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Special Report Offshore production of green hydrogen ②

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작성자 최고관리자 댓글 0건 조회 59회 작성일 22-06-15 14:10

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Components of a hydrogen production facility

Although none of the proposed designs for offshore green hydrogen production have been built and operated at full scale, onshore hydrogen production facilities and other offshore industries can provide some insight into how such a facility might look and operate from a systems perspective. The following systems are all likely to be present in some capacity, regardless of the actual design of the facility.

Power delivery to the production facility

One issue common to many windfarm installations is supplying electricity to shore. High voltage alternating current transmission systems have losses between one and five percent for wind farms located 50 to 100 kilometers offshore with nominal power between 500 and 1,000 MW. High voltage direct current lines have losses between two and four percent under the same circumstances and require conversion at each end of the line. Hydrogen, on the other hand, exhibits a loss of under one-tenth of a percent over the same distances through pipelines. Hydrogen pipelines can be a cheaper option than underwater electrical cables, because of their lower manufacturing cost and simpler infrastructure. This can make producing hydrogen closer to a wind farm more efficient than producing hydrogen far away. For existing renewable energy farms, the hydrogen production facility could be connected anywhere along the power transmission system.
The connection between the hydrogen production facility and the renewable power source will depend upon their respective locations. In the case of both floating and bottom-founded offshore facilities, power would be delivered using techniques comparable to those used for exporting it from wind farms. Floating facilities may add some complexity to the design, as the power umbilical would need to be incorporated into the mooring and riser system.
In other cases, it may be possible to integrate the hydrogen generating facility into the wind turbine support structure or near the base of an offshore wind turbine installation. This could simplify the power delivery process, but could add significant challenges to the collection and export of produced hydrogen.

Water processing systems

For most electrolyzers, using unprocessed seawater is not advised. The presence of numerous other ions and particulates in seawater leads to the possibility of competing chemical reactions occurring with a wide range of products and unintended effects. The most problematic possible reaction is the chlorine electro-oxidation reaction, which occurs at the anode and is favored over the oxygen evolution reaction. This reaction produces a family of corrosive chlorine compounds such as chlorine gas and hypochlorite, all of which are environmental hazards and corrode the anode at a faster than normal rate.
Alkaline electrolyzers need an electrolyte solution to operate in, typically potassium hydroxide or sodium hydroxide, while PEM electrolyzers operate in pure deionized water. In the case of PEM electrolyzers, the water requires pre-treatment to remove any suspended particles before passing through reverse osmosis membranes which remove any dissolved salts or other impurities to deliver pure deionized water to the electrolyzer. Alkaline electrolyzers are generally more tolerant than PEM electrolyzers, and any particles involved in competing half-reactions can be managed with a water conditioning and treatment system. Because of the range of aqueous solutions suitable for use in alkaline electrolyzers, there is not a singular procedure for how water should be handled. For a higher level of control over quality of water being fed to an alkaline electrolyzer, the alkaline compound can be added to pure deionized water.

Hydrogen storage systems

Once produced, hydrogen may be compressed or refrigerated for storage or offloading. In the event that hydrogen can’t be received further downstream, having some capacity for storing hydrogen on-site is important to prevent a shutdown of the facility. Because hydrogen is a gas at ambient temperature and pressure, it can be volumetrically inefficient to store or transport at ambient conditions. In order to maximize the amount of hydrogen contained within a given volume, it can be compressed or (even liquefied below -234° C). High pressures between 350 and 700 bar, cryogenic environments below -234° C, or a combination of high pressure and low temperature may be required to reach higher hydrogen densities. It should be noted that hydrogen is typically handled as a gas when in a pipeline, at pressures between 30 and 150 bar. Solutions for hydrogen storage have been proposed at different temperatures and pressures, depending on the arrangement and design of the containment system.
Produced hydrogen can be stored using methods similar to natural gas, with some critical differences. Due to the small molecular size of hydrogen, equipment exposed to the gas is subject to a phenomenon known as hydrogen embrittlement whereby hydrogen can permeate into the walls of some metal alloy tanks over time. This can lead to general weakening of the structure along with crack formation and other forms of brittle failure in tank material.
Hydrogen’s small molecular size also makes it more prone to leakages, especially in links between pipeline sections and valves on pipes and tanks. Hydrogen oxidizing bacteria can also pose an issue for improperly stored hydrogen, as the bacteria naturally metabolize and reduce the purity of the stored hydrogen.
Hydrogen storage is currently done using either fabricated tanks or naturally occurring underground structures like salt domes. In geological storage methods, the hydrogen is pumped into an aquifer or salt cavern as a gas, similarly to natural gas industrial practices. However, underground hydrogen storage systems may be subject to leakage from aquifers at a higher rate than natural gas, therefore not all aquifers are suitable. Salt domes are preferred for geological storage, as they have low leakage rates, quick injection and recovery rates, and are easier to prepare than other geological formations.
In fabricated tanks, hydrogen is commonly stored as a liquid to increase stored density and reduce tank volume requirements. In a liquid state, hydrogen can be stored in metal tanks in a process similar to liquefied natural gas.
The liquefaction process for hydrogen requires more energy to achieve lower cryogenic temperatures compared to LNG, which liquefies around -161° C (-258° F). This process is relatively standardized, with the gaseous hydrogen undergoing compression before being cooled via heat exchangers and liquid nitrogen in a series of refrigeration cycles. Liquid storage of hydrogen requires a high initial investment in the construction of the liquefaction plant and has a high operating cost in terms of energy expenditure to total hydrogen stored. A large risk with storing hydrogen as a liquid is the potential to lose storage capabilities if cryogenic temperatures are not maintained.
To mitigate this risk, additional power reserves will need to be dedicated to the liquefaction system. Hydrogen stored under cryogenic conditions will require tanks designed with materials fitted for these extreme conditions, which also adds to the cost of storage and makes the system design more complex.
For additional reading on the storage of hydrogen, the ABS Sustainability Whitepaper Publication Hydrogen as Marine Fuel covers this topic in greater detail.

Hydrogen export systems

The manner in which hydrogen will be exported from the production facility is dependent upon the design of the facility. In all scenarios, industry experience with oil and gas export systems will heavily influence the design of hydrogen export systems. In the case of a bottom-founded or a floating hydrogen production facility, the hydrogen could be exported by ships in a platform-to-ship arrangement or via pipelines on the seabed leading back to shore.
For subsea hydrogen production, the export could be done to shore with subsea pipelines or to ships by means of a buoy with a riser connected to the subsea facility. In export systems that use a pipeline to deliver hydrogen to shore, there is potential for existing oil and gas infrastructure to be used. The commingling of hydrogen with natural gas has been proposed to take advantage of existing natural gas infrastructure, but is untested on large scales and there remain uncertainties regarding material requirements for such pipelines. If new pipelines are used, they would be constructed using materials compatible with hydrogen using existing industry practices for the pipelaying process.

Hydrogen safety systems

Hydrogen has several critical physical characteristics that must be considered when designing a safe production facility. The most important characteristic is its large flammability range compared with other commonly handled fuels. While hydrogen may dissipate quickly in open, well-ventilated areas, confined spaces with little or no ventilation represent a significant fire hazard. Depending on the flammable mixture, the gas pressure, and the location of the leak, combustion may also occur. When hydrogen burns, it’s invisible to the naked eye and burns quicker than most other compounds. To detect hydrogen leaks, hydrogen detectors and infrared cameras can be used. Leak detection strategies should also be implemented, along with proper ventilation. To extinguish a hydrogen fire, dry chemical extinguishers or carbon dioxide extinguishers are both effective. For additional information on fire safety practices for the handling of hydrogen, the ABS Sustainability Whitepaper Publication Hydrogen as Marine Fuel covers this topic in greater detail.
Because hydrogen is frequently held at extremely low temperatures, human contact with cryogenic materials and uninsulated pipes and tanks can lead to cold burns and skin damage. Hydrogen is non-toxic and lighter-than-air, but at high concentrations in confined spaces it acts as an asphyxiant. The flow of hydrogen through pipes can also cause a buildup of electrostatic charge, which can result in sparks when discharged and potentially cause ignition of hydrogen.
When hydrogen is being handled at cryogenic temperatures and high pressures, mechanisms for protecting systems from pressure buildup will also be necessary. This can be achieved through proper insulation of tanks and pipes and by installing pressure relief valves at appropriate areas in hydrogen-carrying systems. Additionally, a purging or inert gas system will be necessary to prevent the formation of flammable gas mixtures when tanks are being emptied. If the hydrogen is being handled at cryogenic temperatures, the gas selected for use in purging should not liquefy at temperatures below -234°C. The gas should also not contaminate or react with the hydrogen. Helium has traditionally been used for this purpose due to its suitable chemical properties, but sourcing enough helium may be difficult for long term use.

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Risk assessment

Many statutory regulations and certification schemes for hydrogen production facilities require risk assessments to verify that the system is appropriately safe and can exhibit at least an equivalent level of safety as conventional offshore oil & gas facilities. A risk-based approach justification of alternatives may be applicable either to the facility as a whole or to individual systems, subsystems, or components. As appropriate, attention should be given to remote hazards outside of the bounds of the system under consideration.
There are many tools that can be leveraged when performing a risk assessment. A risk assessment may include a Hazard Identification(HAZID) analysis to identify potential hazards that could negatively impact personnel, the environment, and property. A Hazard and Operability(HAZOP) study can also be conducted to evaluate hazards and identify root causes of hazards that may represent risks to personnel or equipment during the operation of a facility. A Failure Mode and Effects Analysis(FMEA) may also be used to identify and catalog potential failure modes of systems, and the causes and effects of those failures. The data collected from these studies plays a key role in determining whether current controls measures are adequate and if additional safeguards are necessary to mitigate risk.
See the ABS Guidance Notes on Risk Assessment Applications for the Marine and Offshore Industries for more information on risk assessment methods and standard recommended practice.

Financial drivers of green hydrogen

The price of green hydrogen in April 2021 ranged between $3.00 and $6.55 per kg. This price makes green hydrogen comparatively expensive in the current market relative to hydrogen produced via blue or brown/grey processes, which cost between $1.30 and $2.90 per kg and $0.70 and $2.20 per kg respectively. The variation in cost for blue, brown, and grey hydrogen depends on a combination of current coal or natural gas prices at the production facility, as well as the costs of building and operating the production facility. Similar to how the availability of natural gas
and coal impacts the price of blue, brown, and grey hydrogen, the availability of renewable energy sources has a large impact on the pricing of green hydrogen. As the technology and infrastructure develops, by 2030 green hydrogen is expected to drop in price to around $2.00 per kg in most regions with lows of $1.00 per kg in especially favorable regions. According to forecasts by the ETC, green hydrogen is expected to be cheaper than blue hydrogen in some areas by 2030 and most of the world in 2050.
One of the most expensive parts of green hydrogen production is the cost of the electrolyzer system. Reports from BloombergNEF(BNEF), the International Energy Agency(IEA), and International Renewable Energy Agency(IRENA) indicate that the average cost of alkaline electrolyzers in 2019 was $950 per kW, but predicted a drop to $625 per kW by 2030. For green hydrogen to be economically comparable to blue and brown/grey hydrogen, electrolyzer prices need to be reduced to closer to $125 per kW. This could be achieved through improvements in existing electrolyzer technologies, new electrolysis technologies being discovered, or an increase in the production rate of electrolyzer units to drop the unit price. Alkaline electrolyzers produced in China have already reached prices of $200 per kW, but both IRENA and BNEF have stated that the electrolyzers may not be able to compete with more expensive designs in terms of quality and reliability.
Another key factor in making green hydrogen economically viable is the introduction of financial incentives by governments. Governments can make green hydrogen cheaper by incentivizing production of green hydrogen, disincentivizing other methods of hydrogen production, or some combination of the two. One example of a financial incentive is a tax credit on new renewable energy developments. A tax credit for producing green hydrogen would decrease the net price to build and install the production facility. Many governments are also proposing low-carbon tax credits as a means of encouraging companies to reduce their GHG emissions below a certain threshold. This might drive traditionally high-carbon companies like those in the oil and gas industry to develop blue or green hydrogen divisions in their companies. As a complement to the incentives being offered by governments, carbon taxes encourage green hydrogen and other renewables by making hydrocarbons more expensive to use. A carbon tax is a tax levied on companies based on their total GHG emissions. As carbon taxes increase, businesses are starting to take greater steps to avoid operations that generate them. Companies can drive down their total GHG emissions by capturing their emissions, switching to renewable energy options, and by adopting cleaner technologies to power their operations.

Ongoing pilot projects and planned developments

Offshore wind and wind/solar hybrid projects are the only renewable energy sources yet identified for integration into offshore hydrogen production facilities. Offshore wind is currently both the cheapest and most readily available source of offshore renewable energy and will continue to be so for the immediate future. As a result, the large offshore green hydrogen production projects proposed so far all integrate wind farms into their designs. 2020 saw 50 GW of green hydrogen projects announced.
The NortH2 Project(Equinor, Gasunie, Groningen Seaports, RWE and Shell Nederland, with backing from the Groningen provincial authority) off the Dutch coast has set a goal of four GW of green hydrogen from offshore wind by 2030 and over 10 GW by 2040. The project is considering three options for the electrolysis facility: located on either an existing or newly constructed platform; on either an existing or purpose-constructed island; or integrated into the wind turbine superstructure.
In Germany, the AquaVentus project (RWE, Shell, Siemens Gamesa, Vestas, and 75 other companies and institutions) is aiming for 10 GW of offshore wind energy being used to generate green hydrogen by 2035. By 2028, the project aims to have an offshore platform with an installed production capacity of 290 MW that pipes produced hydrogen back to shore in Heligoland.
Deep Purple (a consortium led by TechnipFMC) aims to design, build, and construct a pilot for its combined surface electrolysis and subsea hydrogen storage system by 2023.
There are also many other smaller projects at and below one GW that have been announced throughout both Europe and in Australia, Saudi Arabia, and China.
ABS has been engaged in various offshore hydrogen projects, including one with the goal of designing and constructing an offshore platform for green hydrogen production by 2025.
It is important to note that all of the offshore green hydrogen production projects are either early in the pilot phase or still in the conceptual phase of design. Onshore hydrogen production has outpaced offshore so far and is likely to lead the industry in the near future. As these initial offshore projects develop and more experience is gained in adapting green hydrogen technology to offshore operations, the industry will be better able to expand and establish a larger role in the hydrogen market as a whole. Adjusting and expanding quickly will be important for green hydrogen securing a share of the ever-increasing demand for hydrogen around the globe. The lessons learned from these projects will pave the way for the future of offshore production of green hydrogen.

■Contact: ABS(American Bureau of Shipping)
www.eagle.org
 

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