will be provided in the dockside enclosure to activate the dock's emergency shutdown on a high-level alarm. The system has the capability to perform continuity and function checks prior to the start of each loading. To facilitate accurate loading, the barge operator may also wish to provide an unpowered or intrinsically safe solar- or battery-powered gauging system that does not require an external electric source. If no gauging system is provided, a second set of high-level warning/alarm devices must be provided with their contacts wired in series with the other warning/alarm devices such that the signals will be activated if either contact opens. Figure 3-8 is a schematic illustration of a dockside gauging and alarm system for tank barge loading. Figure 3-9 shows the dockside enclosure panel for the system. Vapor-Handling System for Terminals At terminals loading large, inerted tank vessels, the incinerator or other vapor control process and the vapor transfer piping system are sized to receive the maximum loading rate expected for gasoline and crude oil, with a suitable safety margin. At tank barge terminals, the systems are sized for the maximum loading rate plus sufficient addi- tional inerting gas to lower the oxygen content of the vapor stream to less than 8 percent. This may take four or more volumes of inert gas for each volume of barge-emitted vapor, depending on the oxygen content of the inerting gas. As tankship loading rates are frequently five or more times the tank barge loading rates, terminals serving both may find that the required size of the system will be nearly the same, owing to the large volume of inert gas added to the barge vapor stream. Figure 3-10 is a schematic drawing of a simple vapor control system for a tank barge and tankship terminal. Figure 3-11 shows an incinera- tor system for a barge dock. Since the oxygen content of the incinerator exhaust gas can be con- trolled to less than 5 percent with some incinerator designs, operators may consider using this gas as inert gas for tank barge loadings. Other sources of inert gas include fuel-fired inert gas generators, nitrogen, natural gas, and refinery flue gas. To prevent oxygen being drawn into the system, all piping carrying inerted vapors should be under a positive pressure, but not present more than 0.5 psi back pressure at a tank barge flange or 1.0 psi at a tank- ship flange. Underwater pipelines may be at negative pressure only if any extension above water is of all-welded construction. The inlet for inerting gas at barge docks should be as close as prac- tical to the terminal flange. An oxygen analyzer (explosimeter for enriched systems) should be located as close as possible to the terminal
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89 WARNING SHUTDOWN 4-6~. To Barge :: 1P 82P $3p $4p (in) 5p 2S~ 3S:: 4S(0 5 o o o ! EMERGENCY DIMMER ~ ~ SHUTDOWN ty ACKNOWLEDGE o o o o it' Covers in Place to Mimic Ten Tank Barge / To Loading ~ PumpNalve '\ Shutdown FIGURE 3-9 Dockside warning and alarm panel. The following applies: (1) Warning lights are amber and alarm lights are red. (2) The enclo sure is explosion-proof. (3) Wiring to the barge is intrinsically safe. (4) Warning/alarm circuits are open to actuate. (5) High-level alarm actuates siren and shutdown. (6) High-level warning actuates 3-second horn. (7) Warning lights flash for 3 seconds then are on steady. (8) Alarm lights and siren must be acknowledged. (9) Each nine-conductor cable serves four tanks.
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92 flange, but downstream. of any inert gas inlet. A trip valve at the terminal flange should be designed to close if an oxygen concentration of 8 percent or more is detected. If a booster is required because of a pressure drop through vapor transfer piping, a recirculation loop with a cooler or other type of capacity control should be used to maintain a positive pressure at the booster suction. Care must be taken in the design and operation of the vapor transfer system to eliminate any ignition sources. Temperatures in piping and other components of the vapor transfer system should be kept well below the vapor ignition temperature, whether vapors are inerted or not. At a minimum, detonation arrestors and rupture disks should be located at the terminal flangefs) and at the inlet to the vapor control process. A final oxygen analyzer (explosimeter) should be located near the vapor control process, but far enough upstream to ensure closure of the trip valve before the potentially explosive vapors reach that point.
