Loading...
The URL can be used to link to this page
Your browser does not support the video tag.
Home
My WebLink
About
Hydrogen Use In Alaska 1981
LIZRARY COPY HYDROGEN USE IN ALASKA : : | HYDROGEN USE IN ALASKA by " Christopher Blazek Timothy Donakowski Presented at Pioneer School House, Anchorage, Alaska October 13, 1981 and Kodiak Borough Council Chambers, Kodiak, Alaska October 14, 1981 PROPERTY OF: Alaska Power Authority 334 W. 5th Ave. Anchorage, Alaska 99501 Slide No. wo Ont DN FWD FB NbN NY MN NHN PE RP BPP RP BP Dn UF WHR OHM DN DU FF WDYS FO IN S$ T TABLE OF CONTENTS Hydrogen Use in Alaska Production Technologies Trail Electrolyzer De Nora Electrolyzer Manufacturers Surveyed Storage Technology U.S. Steel Hydrogen Storage Vessels Transportation Technology Appliance Conversion Vehicle Conversion Fuel Cell Market Potential for Hydrogen Estimated 1980 Merchant Hydrogen Costs Summary of Renewable Resource Potential and Costs Renewable Energy Sites in Alaska Hydropower Projects Planned or Under Construction Community Selection Community Selection Matrix Old Harbor Aerial Picture of Old Harbor Energy Profile Milestones for Commnity Development Plan Transportation Sector Conversion Residential and Commercial Sectors Conversion Electrical System Conversion Demonstration Costs iii (TUTE Oo F GAS oan FF 10 11 13 14 16 18 19 20 22 23 25 27 29 31 33 35 37 38 40 41 42 43 TECHNOLO G Y co. 4 SLIDE 1 HYDROGEN USE IN ALASKA PRODUCTION STORAGE TRANSPORTATION UTILIZATION MARKETS. RENEWABLE ENERGY RESOURCES Community DEVELOPMENT PLAN SITE SELECTION DEMONSTRATION ProvecT DESIGN - DEMONSTRATION ProvecT Cost Good afternoon, ladies and gentlemen. Before I begin my presentation, I would like to thank the State of Alaska, Department of Commerce and’ Economic Development , Division of Energy and Power Development for supporting the Institute of Gas Technology in this study. I would also like to thank our subcontractor, Arctic Slope Technical Services, for its contributions to this effort. The object: of this study was to evaluate the potential of hydrogen, from renewable resources, as a fuel in rural Alaska and as a large-scale export energy commodity. “For those unfamiliar with hydrogen, it is the most abundant element in the universe. It is the fuel that powers the sun and propels the space shuttle into orbit. Unlike natural gas, oil, or coal, hydrogen is not found naturally in great abundance in its pure form. Because of its high reactivity, hydrogen: is "trapped" in. compounds: with other elements. The most abundant of these compounds’ is water. By applying energy to these compounds, INS TIT U Ti E O: F. GAS T.E-C H NOLOGY hydrogen can be liberated for use as a clean-burning fuel. The primary com- bustion product from hydrogen-fueled devices is water. To evaluate hydrogen's applicability in Alaska, this study was divided into a number of tasks. In the first task of this study, IGT examined four basic hydrogen production technologies: methane-steam reforming, partial oxidation of heavy oils, electrolysis of water, and thermochemical hydrogen production, This analysis was followed by an evaluat ion of gaseous hydrogen storage in pressurized gas cylinders, metal hydrides, glass microspheres, and underground formations as well as liquid hydrogen storage in insulated tanks. Next, the transportation and distribution of hydrogen and its coproduct oxygen by pipeline, truck, rail, and barge were investigated. The final aspect of Task 1 examined hydrogen for use as a general purpose fuel for appliances and transportation vehicles and for generating electricity via a fuel cell. Task 2 of this study dealt with the market potential of hydrogen in the lower 48 states, Canada, and Japan. Some of the largest U.S. markets for hydrogen include ammonia, methanol, oil-refining, and oxo-alcohol production. The hydrogen market study for Canada was confined to potential electrolytic hydrogen applications in the direct iron ore reduction industry. In addition to industrial uses for hydrogen, the market projections for hydrogen use in Japan include the transportation sector. Where possible, all market projec- tions for hydrogen utilization were made through the year 2000. The final phase of Task 2 estimates the potential energy available from Alaska's geo- thermal, wind, wave, tidal, and hydropower renewable energy resources. Recognizing the fact that hydropower offers the lowest electricity cost and is the most abundant Alaskan renewable energy resource, Task 3 focused on an evaluation of proposed and existing hydroelectric production facilities. As part of this survey, which was performed by Arctic Slope Technical Services, a projection was made of surplus electricity production that might be available for electrolytic hydrogen production. Local hydrogen and oxygen markets were surveyed in the final section of this task for their potential in utilizing hydrogen produced from this surplus power. The final two tasks of this report, which will be presented by my colleague, Mr. Tim Donakowski, review hydrogen's use in rural communities. In Task 4, a representative rural Alaskan community was selected, based in INSTITUTE OF GA-:S TECHNOLOGY a aad part on need and availability of local renewable energy resources, for conver- } sion to hydrogen fuel. After reviewing a number of commnities, the village | LJ of Old Harbor on Kodiak Island was selected. A community development plan-was oy then formulated for converting’ this’ village from.its current fossil fuel energy | Ll sources to renewable energy sources producing hydrogen. The final task of this report describes the community of Old Harbor and its current energy use ij patterns, Based on this information, estimations of the community demonstra- tion project design and cost were made. 3 I'NS TIT U TE OF - GAS. T.E-C HNOL OG Y SLIDE 2 PRODUCTION TECHNOLOGIES ’ METHANE STEAM REFORMING PaRTIAL OXIDATION OF HEAVY OILS ELECTROLYSIS OF WATER THERMOCHEMICAL HYDROGEN Cost, $/10° Bru - 6,00 11,15 11,75 32.05 The four basic methods of producing hydrogen reviewed in this study are methane-steam reforming, partial oxidation of heavy oils, the electro- lysis of water, and thermochemical hydrogen production, In the first tech- nique, catalytic steam reforming, a light hydrocarbon such as natural gas, methane, or naphtha is converted to a synthesis gas containing hydrogen and carbon monoxide. In this conmercially available process, part of the feed- stock is combusted to supply the heat necessary for reaction. The resulting synthesis gas is then further reacted to convert the carbon monoxide to hydro- gen via the water-gas shift reaction, This shifted gas is then scrubbed to remove the carbon dioxide produced in the shift reactor. At this point the gas is more than 98% hydrogen. With a feedstock cost of $2.50/10® Btu, the level- ized cost of hydrogen from this process is $6.00/10® Btu. If the feedstock costs were to double to $5.00/10® Btu, hydrogen would cost $9.90/10® Btu. The second technique involves the partial oxidation of heavy hydrocarbon feedstocks. This noncatalytic process is more suitable for heavier, dirtier feedstocks. Feedstocks for this commercially available process can include nearly any type of pumpable or compressible hydrocarbon from methane gas through crude and residual oils to asphalts, regardless of their sulfur con- tent. At a feedstock cost of $30.00/bb1, the levelized cost of hydrogen is $11.15/10® Btu. This escalates to $13.00/10® Btu hydrogen when the feedstock costs increase to $40.00/bbl. 'N S TIT U T°E oO F GA-S TECHNOLOGY Ls In the commercially available electrolytic process, hydrogen is genera- ted. from water.. The basic electrolysis cell consists of a pair of electrodes immersed in a conducting electrolyte dissolved in water.. -A direct electrical - current is passed through the cell from one electrode to the other. Hydrogen is evolved at one electrode, oxygen is evolved at the’ other, and water is thus removed from the solution. Based on an electricity cost of 30-mills/kWhr, the cost of generating hydrogen is $11.75/10® Btu. At 50 mills/kWhr the cost of hydrogen increasés to $17.95/10° Btu, and at 100 mills/kWhr hydrogen is produced at $34.05/10° Btu. These costs are based on advanced ‘technology electrolyzers that will be available in the near future. ‘In the last technique, hydrogen is generated by thermochemical means. At the present time, thermochemical hydrogen procedures are being researched in the laboratory in various programs principally in the U.S., Italy, Germany, and Japan, Thermochemical hydrogen production is a process involving several chemical reaction steps at relatively high temperatures, The reactions operate in a sequence or "cycle." If chemical feedstock in addition to water.must be supplied to the process, the cycle is called an open-loop cycle. If, on the other hand, all feedstocks except water are recycled, the process isa closed-loop cycle. Several dozen thermochemical hydrogen cycles have been identified; however, only about 10 have: been proven in the laboratory. The cost of hydrogen from this future process is projected to cost $32 to $40/10® Btu, with nuclear or solar energy supplying the required heat input. INS THTUTE OF GAS TECHNOLOGY SLIDE 3 This slide shows a picture of one of the largest electrolytic hydrogen plants in the world, located in Trail, British Columbia, Canada. Although this plant has been shut down for a number of years due to rising power costs, it represents the first North American attempt at large-scale hydrogen production, This plant contains 3,229 tank-type cells and consumes about 60,000 kWhr of electricity to produce a ton of hydrogen. This tank-type cell is the oldest form of industrial electrolyzer. It consists of a series of electrodes, anodes, and cathodes alternately, which are suspended vertically and parallel to one another in a tank partially filled with electrolyte. Alternate electrodes, usually cathodes, are surrounded by diaphragms that prevent the passage of gas from one electrode compartment to another. The diaphragm is impermeable to gas, but permeable to the cell's electrolyte. The whole assembly is hung from a series of gas collectors. A single tank-type cell usually contains a number of electrodes; all are connected electrically in parallel. These 1N STITUTE OF GAS TECHNOLOGY tank-type electrolyzers have two major advantages. The first advantage is that tank-type electrolyzers have few parts and are relatively inexpensive. The second advantage is that each cell may be isolated, which minimizes down- time-for the entire plant, Tank-type electrolyzer disadvantages include lower thermal efficiency and requirements for more floor space. They are also difficult to operate at elevated pressure. For these reasons tank-type electrolyzers may be more applicable for use with very low-cost electricity and when low pressures are acceptable. (NS TITUTE Oo F GAS TECHNOL OG Y SLIDE 4 HM i i | | This next slide shows a picture of a De Nora filter-press type electro- lyzer. This cell is sometimes called a bipolar cell because each electrode is used with one face as the positive electrode of one cell and the opposite face as the negative electrode of the next cell. In practice, filter-press type cells are usually constructed with separate electrodes in each cell that are electrically connected through a solid metal separator plate that serves to keep the hydrogen cavity of one cell separate from the oxygen cavity of the next. Because the cells of the filter-press type electrolyzer can be relatively thin, a large gas output can be achieved from a relatively small piece of equipment. It is usually necessary to cool the cells by circulating the electrolyte through them, and the electrolyte exiting from the cell carries with it the gas produced. electrolyte is accomplished in a separating drum mounted on top of the electro-— lyzer. The electrolyte, 1'NSTITUTE In many designs, separation of the gas from the free of gas, is recirculated through the cells. TECHNOLOG Y The i fy i major advantages of filter-press-type electrolyzers are that they take up less floor space than tank-type electrolyzers .and they can operate at higher temperatures and pressures. The major, disadvantages include much closer con- struction tolerances due to sealing problems and a greater potential of in- creased downtime. Production losses stem from the fact that the entire cell stack must be dismantled if one cell fails. Oo . Filter-press electrolyzers usually represent higher capital costs per unit area than tank-type cells but compensate for this by operating ‘at higher current densities, therefore producing more hydrogen per unit cell area. ‘In general, filter press-type electrolyzers are more efficient at producing hydrogen under pressure, INSTITUTE OF GAS TECHNOLOGY SLIDE 5 MANUFACTURERS SURVEYED Name Electrolyser Corp. Teledyne Isotopes, Inc. De Nora, S.p.A. Lurgi GmbH : Construction John Brown, Ltd. Brown-Boveri General Electric Co. Norsk-Hydro Cominco, Ltd. Life Systems, Inc. Location Canada U.S.A. Italy W. Germany U.K. Switzerland U.S.A. Norway Canada U.S.A. .Pressure,-. psig . 0.4 35-3000 > ol 440 440-3000 — 0.4 2-3000 1 0.1 600 This slide presents a list of the electrolyzer manufacturers surveyed in this study. All of these electrolyzers are commercially available and proven except for the Teledyne, General Electric, and Life Systems units. These three electrolyzers are presently emerging from the research phase and should be available in the near future, This new generation of electrolyzers can operate at higher current densities and improved efficiencies, thereby lowering the cost of hydrogen production. As seen in this slide the tank-type electrolyzers operate at low pressures in the range of 0.1 to 1 psi gauge. The filter-press or stack-type electrolyzers are capable of generating hydrogen at pressures of up to 3000 psi gauge. (NS TITUTE. OF. 10 TECHNOL OG Y poy ‘SLIDE 6 STORAGE TECHNOLOGY PRESSURIZED. Gas CYLINDERS METAL HYDRIDES Gass MICROSPHERES _ UNDERGROUND FORMATIONS INSULATED TANK LrqurD STORAGE After the hydrogen production step, a means of storing hydrogen is re- quired. Hydrogen can be stored as a gas in pressurized gas cylinders, metal hydrides, glass microspheres, and underground formations and as a liquid in cryogenic insulated tanks. _-Gas storage in tanks or tubes is applicable to small-scale users. Lar ge- scale users also use gas tank storage at pressures of up to 15,000 psi in specially designed, double-walled pressure vessels with an inner metal liner compatible with hydrogen at the high stress levels and the outer wall of high-strength welded steel designed to contain the pressure. Hydrogen can be stored by chemically combining it with various metals and alloys to form hydrides, Heat is released during the hydriding process. During the dehydriding process, the hydride 4s dissociated by heating, and hydrogen gas is released for use. Hydrogen storage densities equivalent to liquid-hydrogen densities can thus be obtained. At present the main tech- nical drawback of metal-hydride storage is the very high overall weight and volume involved. Other critical factors include cost, availability of metals, and tolerance to impurities. Advantages include hydrogen storage as a hydride at ambient pressures and temperatures and, when needed, release of hydrogen at moderately high pressures. Glass microsphere storage is another emerging technology in which hydrogen is stored in small glass spheres. The concept is based on the ability of hydrogen to diffuse into the small hollow glass beads under high pressure. ‘11 “tN S$ TITUTE OF - GAS TECHNOLOGY Bead breakage during recycling and bead costs are hindering the development of this concept. If developed to commercialization, microsphere storage could provide a low-pressure, potentially safe means of storage with less weight penalty than metal hydrides. Underground formations can also be used for large-scale hydrogen storage. Hydrogen gas has been successfully stored in solution-mined salt caverns in © England and in an aquifer in France. An important consideration in underground storage is the impermeability of the cap rock over the formation. Due to hydro- gen's high mobility, many formations will leak hydrogen if surrounding forma- tions are too porous. Liquid hydrogen storage in insulated tanks is another available hydrogen storage technology. Insulated. storage tanks as large as 500,000 gallons have been built. Liquid hydrogen is also available in tank cars and trucks. An insulation layer consists of a vacuum jacket, like a thermos bottle, with a multilayer radiation shield to keep evaporation losses to a minimum. Disad- vantages include high liquefaction costs and high technology requirements due to the extremely low -412°F liquid storage temperature. Advantages include small storage volume requirements and minimization of storage weight. 12 INSTITUTE Oo F GAS TECHNOL OG Y oo PRESSURE, 1 PSI SLIDE 7. U.S, STEEL HYDROGEN. STORAGE VESSELS STORAGE VESSELS REQUIRED TO Tora Cost __ SIZE; Store 10° SCF For 10° scr, $106 500 2U-IN, 0.D, 265 . 2,30 40-FT. LONG 1300 24-IN, OD: 116 1,06 40-FT. LONG 2450. 24-1N. O.D, 1.37 20,5-FT, LONG For small-scale hydrogen storage for use in rural communities, tube storage may be most appropriate. In the design pressure range of 500 to 2450 psi, vessels are available from U.S. Steel Corp. “The U.S. Steel seam- less. vessels could be manifolded together for larger volume storage of hydrogen with discharge at the desired rate. This slide provides some data on the features of each storage vessel size for storing 1 million SCF of hydrogen. Manifolding and mounting costs are included in the capital equipment cost along with those for the vessels. From this analysis, vessel pressures near 1300 psi appear to provide the lowest equipment costs of the three pressures considered. Annual operating and maintenance costs for cylinder storage could range from approximately 1% to 3% of the installed cost of the storage facility. 13 I1INSTITUTE O-F GAS. TECHNOLO G Y SLIDE 8 “TRANSPORTATION TECHNOLOGY . 7 ee precute teat co PIPELINE + 2000 psig «$9.1 ~ 1,00/10° Bru TRUCK 120,000 2400 PsiG $140,000 1,44 x 19° 10 + 100-psic $350,900 RAIL 5,646 x 10° 10 + 100 psic $440, 000 BARGE 69.75 x 10° - 10 + 100 psig” $18 x 10° Transportation technologies were investigated next in this study. The final cost of hydrogen delivery is dependent on a number of factors such as transportation distance, quantity, and equipment utilization. For this reason, this slide presents a range of delivery costs or actual equipment costs. For gaseous pipeline transmission of hydrogen, transmission costs range from 10¢/10® Btu per 100 miles for large quantity transport to $1.00/10® Btu for small-scale distribution service. Capital costs for these pipelines can range from thousands of dollars to hundreds of millions of dollars. Transmission pressures range from just over atmospheric pressure for distribution service to over 2000 psi for long distance, large-diameter gas pipeline transmission, Hydrogen can also be transported on a smaller scale by tractor trailer in gaseous or liquid forms. In the gaseous form a tube trailer carrying 120,000 SCF of hydrogen at 2400 psig would cost roughly $140,000. A cryogenic insula- ted tank trailer is also available for carrying liquid hydrogen. This truck would cost roughly $350,000 and would be capable of carrying 1.44 million SCF of hydrogen in liquid form. Transportation of liquid hydrogen by rail car can also be used. A liquid hydrogen tank car is capable of carrying 5.646 million SCF of hydrogen; this car would cost roughly $440,000. 14 INSTITUTE Oo F GAS T.E C HNOLOG Y If ocean or river transportation options exist, a liquid hydrogen barge can be utilized. This barge carrying. over 69.75 million SCF of hydrogen would cost nearly $18 million dollars. Larger ocean-going ship transport is also a future option. However, ocean-going ship transportation of cryogenic hydrogen has not been commercially proven. 15 a . INS THETUTE ‘O F° GAS TECHNOLOGY SLIDE 9 APPLIANCE CONVERSION ATMOSPHERIC BURNERS @ FueL FLow RATE @ Arr/FuEL RATIO o e@ Burner VELOCITY @ PrimaRY-AIR ENTRAINMENT CaTALyTIC BURNERS e@ Low-TEMPERATURE @ HIGH-TEMPERATURE an The next three slides cover the aspects of hydrogen utilization in appli- k ances, transportation vehicles, and fuel cells for generating electricity. In this slide, aspects of residential appliance conversion are reviewed. These appliances would include stoves, hot water heaters, and furnaces. Hydrogen cannot be directly substituted into ‘these appliances; burner modification or possibly replacement burners are necessary before hydrogen could be used as a fuel. Similar equipment modifications were necessary when natural gas was - mo introduced in the 1930's, 40's, and 50's to replace manufactured gas. Simi- larly, when appliances .are converted from oil to natural gas or propane, burner modification or replacement is necessary. Hydrogen has a number of combustion properties that can be beneficially exploited with burners that operate through the action of a catalyst. The burners built into domestic gas appliances are designed to burn fuel from a low-pressure gas source and are know as "atmospheric burners." These burners operate on the same principles as a Bunsen burner, which consists of a straight, smooth metal tube with a gas metering orifice at the lower end. 4 Ambient. air enters the tube through adjustable openings around the gas orifice and is transported by the high velocity jet stream. When hydrogen is substituted ™ 16 INSTITUTE OF GAS TECHNOL OG Y 1G for natural gas, for instance, four primary modifications must be considered. In the first area of concern, the fuel flow ratio must be adjusted to deliver “the same heat rating. Because of hydrogen's lower heating value per cubic foot and other unique properties, an unmodified flow rate for hydrogen would deliver 10% less energy as compared with natural gas. In the area of combustion air to fuel ratio, hydrogen requires less than one-third the air for complete com- bustion as natural gas. Therefore the adjustable air inlet opening around : the burner orifice must be closed somewhat. However, because the primary air is mixed in somewhat differently as it is entrained, the one-third ratio stated above is somewhat low. The final conversion aspect for atmospheric burners involves the burner velocity through the orifice ports. Because the hydrogen flame burns faster than natural gas, flashback or popping becomes a problem. This problem can be solved by increasing the ‘delivery pressure or decreasing the primary air. Instead of modifying existing burners, the possibility exists to replace these burners with catalytic burners. In a low-temperature catalytic burner, hydrogen combustion occurs at room temperature without the assistance of an open flame. Temperatures. reached at the face of a catalytic burner of this nature are somewhat lower than that of an open hydrogen flame. High-temperature catalytic burners can attain a higher combustion temperature but still require a pilot flame to initiate combustion. 17 (NS TITUTE Oo F GAS TECHNOLO G Y SLIDE 10 VEHICLE CONVERSION HYDROGEN STORAGE e@ HiGH-PREssurE GAs @ Metal HypRIDE e Cryocentc LiquipD @ CHEMICALLY BonDeD Motor CoNVERSION e@ INJECTION ‘Another aspect of hydrogen utilization involves vehicle conversions. The primary concerns in these conversions are the requirements to store hydrogen on-board. Storage can be accomplished in pressurized gas cylinders, in metal hydrides, as a cryogenic liquid, or chemically bonded. All these methods require more storage volume than gasoline or diesel fuel and in most cases are much heavier than the equivalent energy capacity of conventional techniques. The first three cases were discussed earlier in this presentation. The last category, chemically bonded, involves hydrogen storage in the form of a com pound such as ammonia, which is then reformed on-board the vehicle and converted to hydrogen. The extra complexity of this system is a drawback for its uti- lization. In all four cases the extra weight of the storage system and lower density of the fuel limit on-board storage space and also limit the transpor- tation range of the converted vehicle. In the area of engine conversion, hydrogen injection mst be performed. This is accomplished by installing a pressure regulator and a gas mixer valve. A solenoid.valve is used to control the hydrogen supply to the engine. Ignition system modifications may also require elimination of the centrifugal spark advance and a decrease in spark plug gap. An increase in engine compres- sion ratio may also be required to improve engine performance. 18 1'NS TIT UTE OF GAS TECHNOL OG Y — FUEL- HYDROGEN CONTAINING ANODE- OXIDATION REACTION CURRENT ELECTROLYTE -!ON CARRIER COLLECTOR OXIDANT 1N cmmmsemntie . OXIDANT OUT a CATHODE: REDUCTION REACTION COLLECTOR OX1DANT- OXYGEN CONTAINING A7906130! Fuel cells are electrochemical energy conversion devices, defined as electrochemical cells, that can continuously transform the chemical energy of a fuel to electricity by an isothermal process involving an essentially invariant electrode-electrode system. Unlike a battery, a fuel cell does not run down or require recharging. It will operate as long as both hydrogen fuel and oxidant air are supplied to the electrodes. The electrodes act as reaction sites or catalysts where the electrochemical transformation of the fuel and oxidant occurs, producing d~c power. This d-c power is then sent to a power conditioner or inverter transforming the d-c power to a power compatible with user requirements, Molten carbonate and acid-based. fuel cells with better than 50% overall efficiencies have been successfully operated in the laboratory. A phosphoric acid fuel cell with a generating capacity of 4.8 MW is undergoing preliminary check out in the heart of New York City and will begin testing in February-March 1982. 19 IN S THFT UTE OF . GAS TECHNOLO G Y SLIDE 12 MARKET POTENTIAL FOR HYDROGEN 1980 Demanp, USER 109 SCE ___ PRESENT SOURCE AMMONIA 1400. METHANE-STEAM REFORMING METHANOL . 210 METHANE-STEAM REFORMING OrL REFINING 780 NAPHTHA-STEAM REFORMING Iron ORE REDUCTION 34 METHANE-STEAM REFORMING Fats AND OILS 8,7 ELECTROLYSIS, MERCHANT CHEMICAL MANUFACTURING 58,6 METHANE-STEAM REFORMING, ELECTROLYSIS, MERCHANT METAL INDUSTRY 11.1 MERCHANT ELECTRONICS 3,1 MERCHANT FLOAT GLAss 1.0 MERCHANT MERCHANT HYDROGEN 105 METHANE-STEAM REFORMING Hydrogen is used extensively in the chemical and oil-refining industries and is important in several other industries. As such, hydrogen is used almost exclusively as an intermediate chemical rather than as a marketed com- modity. Valued conservatively, the hydrogen used each year by U.S. industry is worth more than $2 billion. This slide identifies the U.S. industries using hydrogen and judges their potential as customers of an electrolytic hydrogen production system in Alaska. The three largest consumers of hydrogen are ammonia synthesis, oil re- fining, and methanol synthesis, in that order. Together, they comprise more than 90% of the current 2495 billion SCF U.S. hydrogen demand. The hydrogen used in oil refineries is supplied mainly as a by-product of catalytic reform- ing, a process associated with the production of aromatics and the upgrading of gasoline stocks. Thus, the majority of refineries produce all the hydrogen they need from this captive source. 20 IN S$ TET UT E 0O.F GAS. TE.C HN OLOG Y Other important uses are direct reduction of iron and certain nonferrous ores, reducing.atmospheres for heat-treating metal parts, hydrogenation of , fats and oils, and various chemical processes. From the standpoint of ‘utilizing an outside hydrogen stream, we largely discounted petrochemical processes other than methanol because of their proxi- mity to internal by-product hydrogen and also because, like methanol, many processes require synthesis gas (hydrogen and carbon monoxide) rather than pure hydrogen. Similarly, chemical processes tied in with the chlor-alkali industry, such as the production of hydrogen chloride, will almost certainly use: by-product hydrogen from the chlorine cells. The most compatible markets today for merchant hydrogen are the hydrogena- tion of fats and oils, direct reduction of nonferrous metals, atmosphere uses in metal working, glass production, and semiconductor production in the elec- tronics industry. Also, the industrial gas companies that market hydrogen to smali-volume consumers might themselves be considered markets for hydrogen. These markets, because of their scale of hydrogen use, have much higher hydrogen costs than the major users, 21 INSTITUTE OF GAS TECHNOL.O-G Y SLIDE 13 ESTIMATED 1980 MERCHANT HYDROGEN costs First 20,000 SCF/MonTH $60,00/1000 SCF’ Next 80,000 SCF/MonTH $20,00/1000 SCF NEXT 200,000 SCF/MoNTH $14,00/1000 SCF Next 800,000 SCF/MontH = = $12,00/1000 SCF Next 1,100,000 SCF/MontH $11.00/1000 SCF MORE THAN 2.2 MILLION SCF/MoNTH $10,00/1000 SCF This slide summarizes the hydrogen costs for various scales of use. The monthly hydrogen volume varies over 7 orders of magnitude, whereas the hydrogen price varies by a factor of 6. A declining block rate structure is used, and there is usually an additional monthly charge for storage facilities. For small-scale users requiring less than 20,000 SCF/month of hydrogen, the cost of hydrogen is approximately $60/1000 SCF. For large-scale users of more than 2.2 million SCF of hydrogen per month, the cost drops significantly to $10.00/1000 scF. , There are three major merchant producers of liquid hydrogen in the U.S.: Union Carbide (Linde Division), Air Products, and Airco. Union Carbide and Air Products dominate the market. Merchant hydrogen production represents a small part of the total hydrogen production in the U.S. Current 1980 capacity is roughly 128 tons/day with an increase in capacity expected from the addition of two new plants at Sarnia, Ontaria, and Niagara Falls, New York, which are expected to come on stream soon. INSTITUTE “OF GA':S TECHNOLOG Y cy 7 —— Cs SLIDE 14 SUMMARY OF RENEWABLE RESOURCE POTENTIAL AND COSTS AwnuaL ELECTRICITY POTENTIAL, __ RESOURCE GWHR Cost, MILLS/KWHR GEOTHERMAL 2 100 WIND 250 + 60 WAVE 9,000 + 200-500 TIDE : 11,200 40 HYDROELECTRIC 175,700 20 The following renewable resources were considered for Alaska: geothermal, wind, wave, tidal, and hydroelectric. We estimated annual electricity poten- ’ tials (for electrolysis of water to hydrogen), favorable locations, and cost of electricity production. In the area of geothermal energy, we investigated hydrothermal convection systems with temperatures in excess of 150°C which are considered the most viable for electricity production. The total annual electricity potential in Alaska was conservatively estimated as 2 GWhr; this is based on continuous thermal equilibrium, The estimated average levelized cost of service for electricity production from geothermal energy was calculated to be roughly 100 mills per kWhr. However, costs can be significantly higher depending on well size and remoteness. For instance, geothermal wells being developed at Dutch Harbor have a projected levelized cost of service of 300 mills/kWhr. For the utilization of wind energy we assumed an average annual wind speed of 12 mph or greater was required for feasible electricity generation. At least 26 sites in Alaska meet this specification, and, undoubtedly, many more sites exist that have not been recorded. Assuming a single, 3-MW wind system at each site identified, an annual electricity potential of 250 GWhr exists. The reported cost of electricity from the 2.5 MW MOD-2 system being developed 23 INS THT UTE OF GAS TECHNOL OG Y by Boeing Engineering and Construction is roughly 60 mills/kWhr. For smaller systems, such as the three Jacobs machines at Unalakleet, the installed cost of electricity is ‘projected to be roughly 300 mills/kWhr. In the area of wave energy the Kodiak Island area seems especially prom- ising. The annual wave energy in this area is estimated as 17,300 kWhr per foot of coastline. If 100 miles were developed, we estimated the annual elec- tricity potential to be roughly 9000 GWhr. The greatest amount of energy is available from December to February and the least amount from June to August. Systems to generate electricity from waves have not been commercially demon- strated, Estimated costs per kWhr range from 200 to 500 mills as a function of system utilization factor (0.40 to 1.0). Only three sites in North America are judged suitable for recovering tidal energy: Passamaquoddy, Bay of Fundy, and Cook Inlet. Power potential at Cook Inlet is estimated to be 3500 MW. Based on designs for power systems in the Bay of Fundy, we estimate the annual electricity potential is about 11,200 GWhr. Generation of electricity is expected to be very capital intensive, requiring deep water dams designed for a high incidence of earthquakes in Cook Inlet. Based on cost estimates for the Bay of Fundy project and operating experience at Eklutna Dam (Anchorage), we estimate the cost of electricity as 40 to 80 mills/kWhr. The State of Alaska's hydropower potential at undeveloped sites was iden- tified by the Federal Power Commission (now FERC) in 1976. The total potential for sites with an installed capacity greater than 5 MW was 33,250 MW. The average annual energy from these sites is approximately 175,665 GWhr. The cost of electricity from Alaska's hydropower potential ranges from 20 to 700 mills/kWhr, depending on the location, water availability, and size. 24 INS T1I1TUTE OF GAS -T &ECHNOLOG Y 3LhLhnatttsuni 0 d v9 s AO9OT0NHOIDAL fo) be. oo te ee oe es Hs Ue = le is ie s DePOOOt+E i i Fe On exremt ARCHIPELAGO / aN \ Ss AUUTIAN Mu " s fy ay Ceurian 1S UAN 2 OMe ae } a evi ss) ts mf oe Oo SAO. J at mar ‘; tam anor oo UNALAGEA |. anct t . - ‘onmuse | v 2 7 7 . . 7 = . 0 " a " “« a 16 — _ 7 ” " ™ a a a ™ RENEWABLE ENERGY SITES IN ALASKA ST SaI1S This slide presents some of the renewable energy sites for wind, wave, tidal, geothermal, and hydropower energy. Wind power is prevalent. in the north- west, west, and southwestern coastal areas. Hydropower potential exists, in the south-central and southeastern regions of Alaska. Tidal power potential is confined to the.Cook Inlet region. Wave energy is available throughout coastal Alaska and in particular the area around Kodiak Island. Finally, geothermal sites exist in the northwest, southcentral, and Aleutian Island regions. 26 INSTITUTE OF GAS TECHNOLO G Y —_ U SLIDE. 16 HYDROPOWER PROJECTS PLANNED OR UNDER CONSTRUCTION ~ Capacity, Firm, AVERAGE, it MW _ Gir GWHR Le ProvecTs UNDER CONSTRUCTION , Lo SOUTHCENTRAL REGION SoLoMON GULCH, VALDEZ | SOUTHEAST REGION fy GREEN LAKE, SITKA ProvecTs PLANNED On LINE By 1990 uu SOUTHCENTRAL REGION BRADLEY LAKE, KENAI TERROR LAKE, KODIAK Power CREEK, CoRDOVA | La SouTHEAST REGION. SWAN LAKE, KETCHIKAN hy TyEE CREEK, PETERSBURG/ WRANGELL 7 BLack BEAR, CRAIG-KLAWOCK 7 SOUTHWEST REGION | Lake ELva, DILLINGHAM 27 INSTITUTE oO F. GAS TECHNOLOGY Throughout the State of Alaska there are more than 40 existing hydro- electric facilities. However, the vast majority of these facilities are very small and of local significance only. Of the remaining 14 plants, 2 are located in the south-central region, servicing the Anchorage-Cook Inlet area, and 12 are located in the southeast region, servicing the major towns and population centers. At present only one power plant is in the position of producing any surplus power — the Snettisham Hydroelectric Project, which services Juneau, the state capital. Also, the expansion potential of existing plants is small or nonexistent except for the Snettisham Dam through the Crater Lake Project planned to be on line by 1986 and through the Long Lake Dam Project to become effective by 1988. : Proposed new schemes either under construction or planned on line by 1990 will add power to various districts in the southwest region (1 new scheme), south-central region (4 new schemes), and southeast region (4 new schemés). However, the increasing demand of the various service areas is such that mst of the additional energy generated by those schemes will be used with little or no surplus. Exceptions to this may include those facilities with little or no firm generating capacity. These include the Solomon Gulch, Terror Lake, and Power Creek Projects. For these projects, hydrogen is well suited for utilizing peak.electricity production for hydrogen generation and storage with subsequent reconversion to electricity or directly as a fuel when little or no electricity is available from the hydroelectric dam. 28 1NS THETUTE OF GAS TECH NOL.OG Y fo = SLIDE 17 [| - | COMMUNITY SELECTION {| ANGOON - | CRAIG PL . HOONAH KLAWOC K ) { ad PELICAN F OLD HARBOR WRANGELL i The following communities were selected with the help of the Alaska is Division of Energy and Economic Development and were evaluated for their poten- tial as a demonstration site. However, considering the constraints on the {, scope of this study, they should not be considered as the only possible demon- stration sites. Additional site selection studies should be made to verify | the results of this study and to establish other sites that are also suitable for demonstration purposes. The communities selected are — e Angoon, (Population 465.) Located on the west coast of Admiralty Island, wv 41 miles northwest of Sitka. The Alaska Power Authority indicates no alternative to diesel generated power at this time (300-kW diesel capacity). Ly e Craig. (Population 527.) Located on the west coast of Prince of Wales Island, 5 miles south of Klawock., This village will be affected by the Black Bear Lake Hydropower Project, scheduled for completion in 1986. e Hoonah. (Population 680.) Located on the eastern shore of Port. Federick, 40 miles southwest of Juneau. Hoonah has a 1100-kW diesel capacity. e Klawock. (Population 318.) Located on the west coast of Prince of Wales Island, 5 miles north of Craig. Klawock is near the Black Bear Lake \ Hydropower Project, which is expected to begin operation in 1986. Until —) that time there is diesel power and waste-wood available for use. Elec- trical service is supplied by T-HREA (800-kW). e Pelican. (Population 180.) Located on Lisianski Inlet. Hydropower is in use, but is supplemented by diesel power in the winter. The existing hydropower plant was built in the early 1900's and is in poor condition (700-kW diesel). 29 INS T-I1TUTE OF GAS TECHNOL OG Y Old Harbor. . (Population 340.) Located on the east-central coast of _ Kodiak Island, in the proximity of an area having tidal power potential and near the planned Terror Lake Hydropower project which is expected to be on line by 1990. Electric power is generated by the Alaska Village Electric Cooperative (AVEC) by two 155-kW diesel-fueled generation units. Wrangell. (Population 2184.) Located on the north coast of Wrangell Island, 140 miles to Juneau, 90 miles to Ketchikan. Wrangell is 45 miles (by water) from Petersburg. This area was identified in Task 3 as having a possible surplus of hydropower and thus is an area to be considered for a potential site. However, it is not representative of a rural community. 30 N STITUTE Oo F GAS TECHNOLO G Y* 3LlaLiltswni AO9OTONHOAL TE TIME FRAME REPRESENTATIVE PROXIMITY ApEquaTe INFO NEED + oo + N/A + + + + N/A + oo + Ancoon CraiG HoonAH OLD HARBOR 1986 1991. + + + + COMMUNITY SELECTION MATRIX Kuawock PELICAN N/A — 1985 1986 + + + + 8T 4a11s + O00 + As the first step in the selection process, we collected data for selected towns and villages, and then chose a set of criteria to measure these alter- native communities. A matrix wads then developed that included the selected communities and components of our criteria. After examining the completed matrix we identified and recommended a rural community potentially suitable for a possible demonstration project. The criteria used for evaluating the rural communities include need, representativeness, time frame, proximity, and adequacy of information. Need is based on the cost of the electricity currently being supplied to the com- munity. A plus indicates electricity costs above $30/1000 kWhr; a zero is $10 to $30/1000 kWhr; and a minus indicates a cost of less than $10/1000 kWhr. Representative is defined in terms of population size, physical area, and social and cultural values. Communities which typify rural communities in Alaska are indicated with a plus for good, a zero for fair, and a minus for poor. Time frame is defined as the future availability of hydroelectric surplus power. A plus indicates that a hydroelectric facility exists or is under con- struction in the general area of the community, a zero indicates that one is planned by 1990, and N/A indicates that a hydroelectric facility is not fore- seen as becoming available. The term proximity is used to measure the nearness to the hydroelectric resource, A plus denotes within the area; a zero indi- cates that the community is within the region; and a minus indicates that the community is outside the region, The final criterion in the matrix involves the adequacy of information. If sufficient published information was avail- able to size and cost the hydrogen energy.system, a plus sign is used. A zero indicates that sufficient energy statistics were not available for project cost estimation. 32 (NS TITUTE OF GAS » TECHNOLOGY ( SLIDE 19 . - ‘OLD HARBOR NEED FOR MORE ECONOMICAL AND RELIABLE ENERGY SOURCE AVAILABILITY OF ABUNDANT RENEWABLE ENERGY SOURCES TYPICAL RURAL COASTAL VILLAGE DESIRE TO ATTRACT NEW INDUSTRY FAVORABLE COMMUNITY AND POLITICAL STRUCTURE From the community selection matrix it can be seen that certain communi- ties can be eliminated as possible demonstration sites. For instance, Wrangell, although having a need for a cheaper energy source, is not considered to be representative of a rural community in Alaska. In addition, Wrangell will have additional power following completion of the Tyee Lake Hydroelectric project. The communities of Craig and Klawock will have additional power following the completion of the Black Bear Lake project, which is due for completion by the mid 1980's. The commnities of Angoon, Hoonah, and Pelican appear to have no alternative to their existing systems for the foreseeable future and there-— fore could have a greater long-term need than some of the other comminities. The community of Old Harbor, although in the general area of the planned Terror Lake hydropower project, will still require energy much of the year due to the lack of storage at the Terror Lake site. In this area, hydrogen can be generated during peak season and stored for use when needed. In all cases, the smaller communities could be :considered representative of rural coastal comminities in southeastern Alaska and the Island of Kodiak. The communities of Angoon, Hoonah, and Pelican were eliminated from the hydrogen community evaluation because of inadequate information. Basic research is required to gather energy- and community-related information on these villages; this was deemed beyond the work scope of this project. The communi- ties of Craig and Klawock were also eliminated because of their potential 33 INS TIT UTE.’ OF - GAS TECHNOL OG Y tie-in with the Black Bear Lake project and possible community conflicts be- tween these two adjacent villages if only one community were selected. This elimination process leaves the community of Old Harbor, which is considered to be an appropriate community because of — 1. The need for an alternative energy fuel for both transportation and electrical generation, which will remain nearly constant in price in the near term 2. The need for an energy storage mechanism for storing energy from the seasonal peaks generated by the Terror Lake hydropower project 3. The availability of wind power to generate hydrogen 4. The potential availability of tidal power in the region to generate electricity for hydrogen production. 34 INSTITUTE Oo F GAS TECHNOLO G Y SLIDE 20 , USS. 4793 "We. Oy gi ee -, SSE ONLY 2? ¥ 30-79-0061 |. *50-78- 0060 RP SSE er ea USS 4793 Tr. F cn SSE at USS 4793 X : 4 Tre € ~ russ \a793 + : sg oe, Be: . : a N uss 47985 r. * ; » - - USS 474 Trek s - 7 - ahs TE — ~ — a a Se A . . Por A = ° 1400 Feet f NA Aptn ? ° 400 Meters ye ann / AERIAL PICTURE OF OLD HARBOR 35 I'N STITUTE Oo F GAS TECHNOLOG Y This is an aerial photograph taken from the of Old Harbor. Population in 1980 was 340; over the summer fishing months. About 100 households are old and new: sections in the village that are August 1981 Community Profile 400 people live. there during exist in the community. There connected by a natural land bridge. An underground utility corridor containing water and electric ‘power lines links the two sections. Old Harbor and Kodiak Island are near geologic faults and have experienced earthquake activity. No roads connect the village with the remainder of Kodiak Island. Phone service is available via satellite; a direct line connects the village with a medical center in Anchorage. At least 3 sideband radios exist for outside communications. Nearly all households have television sets. Drinking water is obtained from surface water sources, Sanitary wastes are treated in a septic tank and a sewage lagoon. Potential renewable resources include hydroelectricity, wind, waves, tides, and currents in the Sitkalidak Strait. 36 INSTITUTE -.0-F GAS TECHNOL OG Y SLIDE 21 ENERGY PROFILE . Fue. ‘1980 Consumption GASOLINE 17,000 GaL. DIESEL 45,000 Ga, HEATING OIL 105,000 GaL. DRIFTWOOD | Not AVAILABLE Peak ELectRIC PowER 105 KW Energy consumption for 1980 is summarized here. Gasoline storage capacity is 10,000 gallons, which represents about a 7-month supply. Diesel and home heating oil is stored in a 60,000-gallon tank, which is equivalent to roughly a 5-month supply. Fuel is brought in by oil company barges at various times. of the year. Driftwood is used for heating and cooking; estimates for amounts of wood consumed are not available. The electric power peak recorded for the village in 1980 was 105 kW. Diesel engines are used to generate electricity. Apparently, power outages are not uncommon. In 1980, about 270,000 kWhr were consumed. More electricity would be used if power was more reliable. 37 (NS TITUTE OF GAS TECHNOL OG Y 3aLlA LiL SS NI o v9 s AD O1T70NHOIDGAL se PRELIMINARY INVESTIGATIONS NON- SITE DEPENDENT SITE DEPENDENT FIELD STUDIES OFF-SITE R&D DEMONSTRATION PROJECT PHASE | PHASE 2* PHASE 3 PHASE 4* PHASE 5* PHASE 6 EVALUATION ¥ Optional . é@ SACS The milestones for the development plan we recommend for demonstrating a hydrogen community. are shown here chronologically. The major objectives are to demonstrate a: total:.all-hydrogen community, to risk the least amount of dollars throughout the demonstration, to disrupt the. community as little as possible, to efficiently utilize the developer's personnel, and to ensure high reliability of energy supply. Preliminary investigations are site independent and dependent. The first milestone is the formation of a special project team to oversee and carry out the demonstration. The first action is to establish goals and objectives for the demonstration project. The need for some sort of environmental impact state- ment must be determined. Discussions should then be initiated with appropriate agencies in regard to financing the project. The effects on homeowners’ and commercial insurance policies should also be investigated. Demonstration go- ahead should be obtained from the promoting agency, Manufacturers of gas uti- lization equipment can now be contacted for possible support. The site-dependent investigations begin with the development of a public relations program, Community acceptance of the demonstration is then solicited. The project team should then examine local fuel supply contracts to determine contractual commitments that may interfere with the. demonstration. Fire codes and zoning ordinances are also examined. Financing arrangements are finalized, 4 and the demonstration design and costs are refined. A training program for par- —~ ticipants in the demonstration is set up, and the EIS (if required) is performed. In the Field Study phase, baseline commnity energy data are gathered, and types of existing utilization equipment are surveyed. Additional off-site research and development is then performed to test modifications to the utilization equipment and to size storage, distribution, utilization, and production equipment. The actual demonstration phases are described in the following three slides. The first two phases convert the transportation sector, Phases III and IV con- vert the residential and commercial sectors, and Phase V converts the electri- city generation sector. The final milestone is the evaluation of the demonstration's success at meeting the objectives set out for it. The entire demonstration is expected to require 6 to 7 years to complete. 39 1N STITUTE OF GA-S TECHNOLOG Y SLIDE 23 TRANSPORTATION “SECTOR CONVERSION (PHASES I & IT) 600,000 SCF Ho STORAGE (1400 IGAL. GASOLINE EQUIVALENT) VEHICLE CONVERSIONS ~~ $ 2,000 per GASOLINE ENGINE — $20,000 per LarGe DIESEL ENGINE . RENEWABLE ResouRCE ELECTRICITY GENERATOR (220 KW) Lurer Type $556 ELECTROLYTOR We anticipate that conversion of the transportation sector will be most difficult for the community to accept. Because an all-hydrogen community is desired, we propose to convert this sector first. If the community does not accept hydrogen vehicles, there is no point in continuing the demonstration. The two major problems with hydrogen-fueled vehicles are their probable longer refueling times and reduced trunk volumes. In Phase I, pressurized storage vessels are brought into the community for storing 600,000 SCF of hydrogen. This is equivalent to 1400 gallons of gasoline and represents about 1 month's storage. Gasoline-engine vehicles (such as autos, three-wheelers, and boats) are converted at an estimated cost of $2000 per vehicle. Large diesel engines for boats are estimated to cost $20,000 to convert to hydrogen. Seventy gasoline engines and fifteen diesel engines would be converted in Old Harbor. In Phase II, 220 kW of renewable resource electricity generators are installed. Wind systems were presumed, although other resources could be used. Commercial electrolyzers (such as Lurgi-type electrolytors) produce hydrogen from water for the transportation sector. 40 'N S TIT U-TE OF GAS -T ECHNOLOG Y SLIDE 24 RESIDENTIAL & COMMERCIAL. SECTORS CONVERSION (PHASES III & IV) @ 7.5 MILLION SCF Hy StoraGe @ UNDERGROUND DISTRIBUTION SYSTEM e AppLiANce CONVERSIONS — $400 PER FURNACE «: — $150 per WaTeR Heater, RANGE AND OVEN e@ RENEWABLE REsouRCE ELECTRICITY GENERATOR (1900 KW) LurG1 ELECTROLYTOR A 1-month supply of fuel for these sectors requires 7.5 million SCF of hydrogen storage capacity. Pressure vessels are again specified. An under- ground pipeline distribution system is constructed to deliver gaseous hydrogen to each residence and commercial establishment. Furnace conversions are estimated to cost $400. Water heaters, ranges, and ovens are estimated to cost $150 each to convert to hydrogen. Phase IV calls for the installation of renewable resource electricity generators (at a capacity of 1900 kW) and the installation of commercial electrolyzers to produce hydrogen for the residential and commercial sectors. 41 INSTITUTE OF GAS TECHNOLO G Y —_—— SLIDE 25 ELECTRICAL SYSTEM CONVERSION (PHASE V) Peak ELEcTRICAL Capacity oF 150 KW RENEWABLE REsouRCE ELECTRICITY GENERATOR (500 KW) Lure1 ELEcTROLYTOR 280,000 SCF Ho SToRAGE Fue Cect (150 kW) The final phase of the demonstration converts the diesel-powered elec- trical system to a combined wind/hydrogen one. The peak electrical power capacity specified for the community is 150 kW. Additional wind capacity is required to produce hydrogen, which is used to generate electricity via a fuel cell during periods of calm wind. This additional capacity amounts to about 350 kW. “Total wind system capacity is 500 kW. One-week storage for hydrogen is provided (that is, 280,000 SCF). Additional storage may be avail- able in the transportation and residential sectors. Electrolyzers are sized to produce 1600 SCF of hydrogen per hour. The fuel cell system converts the stored hydrogen into electricity, and its capacity is 150 kW. 42 INSTITUTE OF GAS TECHNOLO G Y __) SLIDE 26 DEMONSTRATION COSTS (EQUIPMENT, SUBCONTRACTS, & SUPPORT) $ 1981 PRELIMINARY INVESTIGATIONS - 225,000 Fietp StupIEs 225,000 Orrsite ReD 175,000 Puases I & II 1,630,000 Puases III & IV 11,928,750 PHASE V 1,095,000 EVALUATION 75,000 FREIGHT & CONTINGENCY 4,300,000 19,653,750 Demonstration costs, which include equipment, subcontracts, and support staff, are shown here. Total costs are nearly $20 million, assuming 1-month storage capacity is sufficient. Storage equipment is the most significant contributor to the cost of the demonstration. We did not optimize the storage systems, so there may still be cost reductions there. Liquid hydrogen storage may reduce costs but would significantly complicate operations. State-of-the- art equipment was specified; future developments such as electrolyzer improve— ments may also reduce costs. With advanced equipment in place, Hz could be produced in Old Harbor for $10 to $15 Btu/million. This is equivalent to gasoline or diesel oil at $2.00 to $2.50 per gallon. The commmnity would also be nearly immmne to price raises in the cost of conventional fuels. 43 'NSTITUTE Oo F GAS TECHNOL OG Y