OCEES International, Inc. Hydrogen

The eventual fuel for human civilization will be hydrogen. In order for this to happen without major disruption, enough time must be allowed for the transition (about 50 years), and a large and reliable source of hydrogen must be selected. This means that the source material must be renewable and big enough to not be overtaxed by the growing demand of an immense world population with increased industrialization. A review of available alternatives shows that only offshore OTEC/hydrogen meets these criteria. This does not, of course, mean that smaller and/or intermittant renewable energy alternatives should not also be included where they are available.

The huge energy reservoir in the tropical ocean available via the OTEC process will require a transportable form of that energy to allow access by the demand centers in the Temperate Zone. The most attractive and versatile transportable energy form is hydrogen. There are several natural synergies between OTEC and hydrogen, especially liquid hydrogen (LH₂).

This scenario was recognized in the mid 1980's by Lockheed Corporation and led to a proposal to construct several 500 MW floating OTEC plants to be located in the tropical east Pacific, the Gulf of Mexico and the tropical west Atlantic. These plants would produce electricity using closed-cycle OTEC with ammonia as the working fluid. The electricity would be used to produce hydrogen by electrolysis and the hydrogen would be liquefied and transported cryogenically via LH₂ tankers (similar to LNG tankers) to Southern California to be used as transportation fuel. The demand for such zero emission fuel was anticipated because of regulations requiring a certain percentage of vehicles in Southern California to have zero emissions. Soon after this proposal was made, Lockheed made a corporate decision to restrict its business to Defense contracts only and to drop civil projects such as OTEC hydrogen.

The Lockheed proposal, however, proves several important concepts. First, it shows that OTEC hydrogen technology was advanced enough (even more than ten years ago) to support a design by a large and reputable engineering company. Second, it shows that the tropical ocean energy resource to be tapped by OTEC is large and accessible enough to the demand centers in the Temperate Zone to warrant such a study. Third, it shows that the economics of the OTEC hydrogen process were attractive even under the economic conditions at that time.

Fuel cells powered by pure hydrogen are simple and reliable in comparison to those fueled by hydrocarbons. The usually cited trouble area for pure hydrogen fuel, storage, has several alternative technical solutions. There are also several very promising research avenues for hydrogen-based fuel cell storage, such as carbon bucky tubes.

Concerns about the safety of hydrogen are sometimes brought up. An objective evaluation, however, shows that hydrogen is likely to be safer than gasoline or methane as a fuel.

Safety Ranking of Fuels

Characteristic	Fuel Ranking*
Characteristic	Gasoline	Methane	Hydrogen
Toxicity of Fuel	3	2	1
Toxicity of combustion	3	2	1
Density	3	2	1
Specific Heat	3	2	1
Ignition limit	1	2	3
Ignition energy	2	1	3
Ignition temperature	3	2	1
Flame temperature	3	1	2
Explosion energy	3	2	1
Flame Emissivity	3	2	1
Totals	30	20	16
Safety Factor øs	0.53	0.80	1.00
*1, safest; 2, less safe; 3, least safe

A comparison of various fuel properties

Properties		Hydrogen	Methane	Gasoline
Lower heating value	(kWs/g)	120	50	44.5
Self-ignition temperature	(Degrees C)	585	540	228-501
Flame temperature	(Degrees C)	2045	1875	2200
Ignition limits in air	(Vol. %)	4-75	5.3-15	1.0-7.6
Minimal ignition energy	(mWs)	0.02	0.29	0.24
Rate of flame propagation in air(Stoichiometric composition)	(cm/s)	265	40	40
Detonation limits	(Vol. %)	13-65	6.3-13.5	1.1-3.3
Detonation velocity	(km/s)	1.48-2.15	1.39-1.64	1.4-1.7
Theoretical explosion energy	(kg TNT/m^3 gas)	2.02	7.03	44.22
Diffusion coefficient in air	(cm^2/s)	0.61	0.16	0.05

A hydrogen economy will be environmentally benign, economically viable and steady, with a long-term future.

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TECHNICAL AND ECONOMIC DEVELOPMENTS

Since the time of the Lockheed proposal, in the early 1980's, there have been several technical improvements and economic developments that make an OTEC system that provides hydrogen even more attractive. These include:

The development and installation of several Kalina Cycle^® plants. The Kalina Cycle^® with its ammonia/water working fluid improves the efficiency of power production above that of the power cycle using pure ammonia as the working fluid. Kalina Cycle^® plants are now proven technology.

The development and installation of offshore oil production platforms in waters deeper than 3000 feet. In the tropical ocean these platforms could be used for OTEC hydrogen production. This technology, although developed for oil, is directly applicable to form the base of an OTEC hydrogen plant.

The optimization of the hydrogen production system by electrolysis of water with a high KOH concentration. This improved the efficiency of electrolysis from about 70% to about 85%, a significant improvement.

The optimization of the production of liquid hydrogen (LH₂) using several steps. The steps include compression and cooling followed by further cooling with liquid nitrogen; counter cooling heat exchange with very cold gaseous hydrogen followed by liquefaction through a Joule-Thompson valve. George Claude who also was the first to install an open-cycle OTEC plant (in Cuba) first developed an earlier version of this process.

The development of LH₂ transport and storage systems. Currently, LH₂ is transported via barge from Louisiana to Florida for use by the space shuttle. LH₂ is also regularly transported via tanker trucks on the Autobahn in Germany and used by experimental vehicle fleets which fill up at LH₂ stations.

The development of a full-scale system to use LH₂ for transportation in fuel cell powered vehicles in Iceland. In this case geothermal power plants produce the electricity (instead of OTEC plants). A car company (Daimler-Chrysler), an energy company (Dutch Shell), and a local Icelandic development company teamed up to put this system into place.

Considering this recent technological history it can be stated that the development of OTEC hydrogen requires no technological breakthrough. Working facilities have proved every aspect of a modern OTEC system.

Present economic conditions are also favorable for the development of OTEC hydrogen. Interest rates are at a 40 year low and competing oil prices are relatively high ($29 per barrel as of this writing, September 15, 2002).

OTEC HYDROGEN SYNERGIES

There are a number of advantages to combining an offshore OTEC platform with a hydrogen production and liquefying process. These include:

Full and efficient utilization can be made of the investment in production capacity because OTEC is available 24 hours per day, and 365 days per year. This is in contrast to most renewable energy systems such as wind, waves, tide, direct solar and photovoltaics. In addition, OTEC systems cannot exhaust the resource at the location where they are installed – in contrast with oil, natural gas, geothermal or even hydroelectric (the reservoir eventually silts up).

The efficient production of hydrogen by electrolysis requires very pure water for the KOH solution. A small part of the OTEC process can be used to produce this pure water from the surface seawater.

Liquefying hydrogen by the Claude process requires an efficient heat sink to minimize process energy. The cold seawater that is used in the OTEC process provides this efficient heat sink.

Ocean Tankers most efficiently transport liquid hydrogen. The offshore OTEC hydrogen plant is already located on the transport medium and therefore would result in the lowest cost for transport to market. From a global perspective, ocean transport distances of OTEC derived LH₂ are much shorter than our present system of oil transport from the Middle East around Africa to North America or Europe or from the Middle East around India and the Malay Peninsula to Japan.

All elements of the technology required to economically produce LH₂ using OTEC exist. No significant technical barriers remain. The successful development of a global hydrogen economy will undoubtedly have to involve the largest renewable energy resource in the world – the tropical ocean.

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OCEES International, Inc. intends to leverage its extensive experience into the development of floating OTEC platforms within the tropical region of the planet, utilizing existing oil platform technology, to support an operational OTEC system incorporating its natural synergies for providing energy to a hydrogen electrolysis and liquefaction plant. Liquefied hydrogen can then be shipped via existing technology to the industrial market centers of the world to supply a transportation fuel and fuel source to an impending hydrogen based economy. OTEC’s greatest potential is to supply a significant fraction of the fuel the world needs by implementing large, floating platofrms and or grazing plant ships to produce hydrogen or other suitable transportable energy carriers.

Proposed First Installation Locations

There are two possible reasonable candidates for commercial scale installations of OTEC hydrogen plants. One of these is on an offshore platform off the coast of a suitable tropical island installed in 3,000 feet of water. In an arrangement similar to that of the Iceland Hydrogen Project; a car company, an energy company, and OCEES International, Inc. with local government participation would form a consortium to build and operate a 100 MW OTEC hydrogen plant. The LH₂ produced would be used to power fuel cell equipped cars and buses in a demonstration of environmentally friendly technology.

Another immediately possible OTEC hydrogen project is to use one or more existing oil platforms in water depths greater than 3,000 feet in the Gulf of Mexico. As these newer generations of deep platforms exhaust the oil reservoir at their particular location they can be transformed into OTEC hydrogen production platforms. This would be a more economical approach than removing these platforms. The cost of an OTEC hydrogen system under these conditions would be approximately 25% less than one which requires the construction and deployment of a new platform.

It should also be noted that the design of these deep off-shore oil platforms could in the first instance incorporate a small (3 to 4 MW) OTEC plant to power the oil drilling and pumping functions as well as provide fresh water and air conditioning. Such a design would significantly reduce the present supply requirements from shore for these offshore installations.

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The vast majority of the hydrogen produced today is transported only a short distance before use. Short-distance distribution is by pipeline; similar to the method used for natural gas. At present, long-distance distribution is primarily in liquefied form in large tanks. Both options pose certain technical challenges. Techniques for central bulk storage are also important for the distribution infrastructure. (Small-scale storage techniques for the point of end use are discussed in the next section.) If fuel use of hydrogen is to be expanded significantly, a shift of emphasis seems likely, from tanker to pipeline.

Transport in Liquid Form

At atmospheric pressure, liquid hydrogen (known as LH₂) boils at 20°K (-423°F), making liquefaction, storage, and distribution challenging. Liquefaction is also very energy-intensive. Nevertheless, greatly reduced space requirements compared with gaseous hydrogen make the use of LH₂ an attractive option in some cases.

Hydrogen is usually liquefied in a complex, multi-stage process that includes the use of liquid nitrogen and a sequence of compressors. Detailed procedures are required throughout the process to control the proportions of the two types of hydrogen molecule, known as ortho and para. If this were not done, ortho hydrogen in the distribution and storage tanks would slowly but spontaneously convert to para hydrogen over a period of days or weeks, releasing enough heat to revaporize most of the liquid.

There are over 10,000 bulk shipments of LH₂ per year in the United States, to over 300 locations; NASA is by far the largest customer. Three main techniques are used for transportation: barges, truck trailers, and railcars. All these vehicles carry the hydrogen in pressurized, vacuum-insulated tanks, holding tens, or hundreds of thousands of gallons (3500-70,000 kg).

The cost of distribution in tanks is likely to remain higher for LH₂ than for other liquid fuels such as gasoline. This is because hydrogen takes up several times more space than an energy-equivalent amount of other fuels. It also requires special insulating equipment to keep it liquid.

Gaseous Distribution

Compared with the hundreds of thousands of miles of existing natural gas network, the hydrogen pipeline system is very small, totaling only about 460 miles. Air Products and Chemicals, Inc., has two gaseous hydrogen pipelines in the United States, one near Houston and one in Louisiana. Their total length is approximately 110 miles, and they carry an average of 190,000 kilograms of hydrogen per day to more than 20 customers at refineries and chemical plants. Air Products also operates a 30-mile, 50,000-kg/day pipeline in the Netherlands. Praxair, Inc. operates pipelines near Houston and in Indiana, totaling 160 miles and delivering about 200,000 kg/day to refineries, chemical plants, and steel manufacturers. Several other shorter lines deliver "over the fence" to individual industrial customers.

If the use of hydrogen pipelines were to be expanded, possible embrittlement problems would have to be considered. Pipes and fittings can become brittle and crack as hydrogen diffuses into the metal of which they are made. The severity of this problem depends on the type of steel and weld used and the pressure in the pipeline. The technology is available to prevent embrittlement, but depending on the configuration being considered, distribution costs may be affected.

The capacity of a given pipeline configuration to carry energy is somewhat lower when it carries hydrogen than when it carries natural gas. In a pipe of a given size and pressure, hydrogen flows about three times faster, but since it also contains about three times less energy per cubic foot, a comparable amount of energy gets through the pipe. Since compressors operate on the volume of a gas, however, not its energy content, the capacity of the compression stations (on an energy basis) is about one third less with hydrogen. In a pipeline system optimized to carry hydrogen, the pipe's dimensions and the size and spacing of the compressors would be changed to accommodate these factors. All told, transmission costs might be about 50 percent higher than for natural gas.

Some segments of the small hydrogen pipelines mentioned above were originally designed to carry natural gas. Could the existing natural gas networks be used to carry hydrogen on a larger scale, even though they are not optimized to do so? This question requires further study (see "Recent Legislation", below) but probably each pipeline segment would have to be considered on a case-by-case basis. Some steels and welds would be compatible, but others might be subject to embrittlement, particularly the welds in older segments. Compressors would generally have to be refitted with new seals and valves. Department of Transportation safety standards for hydrogen and natural gas pipelines are the same.

Mass Storage Systems

Any large-scale hydrogen distribution system must address the problem of bulk storage, to provide a buffer between production facilities and fluctuations in demand. Low-cost and efficient bulk storage techniques are a major research goal.

One can store hydrogen as either a gas or a liquid. The most widely studied options for storing gaseous hydrogen are underground caverns and depleted underground natural gas formations. Although hydrogen is more prone to leak than most other gases, leakage has been shown not to be a problem for these techniques. For example, town gas (a mixture containing hydrogen) has been stored successfully in a cavern in France, and helium, which is even more leak-prone than hydrogen, has been stored in a depleted natural gas field near Amarillo, Texas. The energy consumed in pumping gas in and out of such storage facilities may be significant, however. Aboveground storage tanks at high pressure are another option.

A certain amount of gaseous storage can be achieved by allowing modest pressure changes in the distribution pipeline system. In the case of natural gas, this technique is used to help manage transient demand fluctuations, such as the morning and evening peaks in residential demand in urban areas. Though the same technique might be useful for hydrogen, its potential is limited, particularly if the hydrogen is to be produced from intermittent sources such as solar or wind.

Storage in liquid form uses tanks similar to those used for liquid hydrogen distribution. Kennedy Space Center uses an 850,000-gallon sphere near the launch pad, and can transfer fuel from this tank to the space shuttle at up to 10,000 gallons per minute. Storage at liquefier plants is in vacuum-insulated spherical tanks that usually hold about 400,000 gallons. The energy required for liquefaction may not be a barrier if the hydrogen is to be transported as a liquid anyway, or if the end-use application requires its fuel to be in liquid form.

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ECONOMIC EVALUATION

With present technology we are now confident in proposing a 100 MW_net OTEC production system on an off-shore platform requiring only a vertical cold water supply line. The capital cost for such a system would be approximately $400 million. Using a 6% interest rate and a 20 year project period this works out to about $0.04/kW_hr. The OTEC electric power production O&M costs are very low since the Kalina cycle^® is low temperature and low pressure and the whole process is easy to automate.

Once the electricity is generated, hydrogen production by electrolysis and liquefaction by the updated Claude process would be the same as with other systems. Such systems, as the Iceland system or the Euro-Quebec project, have established this technology.

The capital expenditure for the hydrogen production and liquefying system is expected to be about $200 million. Using the same capital recovery factor as developed for the electricity production and considering the efficiencies of hydrogen production (85%) and liquefying (70%) this translates into another $0.033/equivalent kW_hr. Additionally, there are O&M costs associated with the hydrogen production, liquefying, and transport. These are estimated to be an additional $0.03/equivalent kW_hr. All this results in a total of about $0.103/equivalent kW_hr LH₂ FOB. This translates into $0.24/liter of LH₂ not counting any profits, insurance, taxes or other expenses.

The current price for LH₂ FOB Amsterdam (2002) is about $1.00/liter. This makes OTEC hydrogen roughly compatible and profitable within present market conditions.

Currently, several companies, including General Motors, Daimler-Chrysler, BMW, and Honda are all designing hydrogen powered vehicles. The only energy system with the base capacity to provide hydrogen to all of these vehicles and power plants is OTEC.

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