RA 693JK322RA0001 Attachment 7 Research Topics.docx

U.S. Department of Transportation (USDOT) Pipeline and Hazardous Materials Safety Administration (PHMSA)

RA #693JK322RA0001

Attachment #7

Pipeline Safety Research and Development The Proposed Research Topics

Research Announcement # 693JK322RA0001

Technology Research Sought with Resource Sharing Rehabilitation of Aging Cast Iron Pipelines Technology Development – Rapid Cure Process for Cured-In-Place Liners The objective of this project is to develop a Cured-In-Place Liner (CIPL) with a rapid cure process that will reduce undesirable system downtime.

CIPLs are frequently utilized to rehabilitate aging cast iron and bare steel natural gas mains, which are primarily located in major U.S. cities. The current replacement process often results in excessive periods of loss of service due to system downtime. Liner technologies should allow successful service reinstatement to occur within 24 hours. A cost-effective technology is sought to target natural gas mains less than 16 inches in diameter.

The project scope should consider the following:

· Perform a literature review of relevant research from private or public research efforts (e.g., Advanced Research Projects Agency – Energy[footnoteRef:1] (ARPA-E)). [1: https://arpa-e.energy.gov/technologies/programs/repair]

· Develop a pipe lining for natural gas cast iron and bare steel distribution service.

· Demonstrate that the rapid cure process results in time savings over the current state of the practice.

· Include a demonstration with performance measures that successfully rehabilitates the full length of a pipe segment, as determined by the researcher.

· Illustrate how the proposed research could conform to and advance beyond the current state of practice within the American Society of Testing and Materials (ASTM) F2207-06 (2019), Standard Specification for Cured-in-Place Pipe Lining System for Rehabilitation of Metallic Gas Pipes.

· Deliver reported results in 36 months, with a project cost of approximately $1.5 million.

Underground Natural Gas/Hydrogen Storage Technology Development – Solutions for Predicting/Monitoring Hydrogen Gas Loss The objective of this project is to develop an estimate of hydrogen gas loss in a representative underground gas storage (UGS) facility.

Hydrogen gas loss has been observed in underground geologic gas storage operations that could prohibit utilizing UGS facilities for hydrogen containment. The gas loss could be the result of stratification, segmentation (mixing with storage fluids), or mixing (mixing with the existing natural gas in situ). A representative facility must be identified for characterization in the research proposal.

The project scope should consider the following:

· Review literature or research results from other private or public research efforts to assist in achieving the project goals.

· Measure the difference between injected hydrogen and produced hydrogen in the facility by using chromatograph and other appropriate measurement tools.

· Propose variables that can be collected to describe where the hydrogen gas is residing.

· Develop a model, if necessary, that calculates hydrogen consumption from microbial populations in underground storage facilities.

· Involve participation with standards organizations, such as the American Petroleum Institute (API).

· Evaluate whether a new standard practice could be developed using the project results.

· Establish various recommendations on how to implement preventative or mitigative measures to reduce hydrogen gas loss.

· Establish recommendations on best practices or measures to monitor hydrogen gas loss within geologic gas storage.

· Deliver reported results in 36 months, with a project cost of approximately $600 thousand.

Hydrogen Pipeline Network Components Technology Development – Validate Existing or Develop New Hydrogen Leak Detection and Quantification Technologies Compatible with Hydrogen-Blends The objective of this project is to validate existing leak detection and quantification technologies and/or develop new technologies compatible with pure hydrogen and hydrogen-blends based on flammability limits and relevant industry codes and standards.

Many technologies can detect natural gas leaks at lower concentrations and better pinpoint the leak location. However, as more hydrogen pipelines are placed into service, there is a need to ensure leak detection sensors and technologies can remain effective to safely transport pure hydrogen and hydrogen-blends. In addition, leak detection sensors and technologies used for hydrogen pipelines should be able to quantify, detect, and warn for the presence of dangerous levels of each blend of gas.

PHMSA may fund multiple proposals addressing either advancements/validations to existing technologies or new technology development.

The project scope should consider the following:

0. Perform a literature review of relevant research from private or public research efforts, along with performing industry outreach to aid in the research, to avoid duplication, and to potentially complement what already exists.

0. Ensure technologies can be used in various operating environments. These environments should include within structures (residential/commercial), along other parts of pipelines and pipeline facilities, in confined spaces, and as deployed in an underground, ground level, or airborne environment. Limitations of each tested technology should be well documented, so that participating service providers can adjust sensors based on limitations.

0. Consult with pipeline operators and technology service providers to establish three or more hydrogen-natural gas blend levels for testing, in addition to baseline levels using 100% hydrogen and 100% natural gas.

0. Partner with a technology provider. Partnerships may be appropriate for projects involving existing technologies and/or to develop sensors to detect hydrogen-natural gas blended leaks, quantify the amount of gas species, warn of unsafe gas levels, or further the development of existing technologies.

0. Describe the planned testing scheme for the various hydrogen-natural gas blend levels and baselines, including adequate sampling to achieve validation and statistically meaningful results.

0. Conduct validation testing as described in the main project objective to further a new or existing tool to the market, including under real and varying field conditions, as appropriate.

0. Deliver reported results in 36 months, with a project cost of approximately $1.5 million.

For proposals addressing advancements/validations to existing technologies, proposals should also consider the following:

0. Focus on the tools and technologies that have the best potential for being used ‘as is,’ modified, enhanced, or added onto, to perform reliably for all critical gas constituents (methane, hydrogen, etc.).

0. Describe the operational tasks that an operator would use this technology for, and in what typical environments (i.e., in-situ or external to buried pipe; confined spaces; residential/commercial handheld; right-of-way patrol; land or airborne vehicle; facilities piping; metering or measurement equipment; etc.).

0. Test for application on pipelines or pipeline facilities as appropriate.

Methane/CO2 Mitigation – Construction through Operations Technology Development – Field Validation Demonstrations to Advance Pipeline Leak Detection Beyond Current Capabilities The objective of this project is to validate innovative leak detection technologies (LDT) installed directly on Hazard Liquid (HL) or Natural Gas (NG) pipelines that would detect and locate a leak more accurately and quickly.

Current technologies utilize computational pipeline monitoring (CPM) and supervisory control and data acquisition (SCADA) systems[footnoteRef:2]. Inaccuracies or changes in volumes or pressures in the pipeline system are detected, and notifications (alarms, etc.) are sent to the dispatchers. However, these notifications can be delayed and inaccurate due to limitations with the instrument locating the leak and time differences in detecting the leak. Inaccurate measurements also occur due to time differences in detecting the leak. [2: CPM is a key tool used to measure pipeline data, such as measuring flow delivery volume changes and pressure drop in the pipeline system. SCADA systems are a key tool that measure the pipeline system pressure and delivery volumes to customers. The SCADA system is limited to measuring the pressure drop along the pipeline and does not measure gas volumes or leak locations.]

The innovative LDT will utilize CPM, SCADA, or other third-party systems to detect a pressure drop or flow variation, and specifically pinpoint where the leak is occurring along the system.

The pipeline operator will receive more accurate timing data that a leak is occurring, as well as the location of the leak along the system.

The project scope should consider the following:

0. Perform a literature review of relevant research from private or public research efforts, including service providers and operators.

0. Include a series of field validation demonstrations that prove enhancements advance the technology beyond those currently available, differentiate between a leak/rupture or operational signal (i.e., source input from equipment, valve, flow sensor, maintenance, etc.), and address any limitations.

0. Involve a pipeline operator, service provider, and a state regulatory partner that, along with PHMSA, could pilot a leak detection technology on a HL or NG pipeline system. (This will enable a design of demonstration that quickly identifies leak locations, which would support the Department of Transportation’s (DOT’s) strategic goals of Safety and Climate and Sustainability.)[footnoteRef:3] [3: https://www.transportation.gov/dot-strategic-plan]

0. Document the results of the validation testing, so that a determination can be made of the LDT’s effectiveness.

0. Deliver reported results in 36 months, with a project cost of approximately $1 million.

Breakout Tanks – Preventing Corrosion of Tank Bottoms Technology Development – Developing Corrosion Control Monitoring Technology for Hazardous Liquid Breakout Tanks The objective of this project is to develop validated technologies to monitor the corrosion conditions under the tank bottom.

A breakout tank is a tank used to relieve surges in a HL pipeline system or to receive and store hazardous liquids transported by the pipeline for later re-injection and continued transportation by the pipeline. Corrosion is one threat to the integrity of these tanks and is the emphasis of this research.

The selected researcher may be required to coordinate and share information with other related research efforts. The technology will be applied under the primary tank bottom, including double steel tank bottoms and tank bottoms with a liner/membrane under the steel tank.

The project scope should consider the following:

· Perform a literature review of relevant research from private or public research efforts.

· Develop and field test the technology to monitor corrosion under the primary tank bottom, between the bottoms, with a liner/membrane, or within the electrolyte (sand, concrete, etc.), and under the original floor.

· Determine whether a tank isolated from soil on a liner/membrane or on a concrete pad could be isolated and sealed to keep air and moisture from the tank bottom to prevent underside corrosion. Indicate whether the tank could be mitigated. If so, provide the most effective method.

· Collect performance data on the corrosion monitoring technologies to show whether current regulatory requirements are satisfied.

· Collect data on direct corrosion growth rate in mils per year (MPY) obtained from monitoring.

· Collect data on indirect corrosion growth rate (e.g., through cathodic protection (CP), or other alternative or supplemental processes) in MPY.

· From the collected data, determine if the corrosion growth rate and maximum inspection intervals can be used as a standalone method for determining tank inspection intervals.

Identify if CP is critical for determining inspection intervals. Evaluate other leakage monitoring techniques that could be used. If so, identify what are these techniques.

· From the collected data, determine new design concepts that could be used to better protect breakout tanks from corrosion. Identify these new concepts and what monitoring techniques should be implemented.

· Incorporate how CP influences the corrosion rate.

· Describe the characteristics of alternative or supplemental processes, such as vapor corrosion inhibitor (VCI) application including how long it takes to disperse through the sand pad, and whether it is dispersed effectively. The time required for the reapplication of the VCI should be determined.

· Deliver reported results in 24 months, with a project cost of approximately $500 thousand.

There are relevant standards that should be reviewed and considered during the design and execution of this project, including:

· API Technical Report (TR) 655 on Vapor Corrosion Inhibitors for Storage Tanks.

· API Recommended Practice (RP) 2610 on Design, Construction, Operation, Maintenance, and Inspection of Terminal and Tank Facilities.

· API RP 651 on Cathodic Protection of Aboveground Petroleum Storage Tanks.

· NACE Standard Practice (SP) 0193 on External Cathodic Protection of On-Grade Carbon Steel Storage Tank Bottoms.

Technology Development – Monitoring the Long-Term Compatibility of Vapor Corrosion Inhibitor (VCI) and Cathodic Protection (CP) Associated Components The objective of this project is to develop technologies that can detect and quantify the interactions between VCI and CP and associated components[footnoteRef:4]. [4: VCIs are a class of chemicals that form a protective barrier on a surface to help reduce the corrosion rate of the protected metal.]

A breakout tank is a tank used to relieve surges in a HL pipeline system or to receive and store hazardous liquids transported by the pipeline for later re-injection and continued transportation by the pipeline. Corrosion is one threat to the integrity of such tanks and is the focus of this research. As described in PHMSA’s Report to Congress titled “Aboveground Storage Tanks: Review of Current and New Corrosion Control Techniques,” research on VCIs has shown that their use may improve bottom plate corrosion control but may not have the level of corrosion control for adequate CP to meet federal pipeline safety regulations as a standalone method[footnoteRef:5]. The compatibility of VCI with CP is also not fully vetted. This project is focused on the long-term implications of applying VCI when CP protection is in use and applying VCI without CP protection. The technology will be applied under the primary tank bottom, between the bottoms or within the electrolyte, and under the original floor. [5: https://www.phmsa.dot.gov/news/report-congress-aboveground-storage-tanks-review-current-and-new-corrosion-control-techniques.

The project scope should consider the following:

0. Perform a literature review of relevant research from private or public research efforts.

0. Evaluate VCI for any environmental effects such as coming into contact with surface and subsurface water sources.

0. Evaluate optimal placement/installation for VCI injection points and VCI coverage of the tank area, identifying any gap areas.

0. Define the VCI dosage and how long it should last before needing replacement.

0. Determine whether VCI has a maximum usage life or if electrical resistance (ER) probes can determine its useful life.

0. Evaluate the locations for installing a monitoring system to measure the effectiveness of the VCIs for each tank. Show the optimum location of injection points and ER probes and any other monitoring devices on a tank diagram. Show area of VCI effectiveness and how it should be determined.

0. Develop VCI dosage requirements from the manufacturer’s recommended dosage and methods of applications from the tank manufacturer. Define the dosage and how long it should last before needing replacement.

0. Determine how long it takes for VCI to disperse through the sand pad, and whether it is dispersed effectively.

0. Determine if the type of soil pad construction has an effect on VCI dispersion and effectiveness.

0. Determine the time required for the reapplication of the VCI.

0. Collect data on direct corrosion growth rate MPY as per API 653 obtained from monitoring.

0. Collect data on indirect (e.g., CP, VCI concentration levels) corrosion growth rate MPY.

0. Collect polarization criteria.

0. Collect anode performance data.

0. Collect data on electrolyte compatibility with VCI.

0. Collect performance data on the corrosion monitoring technologies to show whether current regulatory requirements are satisfied.

0. Deliver reported results in 36 months, with a project cost of approximately $800 thousand.

There are relevant standards that should be reviewed and considered during the design and execution of this project, including:

0. API 653 as mentioned above.

0. API TR 655 on Vapor Corrosion Inhibitors for Storage Tanks.

0. API Recommended Practice (RP) 2610 on Design, Construction, Operation, Maintenance, and Inspection of Terminal and Tank Facilities.

0. API RP 651 on Cathodic Protection of Aboveground Petroleum Storage Tanks.

0. NACE Standard Practice (SP) 0193 on External Cathodic Protection of On-Grade Carbon Steel Storage Tank Bottoms.

Non-Technology Research Sought with Resource Sharing Rehabilitation of Aging Cast Iron Pipelines General Knowledge – Decision Support Tool for Replacement/Rehabilitation of Natural Gas Distribution Pipelines The objective of this project is to develop a risk-informed decision support tool (Tool) that can support decisions for replacement/rehabilitation considerations.

The Tool should have the following minimum operational requirements:

1. Inform the operator that risks may have exceeded acceptable limits and propose recommended actions;

1. Assess the suitability of pipe for rehabilitation in a risk assessment format;

1. Provide GIS-based, web-based capabilities;

1. Incorporate cost analysis and pipe-specific risk attributes, such as age and potential failure consequences; and

1. Account for breakage failures due to ground movement threats and seismic settlements or faulting hazards.

The project scope should consider the following:

· Perform a literature review of relevant research from private or public research efforts, such as from PHMSA or the ARPA-E[footnoteRef:6]. [6: https://arpa-e.energy.gov/technologies/programs/repair]

· Refer to ASTM F2207-06 (2019) Standard Specification for Cured-in-Place Pipe Lining System for Rehabilitation of Metallic Gas Pipe, where possible, as a guide to generate criteria for pipe rehabilitation or replacement decisions.

· Demonstrate the reliability of the Tool by comparing the Tool’s rehabilitation/replacement recommendations to actual operational data in replaced/rehabilitated pipe systems.

· Deliver reported results in 36 months, with a project cost of approximately $500 thousand.

Utilization of Inspection Tools on Hydrogen Pipelines General Knowledge – Review of Integrity Threat Characterization Resulting from Hydrogen Gas Pipeline Service The objective of this project is to identify differences between existing integrity threats and possible new threats resulting from the presence of hydrogen.

The safety of hydrogen pipelines depends on proven methodologies to collect integrity information about the systems. Each pipeline operator’s integrity management program (IMP) is designed to prevent and mitigate integrity threats identified and characterized within their system. This is necessary to develop and implement a comprehensive IMP as required by the Code of Federal Regulations (CFR) Part 192 for pipeline systems. PHMSA incorporates by reference the methodology as described in the American Society of Mechanical Engineers (ASME) B31.8S Standard “Managing System Integrity of Gas Pipelines.” These IMPs must be updated to incorporate integrity threats during transportation of hydrogen or hydrogen blends.

The project scope should consider the following:

· Perform a literature review of relevant research from private or public research efforts.

· Establish a team of subject matter experts (SMEs) to assist in the review of the IMP requirements.

· Identify and quantify changes to threat levels resulting from pure hydrogen or hydrogen- blended pipelines as compared to the ASME B31.8S threats (e.g., manufacturing, corrosion, laminations, inclusions, hook cracks that have survived a hydrotest, etc.).

· Determine the effects of various blends of hydrogen and natural gas (5 percent up to 100 percent hydrogen) on various threat levels.

· Review ASME B31.8S threat algorithms, tool selection, repair criteria, and acceptance limits to understand the integrity management challenges related to hydrogen-blended gases.

· Develop a five-year field-testing plan that validates that the integrity management challenges can be detected and characterized.

· Deliver reported results in 24 months, with a project cost of approximately $300 thousand.

Hydrogen Pipeline Network Components General Knowledge – Determining the Required Modifications to Safely Repurpose Existing Pipelines to Transport Pure Hydrogen and Hydrogen-Blends The objective of this project is to determine practical methods to optimize or repurpose existing pipeline networks to safely transport pure hydrogen or hydrogen-blends.

Existing NG transmission and distribution pipelines may be considered for transportation of hydrogen or hydrogen-blends in the near future. Additionally, HL pipelines could be converted for hydrogen service. However, the introduction of hydrogen into NG and HL pipelines has technical, economic, and systems-level challenges. Existing pipelines will require assessment of components before transporting hydrogen. In addition, the operator will need to assess their existing pipelines to determine if modifications are required as different hydrogen-blend percentages are added.

The project scope should consider the following:

· Perform a literature review of relevant research from private or public research efforts, along with performing industry outreach to aid in the research, to avoid duplication, and to potentially complement what already exists.

· Identify potential limitations in system components and any relevant pipeline conditions or anomalies that might affect the conversion to hydrogen service (pure hydrogen or hydrogen-blends).

· Evaluate metallic and non-metallic components as part of the pipeline system that will require retrofit or replacement to safely transport hydrogen.

· Develop an assessment and repair procedure of any currently identified anomaly in the system (i.e., cracks, dents, corrosion, etc.). This should be addressed as applicable to either metallic and/or non-metallic pipelines, for gas distribution and/or gas transmission, and potentially HL pipelines being considered for conversion.

· Assess the need for changes to critical flaw size and respective detection thresholds for pipeline integrity assessments of hydrogen or hydrogen-blend pipelines and determine the appropriate changes and parameters to maintain pipeline safety.

· Review current regulatory requirements for conversion to service from one commodity to another. Evaluate implications for pipeline safety where the goal is to meet or exceed minimum regulatory requirements[footnoteRef:7]. [7: 49 CFR Part 192, § 192.14 Conversion to service subject to this part: https://www.ecfr.gov/current/title-49/subtitle-B/chapter-I/subchapter- D/part-192/subpart-A/section-192.14]

· Determine and describe thresholds for operator actions that may be necessary to maintain safety prior to the introduction of hydrogen. This could include the development of best practices for an operator.

· Deliver reported results in 36 months, with a project cost of approximately $1 million.

Methane/CO2 Mitigation – Construction through Operations General Knowledge – Determining How to Advance Methane Leak Detection Technology Deployed in Diverse Operating Areas/Environments Beyond Current Capabilities The objective of this project is to develop advanced remote methane leak detection technologies.

Improvements in leak detection in diverse operating conditions, such as varying terrain, climate, geographic population, and pipeline operating system conditions, are needed. Recent field validation studies, funded by PHMSA and industry, indicate there are limitations to using natural gas leak detection technology to quantify and locate leaks[footnoteRef:8]. These identified limitations are physical and operational factors or conditions that limit the detection thresholds. [8: https://primis.phmsa.dot.gov/matrix/PrjHome.rdm?prj=647 & https://primis.phmsa.dot.gov/matrix/PrjHome.rdm?prj=850]

The project scope should consider the following:

0. Perform a literature review of relevant research from private or public research efforts, including service providers and operators.

0. Review the findings of recently funded research and develop enhancements to natural gas remote-sensing leak detection technologies that will mitigate or remove the identified limitations8.

0. Validate that enhancements effectively detect, locate, and measure methane emissions in diverse operating conditions, such as varying terrain, climate, geographic population, and pipeline operating system conditions.

0. Document and propose advancements to remote-sensing methane leak detection technologies.

0. Coordinate and share information with other PHMSA-related research projects.

0. Deliver reported results in 12 months, with a project cost of approximately $500 thousand.

General Knowledge – Establishing Pipeline Industry Best Purging Practices for Minimizing Methane Emissions in Transmission, Distribution, and Gathering Pipelines The objective of this project is to establish best purging practices for the elimination or avoidance of methane emissions during pipeline construction, commissioning, and maintenance.

Methane releases and emissions can occur in transmission, distribution, and gathering pipelines at any point across the system. To achieve decarbonization and climate change goals, the government and the pipeline industry are working to minimize methane emissions.

The project scope should consider the following:

0. Perform a literature review of relevant research from private or public research efforts, including service providers and operators.

0. Identify strategies to reduce, eliminate, or avoid methane emissions during construction, commissioning, and maintenance activities.

0. Identify updates on purging operations to be included in the American Gas Association (AGA) Recommended Practice (RP) (AGA XK0101) – “Purging Principles and Practice.”

0. Include new knowledge for minimizing emissions and prioritize considerations to avoid emissions by the quantity of the release.

0. Describe the operating scenario and environment as described in RP AGA XK0101 and develop procedures detailing the events and actions to be taken.

0. Establish the safe rate to purge the system, including the introduction of the purge medium and the operator qualification requirements within the procedures.

0. Deliver reported results in 12 months, with a project cost of approximately $600 thousand.

General Knowledge – Developing Design and Welding Requirements Including Material Testing and Qualification of New and Existing Pipelines for Transporting CO2 The objective of this project is to fill gaps in knowledge on materials, welding, and operational integrity by developing required material assessments and qualifications for pipelines transporting CO2.

CO2 pipelines, both gaseous and supercritical liquid, will play a key role in decarbonizing the U.S. energy sector. The researcher should identify safety gaps and requirements to support best practices for both gaseous and supercritical liquid systems, beyond the requirements of 49 CFR Part 195 for CO2 pipeline transportation.

The project scope should consider the following:

· Perform a literature review of relevant research from private or public research efforts, including service providers and operators.

· Conduct material assessments on fracture toughness and steel pipe quality requirements to arrest fractures if the pipeline should leak or rupture. The findings may be used to develop a strategy for placement of fracture mitigation measures along the pipeline.

· Identify effective odorization strategies for CO2 leak detection.

· Develop recommended emergency response safe distances based on the asphyxiation potential of CO2 pipelines.

· Develop recommended integrity management approaches based on the potential impact radius (PIR) for CO2 pipelines. The project scope should include establishing a PIR for CO2 pipelines if it has not been established already by another organization. This will support the successful assessment of integrity management implications.

· Include material testing on a wide range of steel grades for a CO2 pipeline to determine the effects of corrosion, dents, cracks, or gouges that incorporate current anomaly assessment methods to establish safe operating conditions.

· Establish operational integrity considerations and mitigation techniques for blowdowns and venting.

· Investigate the appropriate use of isolation valves for limiting the amount of product released during incidents and for arresting a propagating fracture.

· Deliver reported results in 24 months, with a project cost of approximately $1.5 million.

Liquefied Natural Gas (LNG) General Knowledge/Modeling – Determine the Maximum Permissible Temperature Drops for Steel when Exposed to Cryogenic Liquid The objective of this project is to address new technologies such as full-containment tanks using a metal secondary outer container and pipe-in-pipe systems, instead of steel material used for LNG tanks. PHMSA is seeking research investigating, testing, and determining the maximum permissible rate of temperature changes for various types of steel when exposed to cryogenic liquid.

Section 193.2155(a)(3) of Title 49 CFR requires that structural members of impoundment systems be designed and constructed to prevent impairment to the system’s performance reliability and integrity from the effects of the temperature, thermal gradient, and any other anticipated degradation resulting from sudden or localized contact with LNG.

The project scope should consider the following:

0. Perform a literature review of relevant research from private or public research efforts.

0. Include two case studies involving releases from the LNG primary container and the inner pipe of a pipe-in-pipe system.

0. Include materials that are used in the design for the LNG container inner tank, such as 9 percent nickel steel, as well as other types of stainless-steel used for cryogenic service.

0. Require that impounding areas have a minimum volumetric capacity equal to the greatest volume of LNG, flammable refrigerant, or flammable liquid that can be discharged into the area during a 10-minute period from any single accidental leakage source per the National Fire Protection Association 59A-2001, Section 2.2.2.2, incorporated by reference in § 193.2101.

0. Recommend proper protection for these supporting structures from exposure to cryogenic temperatures.

0. Provide input from independent SMEs.

0. Deliver reported results in 24 months, with a project cost of approximately $400 thousand.