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5 COST-EFFECTIVENESS The cost of emission control is a central issue. On a gross level, as a proportion of the industry's throughput, it appears manageable. According to estimates prepared for the committee, the annualized cost would be less than 1 percent of the value of cargoes handled. However, these costs may be more burdensome on some parts of the industry than on others. Case studies conducted at the direction of the committee suggest, for example, that installing an operating vapor con- trol facility at a small terminal in Texas would add $0.008 per gallon of gasoline loaded, while the cost at a larger terminal would rise only $0.0036 per gallon. Some smaller companies, especially in the inland barge industry, may have problems financing the necessary investments. On the basis of dollars per metric ton of emissions prevented, the case studies show costs of $5,206 per metric ton and $2,944 per metric ton, respectively, for the small and large terminals. Additional calcu- lations confirm the strong dependence of cost-effectiveness on terminal throughput. To obtain realistic and consistent estimates of the costs of com- plying with possible requirements for hydrocarbon vapor control, the committee developed hypothetical design assumptions (see Chapter 3, ''Hydrocarbon Vapor Control Systems: Assumptions for Purposes of Assess- ment.") For consistency and comprehensiveness, the committee esta- blished seven cases for estimation purposes, covering a range of vessel and terminal types. These assumptions were used in two independent cost studies (one commissioned by the committee) to estimate the capital, operating, and maintenance costs of vapor control systems (Booz-Allen & Hamilton, 1987; United Technical Design, Inc., 1987~. THE COST OF CONTROL Capital Cost Estimates The committee commissioned an independent study by United Technical Design (UTD, 1987) to estimate the capital investments in vessels and terminals necessary to meet the standards now under consideration. The UTD study--using seven detailed design cases developed by the committee 108

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109 that specified four different vessel types and three*terminals--esti- mated the cost of installing the necessary equipment : Case 1 Crude Oil Carrier (70,000 dwt) Vessel characteristics are: 800 ft long by 125 ft wide by 55 ft high; draft, 42 ft; 15 cargo tanks with a single gauging and alarm system; boiler flue gas providing inert gas at 5-7 percent oxygen content; normal loading rate 35,000 bbl/hour; 2 pressure/ vacuum (PV) valves on the inert gas (IG) system main set at 2 psi, each sized for full flow; loading manifold midship without header from IG system main. Design assumptions are: IG system and supply header to be used as the hydrocarbon vapor header. The addition of detonation arrestors is the only modification required. ~ Installation of an additional gauging and alarm system is neces- sary to provide redundant tank gauging capability. 5-1~. Case 2 The estimated capital costs of these retrofits total $168,000 (Table Product Carrier (35,000 dwt) Vessel characteristics are: 700 ft long by 90 ft wide by 50 ft high; draft, 39 ft; 24 cargo tanks with no auto- matic gauging or alarms; no IG system; normally carries several grades of motor and aviation gasolines as well as distillate diesel and jet fuels (distributed in tanks based on the sizes of cargo parcels on each voyage); loading rate up to 25,000 bbl/hour; individual PV valves on each tank, set at 1.5 psi; loading manifold midships. Design assump- tions are: Installation of complete inert gas system. * Recent purchasing experience (by a major oil company) suggests that the UTD study's estimated costs for detonation arrestors (which ac- count for one-third of the total estimated cost of the system on barges) may be substantially higher than realistic. Nor are gas-freeing costs and out-of-service time included in the estimates. In its terminal esti- mates, the study assumes the use of incinerator flue gas as a source of inert gas. It does not include the cost of auxiliary fuel supplies for the incinerators. The report also does not address operating costs of the cooling systems for inert gas scrubbers (which can be substantial).

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110 TABLE 5-1 Case 1 Cost Estimate Summary: Crude Oil Carrier (70,000 dwt) Category Cost ($) Vapor header hardware (detonation arrestors and installation) Instrumentation (hardware and installation) Subtotal Engineering and design (assume 10 percent of subtotal) Startup and testing (assume 10 percent of subtotal) Contingency allowance (assume 5 percent of subtotal) Total job cost estimate Rounded-off 63,120 71,400 134,520 13,452 13,452 6,726 168,150 168,000 5-2~. Case 3 gas system to be used as the hydrocarbon vapor header with Inert addition of detonation arrestors and deck connections. Installation of a redundant tank gauging and alarm system. The estimated capital cost of these retrofits is $831,000 (Table Ocean Barge (19.000 dwt) _ ft wide by 30 ft high; draft, 24 ft; i z cargo tanks with gauging or alarms; no IG system; cargo similar to case 2; up to 15,000 bbl/hour; individual PV valve on each tank, loading manifold midship; diesel-driven pumps aft, with no electric generator. Design assumptions are: Vessel characteristics are: 450 ft long by 75 12 cargo tanks with no automatic cargo similar to case 2; loading rate set at 1 psi; Installation of complete vapor header. Installation of a redundant tank gauging and alarm system. 5-3~. The estimated capital cost of these retrofits is $266,000 (Table

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111 TABLE 5-2 Case 2 Cost Estimate Summary: Product Carrier (35,000 dwt) Category Cost ($) Major equipment (hardware and installation) Piping (material and installation) Instrumentation (hardware and installation) Subtotal Engineering and design (assume 10 percent of subtotal) Startup and testing (assume 10 percent of subtotal) Contingency allowance (assume 5 percent of subtotal) Total job cost estimate Rounded-off Case 4 364,000 140,000 161,000 665,000 66,500 66,500 33,250 831,250 831,000 Inland River Bangs Vessel characteristics are: 265 ft long by 54 ft wide by 12 ft high; draft, 9 ft; 10 cargo tanks with no automatic gauging or alarms; no IG system; cargo similar to case 2; loading rate 4,000 bbl/hour; individual PV valves at each tank set at 1 psi; loading manifold aft; diesel driven cargo pump aft, with no electric generator. Design assumptions are: 5-4). Case 5 Installation of complete vapor header. Installation of a redundant tank gauging and alarm system. The estimated capital cost of these retrofits is $168,000 (Table Product Terminal for Barges Terminal characteristics are: two docks des igned to load two barges at each s ide from two loading stations at each dock; loads one product at a time to each barge at 4,000 bbl/hour; space available for incinerator one-quarter mile away; all gasoline storage tanks have floating roofs; transfer pumps located 300 yd from

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112 TABLE 5-3 Case 3 Cost Estimate Summary: Ocean Barge (19,000 dwt) Category Vapor header hardware (including PV valves and installation a Piping (material and installation) Instrumentation (hardware and installation) Subtotal Cost ($) 67,000 65,000 81,000 213,000 Engineering and design (assume 10 percent of subtotal) Startup and testing (assume 10 percent of subtotal) Contingency allowance (assume 5 10,650 percent of subtotal) Total job cost estimate Rounded-off aDoes not include detonation arrestors. 21,300 21,300 266,250 266,000 dock; loadings handled by one person at waterfront and one at tank farm. Design assumptions are: Installation of four complete hydrocarbon vapor transfer lines and associated incinerator feed headers. Incinerator one-quarter mile away supplies inert gas to the dock area. Installation of two full-capacity booster fans arranged in parallel. Installation of terminal alarm system and vapor control system instrumentation. The estimated capital cost of these retrofits is $1.23 million (Table 5-5~. Case 6 Crude Oil Terminal for Ships Terminal characteristics are: single dock designed~to load one ship of up to 75,000 dwt at a time; loads only one type of crude oil at 35,000 bbl/hour; tank farm with space for incinera- tor located 1 mile from dock; 220-volt alternating current (AC) elec

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113 TABLE 5-4 Case 4 Cost Estimate Summary: Inland River Barge Category Vapor header hardware (PV valves/ detonation arrestors and installation) Piping (material and installation) Instrumentation (hardware and installation) Subtotal Engineering and design (assume 10 percent of subtotal) Startup and testing (assume 10 percent of subtotal) Contingency allowance (assume 5 percent of subtotal) Total job cost estimate Rounded-off Cost ($) 50,000 134,200 13,420 13,420 6,710 167,750 168,000 tricity available at tank farm; nearest natural gas service 6 miles away; storage tanks have floating roofs; terminal operated by one person at tank farm and one at dock; only minimal 110-volt AC electric power available at dock. Design assumptions are: Installation of one complete hydrocarbon vapor transfer line and incinerator feed header. Incinerator does not supply gas to the dock area, since vessels are assumed to have own inerting capability. Incinerator located 1 mile from dock area. Natural gas service available 6 miles from the incinerator. The estimated capital cost of making these retrofits is $2.57 million (Table 5-6~. Case 7 Product Terminal Serving Ships and Barges Terminal characteristics are: one pier for loading two ships of up to 55,000 dwt and two docks for loading four inland barges at each dock; each of two tankship loading stations can provide 25,000 bbl/hour, each of eight barge loading stations can load 4,000 bbl/hour; closest available space for

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114 TABLE 5-5 Case 5 Cost Estimate Summary: Product Terminal Serving Barges Category Major equipment (hardware and installation) Piping (material and installation) Instrumentation (hardware and installation) Subtotal Engineering and design (assume 10 percent of subtotal) Startup and testing (assume 10 percent of subtotal) Contingency allowance (assume 5 percent of subtotal) Total job cost estimate Rounded-off Cost ($) 659,000 271,300 49,800 980,100 98,000 98,000 49,000 1,225,100 1,225,000 incinerator is 1 mile from docks; 220-volt AC electricity and natural gas service available 100 yd from space; all gasoline tanks have float- ing roofs; terminal operated by one person at each dock or pier and two at the tank farm. Design assumptions are: Installation of eight complete barge hydrocarbon vapor transfer lines. Installation of two complete hydrocarbon vapor transfer lines. Incinerator supplies inert gas to ship and dock areas. Natural gas service available 900 ft from the incinerator. Installation of terminal alarm system and vapor control system instrumentation. Installation of two parallel sets of full-capacity booster fans for incinerator feed and inert gas feed to the dock area. The estimated capital cost of these retrofits is $7.50 million (Table 5-7~. These estimates suggest that the owners of tank vessels approaching the ends of their useful lives, a significant proportion of the barge fleet, for example, will need to make investments that are large com- pared to the salvage values of the vessels. The estimates also imply rather substantial costs for low-volume barge terminals. In the long run, of course, shippers will pay these costs. In the present slack market for inland barge services, however, the costs will

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115 TABLE 5-6 Case 6 Cost Estimate Summary: Crude Oil Terminal for Ships Category Cost ($) Major equipment (hardware and471,200 installation) Piping (material and installation,1,551,600 gas service included) Instrumentation (hardware and33,700 installation) Subtotal 2,056,5Q0 Engineering and design (assume 10 205,650 percent of subtotal) Startup and testing (assume 10 205,650 percent of subtotal) Contingency allowance (assume 5 102,825 percent of subtotal) Total job cost estimate Rounded-off 2,570,625 2,571,000 not readily be passed through to shippers, unless traffic rises or a substantial number of barges are scrapped. Operating and Maintenance Cost Estimates The UTD study included estimates of the operating and maintenance costs attendant on the seven retrofit cases. These estimates are low, for two reasons. First, the study limited its evaluation of operating costs to basic utilities such as natural gas and electricity, and ascribed all operating costs to the terminals. Second, it omitted from consideration the operating and maintenance costs of cooling water sys- tems for the inert gas scrubbers in cases 5 and 7; in fact, these cool- ing systems can account for substantial proportions of operating and maintenance costs at marine terminals. The estimated annual operating and maintenance costs for the seven cases are presented in Table 5-8. OPERATING COST ESTIMATES FOR INLAND BARGES The barge industry, already plagued by overcapacity and a stagnant market, would bear some of a vapor control requirement's greatest costs. The prospect of installing $160,000 vapor control systems on

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116 TABLE 5-7 Case 7 Cost Estimate Summary: Product Terminal Serving Ships and Barges Category Cost ($) Major equipment (hardware and2,519,200 installation) Piping (material and installation)3,359,000 Instrumentation (hardware and123,800 installation) Subtotal 6,001,800 Engineering and design (assume 10 600,180 percent of subtotal) Startup and testing (assume 10 600,180 percent of subtotal) Contingency allowance (assume 5 300,000 percent of subtotal) Total job cost estimate Rounded-off 7,502,160 7,502,000 TABLE 5-8 Estimated Annual Operating and Maintenance Costs for the Seven Case Studies Case 1. Crude oil carrier (70,000 dwt) 2. Product carrier (35,000 dwt) 3. Ocean barge (19,000 dwt) 4. Inland river barge 5. Product terminal/barges 6. Crude oil terminal/ships 7. Product terminal/ships and barges Operating Cost ($/year) N/A 1,500 N/A N/A 14,000 14,000 32,000 Maintenance Cost ($/year) 4,800 78,000 12,800 9,600 41,000 28,000 79,000 $250,000 barges prompted the American Waterways Operators, an industry group, to request an independent study of the operating and maintenance costs associated with hydrocarbon vapor control in barges (Booz-Allen & Hamilton, 1987~. Using design assumptions developed by the committee (see Chapter 3, "Hydrocarbon Vapor Control Systems: Assumptions for Purposes of Assess- ment"), the Booz-Allen study developed capital cost estimates that agree

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117 with the UTD study as a basis for estimating operating and maintenance costs. Based on the UTD (1987) report and engineering cost estimates obtained from barge operators, the Booz-Allen study estimated capital costs for retrofitting a variety of inland tank barges, from small vessels in "clean" service (carrying gasoline, middle distillates, or other light products) to large ones engaged in "dirty" service (crude oil, residual fuel oil, and similar cargoes). The cost of retrofitting the 20,000-bbl barge specified in case 4 of the UTD report, the Booz-Allen study estimates, is $160,000 (reasonably close to the UTD estimate of $168,000~. A 5-year-old, 10,000-bbl barge would cost $96,000 to retrofit, according to the Booz-Allen study. The cost could reach $250,000, the study found, in a 50, 000-bbl barge in dirty service. Figure 5-1 displays the study's range of estimated costs for retrofitting inland barges of various ages, sizes, and tank arrange- ments. Installing vapor control equipment on barges would raise operating costs for maintenance and repair, crew training, tank cleaning, and insurance, according to the Booz-Allen study. On the representative 10,000-bbl barge, maintenance costs would rise from $19,000 annually to $25,000 or more, depending on the durability of automated gauging and alarm systems. Training tankermen to operate vapor control systems would cost $4,000 initially, per barge, with a recurring cost of $2,000 per year. Annual tank cleaning costs are estimated to rise by $5,000 on the representative barge, which is assumed to operate in clean service, and thus to need frequent cleaning. Insurance costs would rise by somewhat less than $1,000 per year. In addition, according to the study, each barge would lose revenue owing to the imposition of vapor controls. The representative 10, 000-bbl barge would need to be taken out of service for 4 days, at a loss in revenue of $1,000, while the necessary hardware was installed. Barges also would spend more time at docks during loading, while the vapor control systems were being connected, inspected, and disconnected, at an annual cost estimated at $2,000 for the representative barge. In all, the study concludes, the representative barge's costs would rise by approximately $19,000 per year, and its revenues would decline by $2,000 (not counting the revenue lost during installation). Table 5-9 compares the pro forma income statement of the representative barge before and after the imposition of vapor controls. Because of its limited scope, the Booz-Allen & Hamilton study does not elucidate factors influencing demand. To analyze completely the potential economic impacts of a regulation, the industry being regulated needs to be characterized with respect to its market structure. * The lost revenue is applicable only if the barge could have found work during this period of time. In addition, note that revenue lost to a particular barge would be obtained by another barge. Therefore, the entire industry would not lose any revenue.

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118 275 250 225 200 In he lo: In ~ 175 o I 150 125 100 75 - _ _ /~/t / / ~1 1 1 1 1 0 10 20 30 40 50 CAPACITY (barrels, thousands) Average Number of Tank Compartments Over 15 Years Old 3 6 10 Under 15 Years Old 3 8 13 *As described in the Marine Board's sample vapor control system Dirty Service ~ 15 Years Old Dirty Service > 15 Years Old Clean Service 15 Years Old Clean Service > 15 Years Old FIGURE 5-1 Installed capital costs for vapor control system on an inland barge. Source: Booz-Allen & Hamilton (1987~.

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123 TABLE 5-11 Small Terminal Physical Characteristics Item Total annual gasoline throughput (bbl) Maximum instantaneous loading rate (bbl/hour~ Number of docks Number of loading spots Distancea to incinerator Distance to fuel gas Distance to 220-volt AC All gasoline tanks have floating roofs Distance to loading pumps Manning, direct operations Tank farm Dock Tankermen Ship-loading capability UTD Case 5: Terminal Small Texas for Barges Terminal NA 16,000, gasoline 2 4 1/4 mile 1/2 mile 1/2 mile Yes 300 yd o None 24-hour operation NA 7-day operation NA 1, 373, 000 actual 5,000, gasoline 2,500, fuel oil 2 4 barges or 1 ship and 2 barges 1/2 mileb 6-in. main in immediate area Immediate area Yes 600 yd approx. 2 2 One dock takes 150,000 dwt shipsC and barges; second dock for barges only Yes Yes aDistance from dock. bIncludes minimum distance of 250 ft from other equipment (storage tanks) recommended by Industrial Risk Insurers. CShips are rarely loaded at this terminal. area, and the rest elsewhere on the Gulf Coast. Companies were surveyed to ascertain annual loading throughputs of crude oil and gasoline, maximum pumping rates, and other operational information. An important element in selecting specific sites to study involved the companies' willingness and availability to participate. The two sites selected should not be considered to represent the average small and large terminals in the industry. They represent specific small and large operations in Texas that provide a reasonable basis for this study. At their request, the operators of the sites selected are not identified.

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124 TABLE 5-12 Large Terminal Physical Characteristics UTD Case 7: Terminal for Large Texas Item Ships/Barges Terminal Annual gasoline throughput (bbl) NA 14,900,000 Maximum instantaneous loading 82,000 14,000 rate (bbl/hour) Number of docks 3 3 (2 barges, 1 ship) Number of loading spots Barges 8 6 or Ships 2 3 ships Dock to incinerator 1 mile 1 mile Dock to 220-volt AC 100 yd NA Dock to fuel gas main 100 yd NA All gasoline tanks have Yes Yes floating roofs Dock to loading pump ? NA Manning, direct operators Tank farm 2 9 Dock 3 1/dock Tankermen ? 1/dock Cost of Control at Terminals Fixed capital costs at terminals for the study were based entirely on the UTD study (United Technical Design, Inc., 1987) commissioned by the committee. Where loading volumes of the Texas terminals differ from the UTD cases, fixed capital was factored by methods traditionally used in preparing preliminary capital estimates (Peters and Timmerhaus, 1968).- Operating costs, except as noted, were also taken from the UTD study and adjusted to match the specifics of the Texas terminals. Time con- straints prevented the gathering of unit cost data (e.g., $/kwh), so that variable costs such as utilities and labor are not adjusted. This simplification should not significantly affect the results. It should be noted that most, if not all, terminals surveyed load products other than gasoline. Some of these products may also need vapor control systems. Also, the two terminals selected for this report are used by more than one operating company. These complications were not considered in this study, however, due to a lack of information. A thorough evaluation of these complicating factors could be conducted, but the impacts thus identified probably would not change the conclu- sions of the study. Gasoline loading by the terminal operators is important at both Texas terminals.

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128 A limit to the accuracy of this case study is in the siting of the incinerators. As shown by the UTD study, piping costs can be a major part of a control system. Thus, the distance from the incinerator to the vessel being loaded will materially influence the capital cost. Useful guidelines were obtained from terminal operators, but none could be considered as firm or final; since such siting decisions are made by different functional groups and management levels in the companies and could take several months to complete. A final site plan would not necessarily be the same as one proposed for a hypothetical study such as this one. Thus, it is not possible to represent the site selected at each terminal as anything but a fairly realistic assessment of what might be chosen if the facility were actually built. The site selec- tions do meet recommended incinerator and dock spacings guidelines (Industrial Risk Insurers, 1984~. The operator of the larger terminal stated that an existing flare would probably be used as the necessary control device instead of in- stalling a new flare or incinerator. However, in this report the cost of a new incinerator is included in the capital costs. Use of an existing flare would probably not be typical of the industry, and such an assumption is too optimistic for general conclusions (although in Texas 60 percent of marine terminals are at refineries, where existing systems might be used). The estimated operating costs here do not include indirect charges for corporate overhead, sales, and administrative costs, for example. These costs were not available, vary considerably from company to com- pany, and would add only 10-30 percent to the final annualized operating costs. Cost of Control on Vessels Existing vessels would be retrofitted to operate with a terminal vapor control system. Retrofitting costs were estimated by the UTD study (United Technical Design, Inc., 1987~. To estimate the vessel retrofit costs associated with vapor control at each terminal, it is necessary to determine a mix of vessels sufficient to serve the terminal, considered as a dedicated fleet. The committee developed "fleet factors" representing the number of barrels per day different vessels can load on a daily basis in normal operations, taking into account transit times. Appendix G explains the derivation of the following fleet factors. 70,000 dwt crude carrier (capacity 490,000 bbl): 25,000 bbl/day/vessel 35,000 dwt product carrier (capacity 262,500 bbl): 20,000 bbl/day/vessel 19,000 dwt ocean barge (capacity 142,500 bbl): 10,000 bbl/day/vessel River barge (capacity 25,000 bbl): 1,000 bbl/day/vessel

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129 Many of the inland river barges in Texas are only 10,000-20,000 bbl in capacity. Fleet factors for these smaller vessels were obtained by direct, linear ratio of capacity to fleet factor. Control Effectiveness The incinerator control device chosen by the committee for use in its analysis has a removal efficiency of 99.8 percent (U.S. Environmen- tal Protection Agency, 1985~. If it were used at the two Texas termi- - nals studied, 88.7 and 777.2 metric tons per year of VOC emissions would be prevented at the small and large terminal, respectively. VOC emis- sions factors were estimated using the EPA AP-42 method (U.S. Environmen- tal Protection Agency, 1985~. These factors of 3.4 pounds per 1,000 gal- lons loaded for barges, and 1.8 pounds per 1,000 gallons loaded for ocean barges and 35 kdwt product carriers were applied to the Texas ter- minals' throughputs to calculate VOC emission in metric tons per year. Cost-Effectiveness at Selected Texas Terminals Tables 5-11 through 5-14 give details of costs and physical charac- teristics of the Texas terminals. Fixed capital costs, including vessel retrofit costs, for the small terminal are predicted to be $1,417,000. Annual operating costs (not including supplemental fuel) of $461,800, including capital charges and direct operating costs, equate to $0.008 per gallon of annual throughput on gasoline. Cost of control is calculated to be $5,206 per metric ton of VOC emissions reduced at the small terminal. Fixed capital costs for the larger terminal are likewise predicted to be $8,086,000. Annual operating costs (not including supplemental fuel) of $2,288,600 at the larger terminal results in a throughput charge of $0.0036 per gallon. This equates to $2,944 per metric ton of VOC emissions reduced as the cost of control at the large terminal. Other Costs Not Accounted For Permits, insurance, liability questions, capital generation prob- lems, operating manpower, and other such areas were not addressed. COST-EFFECTIVENESS AS A FUNCTION OF TERMINAL THROUGHPUT The cost-effectiveness of an emission control system is measured by the dollars spent per metric ton of pollutant abated. Cost-effective- ness is generally a function of the capital and operating costs of the control system and the capacity utilization of the control unit. For a particular control unit the cost per ton will generally decrease as the

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130 TABLE 5-16 Fleet Assumptions for Cost-Effectiveness Analysis Vessel Capacity Fleet Factor (1,000 bbl) (bbl/day/vessel) Vessel Type 25 40-50 5,000 130-150 10,000 20,000 400-600 25,000 1,000 Inland river barge 19 kdwt ocean barge 35 kdwt product carrier 70 kdwt crude carrier control unit use increases. For marine terminals, control unit use is directly proportional to product throughput because displaced vapors are a function of product loaded. Capital and Operating Costs for Control System at Terminal Capital and operating costs of the incinerator system were obtained from the United Technical Design, Inc. (1987) study. The UTD costs are based on 2,000 hours of incineration operation for this cost-effective- ness analysis. Throughput was varied for this cost-effectiveness analy- sis, and operating costs were recalculated for various throughputs (see Appendix G). Vessel Retrofit Costs Vessel retrofit costs were obtained from the UTD study. The basis for determining the total amount of vessel retrofit costs attributed to the model facility was to assume a dedicated fleet. To enable this, assumptions were made about the number of barrels per day of terminal throughput that can be handled by vessels of different types (Table 5-16~. The number of vessels needed is determined by dividing annual throughput by 365 and dividing by the appropriate factories) in the table. For example, a terminal with an annual throughput of 356,000 bbl using inland river barges would have an average daily throughput of 1,000 bbl/day. The terminal's fleet would be calculated for inland barges as follows: (1,000 bbl/day)/~1,000 bbl/day/vessel) 2 1 vessel.

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131 The fleet factors in Table 5-16 include allowances for time it takes a vessel to make a voyage (of an assumed length), deliver product, and return to the loading terminal. Because fleet factors are rough estimates, an attempt was made to provide an upper-bound or worst-case cost-effectiveness number by arbi- trarily doubling the fleet size based on the fleet factors. It is possible that the fleet factors as provided already yield a worst-case cost-effectiveness estimate by assuming dedicated service. The retrofit cost in many cases will be shared by more than one facility. However, it is beyond the scope of the analysis to make those estimates. Emission Factors Because cost-effectiveness is a function of both the annualized cost and the emission reduction estimates, emission estimates for loading operation were based on factors obtained from EPA's AP-42 document (U.S. Environmental Protection Agency, 1985~. Emission factors are available by both vessel type and product carried. This analysis assumes that only crude oil and gasoline are being loaded. The emission factors used for the 70 kdwt oil carrier, 35 kdwt product carrier, 19 kdwt ocean barge, and inland river barge are 0.61, 1.8, 1.8, and 3.4 pounds per 1,000 gallons loaded, respectively. These factors are the same as those used to estimate nationwide marine vessel emissions in Chapter 1. These emission factors represent typical or average conditions on a vessel; actual emissions are a function of both vessel conditions and product carried. Cost-effectiveness would obviously increase or decrease if different assumptions affecting emissions are made with respect to vessel condi- tion. For example, the emission factors for a gas-freed tank barge in gasoline service and a dirty vessel in the same service would be 2.0 and 3.9 pounds per 1,000 gallons, respectively. The cost per ton of emis- sions abated would almost double for gas-freed vessels, because there are le s s emi s s ions . Cost - Effectiveness Curves Figures 5-4 through 5-6 are graphs of cost - effectiveness as a function of throughput for UTD cases 5, 6, and 7. The actual numbers plotted are presented in Appendix G. COST - EFFECTIVENES S COMPARED TO CONTROL OF OTHER VOC SOURCES The cost of controlling VOC emissions from tank vessels has been estimated by the committee as $2,944 per metric ton (of VOCs controlled) for large throughput terminals, and $5,206 per metric ton for small throughput terminals. Table 5-17 compares these costs with several other sources of VOCs, whose control is under consideration. The

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132 16 c O ~14 . _ a) .E O 12 o o - - 1n ~ I,LI cn O C] O LU C) ~ LL cn ~ Z J O Z Z 4 o Small Texas Terminal - Terminal Plus Vessel Retrofit Terminal Only 2 4 TERMINAL THROUGHPUT (millions bbl/yr) 8 FIGURE 5-4 Cost-effectiveness as a function of throughput--inland fermi nal serving barges. Source: United Technical Design, Inc. (19879. 18 16 - `> 14 ._ _# a) E o o o ~: ~10 LL ~ CL LL.I O llJ C] ~ ~n ~ Z 6 O Z ~) 4 Z ~ LLJ 2 o FIGURE 5-5 Cost-effectivene- United Technical Design, Inc. Terminal Only Terminal Plus Vessel Retrofit 20 40 TERMINAL THROUGHPUT (millions bbl/yr) 60 -crude oil terminal for ships. Source: (1987~.

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133 40 - o - to lo to ; cr: ~ C:) In O C) O ILI a: In Z O In Z Z IS FIGURE 5-6 Large Texas Terminal 0 4 8 12 16 TERMINAL THROUGHPUT (millions bbl/yr) Terminal Plus Vessel Retrofit Terminal Only 20 24 28 Cost-effectiveness--product terminal serving ships and barges. Source: United Technical Design, Inc. (1987~. TABLE 5-17 Comparison of Costs to Control Volatile Organic Compounds Cost ($/metric ton of Source Control Technique VOC controlled) . . . . . . Large marine terminal (See UTD case 7) $2~944 Small marine terminal (See UTD case 5) $5,206 Automobile gas tanks Stage II control at $850-$1,080a service stations Automobile gas tanks Onboard canisters $850a Gasoline Gasoline volatility $1,500-$2,500 control al984 dollars. Source: U.S. Environmental Protection Agency. examples in the table represent broad EPA strategies for reduction of VOC. A more interesting comparison would be with the highest cost of control being required at the state level in areas not attaining the national standards. These data were not available to the committee.