The answers are in context of PEM and alkaline electrolysis operating at or below 30 bar and below 85 deg C°. A general suggestion: Ask component suppliers about material compatibility, but do an independent investigation to confirm. As a general resource,  safety data sheets (SDSs) sometimes provide material compatibility information. Specific recommendations follow. 

• Hydrogen: Hydrogen material compatibility information can be found at Material Compatibility Hydrogen Tools (h2tools.org), including the very detailed technical reference developed by Sandia National Laboratories.
• Alkaline Water Electrolysis Systems: Cell stack electrolytes are typically potassium hydroxide, sodium hydroxide, or sodium chloride solutions. The pumps, piping, gas/liquid separators, and other components must be compatible. An example of an MSDS that provides information about material compatibility can be found at ERCO Worldwide: Potassium Hydroxide Solution.  Other resources include publications by the National Association of Corrosion Engineers and the Materials Technology Institute.
• Oxygen: Oxygen compatibility is a big concern, especially at pressure. ASTM subcommittee G04.02 affords no-cost access to apt standards and cleaning practices for oxygen. Start here: ASTM International Jurisdiction of G04.02. Other resources include CGA G-4.4, Oxygen Pipeline and Piping Systems. Only certain materials are rated for pressurized oxygen. Cleaning to remove particles and oils is very important to reduce fire hazards - remember, almost anything can be fuel in oxygen. 
• Water: Pure water feed to electrolyzers is important. A good approach is to consult with the water purification equipment supplier for recommended materials for the feed water supply components. High purity water corrosion products can contaminate PEM membranes and degrade electrolyte. 
• The use of plastic tubing in H2 and O2 pressure applications is usually precluded. See the AICHE CHS H2 Laboratory Safety course, which discusses a PNNL laboratory incident. Metal tubing is preferred. While plastic tubing may be desirable for non-conductivity and flexibility, one should only consider plastic tubing after a full hazard analysis to assure there are effective protective safeguards (e.g., ventilation, flow limits, protective enclosures, active leak detection, isolation/depressurization) in place. 
• H2 and O2 gases dissolve in significant quantities in liquids at 30 bar. Materials in these services will need to be compatible with the gas as well as the fluid. Note that these gases will readily come out of solution when pressure is reduced and directed to a drain. Open drains in well-ventilated areas are strongly recommended.

Pay particular attention to material compatibility of safety devices, such as pressure relief valves and pressure sensors. It is important to follow the guidance for proper design of vent systems given in CGA G 5.5 for H2 and EIGA Doc 154 for O2. These standards cover topics such as where back pressure is to be avoided and safe vent locations.
 

Typically, the inner vessel material used is 304 SS and the outer vessel is a combination of 304 SS and carbon steel depending on location. 316 SS or 316L material can be used, but due to higher cost and lower strength, are typically only used for higher purity systems. Nearly all tanks manufactured today use various forms of vacuum jacketed multilayer insulation for best performance. Older tanks frequently used vacuum jacketed perlite as an insulation method.

LNG storage, plumbing, and other systems can’t be directly retrofitted to handle hydrogen. The LNG components and systems will need to be removed and replaced with equipment specifically designed for hydrogen. If the concept is to convert existing equipment or an existing ship, then it’s probably impossible. If it’s to convert an existing LNG design on paper, then it’s probably impractical. Much better to start from the ground up with an H2 design.

From a materials perspective, there would be issues related to both the lower temperature of hydrogen and hydrogen embrittlement.   The temperature of LNG is 113 K, so many materials specified for this temperature will not be suitable for liquid hydrogen’s temperature of 20 K. In addition, liquid hydrogen’s lower temperature will condense air, so insulation systems will need to be significantly different for vessels and piping.

Another consideration is that electrical classification for LNG is different than H2, so would likely require substantial retrofit of instrumentation and controls. LNG equipment also frequently has non-captured vents, which would not be acceptable for hydrogen. Much of the LNG equipment might be located in enclosed areas, in which case the properties of H2 are going to drive design changes. Enclosed areas may also be a hazard for LH2 systems since air may condense on the piping and create a localized oxygen rich environment, especially if poorly ventilated.