Attachment 7 - Research Topics 693JK323RA0001.docx

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

RA #693JK323RA0001

Attachment #7

Pipeline Safety Research and Development The Proposed Research Topics

Research Announcement # 693JK323RA0001

a) Threat Prevention

1. Technology Development – Improve Geohazard Monitoring and Data Integration The objective of this project is to evaluate and develop tools and equipment that can monitor geological conditions at identified geohazard sites. This project will create a database to track and evaluate collected data to determine when or if corrective actions are warranted.

Pipelines are located throughout the United States in a variety of terrains that include geological conditions that can affect the safe operation of a pipeline. These pipelines are subject to many risks associated with geohazards that can be identified, monitored, and mitigated. The routes into which these pipelines are placed is a result of the operating needs, resource locations, and points of delivery, making geological hazards unavoidable. For example, there have been at least 16 pipeline failures since 2016 due to geological-related conditions; tens of thousands of barrels of hazardous liquids have been spilled, and more than 300,000 cubic feet (MCF) of natural gas have been released. This research topic seeks to develop technology to monitor previously identified geohazard conditions facing operating pipelines, which will result in actionable information from collected threat data. The method by which these threats are monitored and the contributing risk profile to the pipeline must be considered and include leading indicators of pipeline failure and contributing factors with industry standards, such as American Society of Mechanical Engineers (ASME) B31.8S Managing System Integrity of Gas Pipelines, for threat identification as a reasonable basis.

The project scope must:

· Be applicable to hazardous liquid and natural gas pipelines;

· Develop an externally focused process or technology for data sharing amongst operators, regulators, and service providers;

· Identify data collection, quality, and reliability solutions to enable improvements to data;

· Address regulatory and oversight drivers in that it allows operators to determine when to intervene prior to failures;

· Provide a solution that can be referenced or used in related consensus standards;

· Develop standard terminology for geohazard identification, monitoring, and threat remediation thresholds; and

· Deliver reported results within 36 months, with a total project cost of up to $800,000.

b) Underground Natural Gas/Hydrogen Storage

2. Technology Development – Improve the Performance of Wellhead Seals: Design and Monitoring The objective of this project is to develop new monitoring methodology for wellhead seals, including energized seals, and propose design changes for wellhead seals that prevent and reduce false indications of annular leaks.

The 2015 Aliso Canyon incident[footnoteRef:1] indicated gaps in surface equipment effectiveness in monitoring underground gas storage well seals. PHMSA is seeking research to fill this gap in research technology and design future wellhead seals. The project must develop new monitoring methodology for wellhead seals, including energized seals, and propose design changes for wellhead seals that prevent and reduce false indications of annular leaks. [1: https://www.phmsa.dot.gov/news/aliso-canyon-natural-gas-leak ]

Annular pressures are indicative of possible subsurface issues and will allow for quick responses to prevent or mitigate any incidents. Typically, annular pressures can arise due to multiple reasons, such as thermal expansion, tubing/casing leaks, formation gas, and wellhead seals. Most investigated annular pressures tend to point to the buildup of pressure as a direct cause from wellhead seals that allow gas to fill the annular space. This can be determined by the volume of gas and blowdown time of gas that is built up in the annular spaces.

The project scope must:

· Follow the developments of current PHMSA rulemaking (UNGS Final Rule)[footnoteRef:2]; [2: https://www.federalregister.gov/documents/2020/02/12/2020-00565/pipeline-safety-safety-of-underground-natural-gas-storage-facilities]

· Review any applicability to American Petroleum Institute (API) Recommended Practice (RP) 1170 Design and Operation of Solution-mined Salt Caverns Used for Natural Gas Storage, API RP1171 Functional Integrity of Natural Gas Storage in Depleted Hydrocarbon Reservoirs and Aquifer Reservoirs, API 90-2 Annular Casing Pressure Management for Onshore Wells, and API 6A Wellhead and Tree Equipment;

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

· Involve participants with standards organizations;

· 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 annular pressure events;

· Establish recommendations on best practices or measures to monitor annular pressures;

· Develop a model of a different wellhead design that could prevent annular pressures caused by wellhead seals;

· Develop a monitoring method that could distinguish the difference between annular pressure events;

· Utilize input from manufacturers, facility operators, service providers, etc.; and

· Deliver reported results within 24 months, with a total project cost of up to $600,000.

3. Technology Development – Incorporating Fiber Optics into Wellbore Design and Monitoring The objective of this project is to develop systems to incorporate fiber optics as an alternative method to mechanical testing and inspection logging without creating new leak paths.

PHMSA is seeking research on wellbore safety that will incorporate fiber optic technology into existing and new underground gas storage wells. The project must develop systems to incorporate fiber optics as an alternative method to mechanical testing and inspection logging without creating new leak paths. The project goal is to continuously monitor the wellbore for potential leaks via temperature, strain, and acoustic profiles. The project must provide solutions applicable for installation in a cemented liner and/or installation by externally strapped tubulars, and provide information on the lifespan of fiber optics in such a deployment context.

One of the primary reasons for UNGS incidents stems from well work events. Entry into the wellbore system is one of the most dangerous events that can be performed. Eliminating the need to conduct wellbore entry activities can be one of the primary ways to reduce UNGS incidents. Monitoring the wellbore through fiber optics can lead to reducing the number of wellbore entries needed.

The project scope must:

· Follow the developments of current PHMSA rulemaking (UNGS Final Rule)2, particularly monitoring the annulus and assessing the well’s integrity;

· Review any applicability to API RP 1170 Design and Operation of Solution-mined Salt Caverns Used for Natural Gas Storage and API RP 1171 Functional Integrity of Natural Gas Storage in Depleted Hydrocarbon Reservoirs and Aquifer Reservoirs;

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

· Involve participation with standards organizations;

· 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 use fiber optics as a means to monitor the wellbore;

· Establish recommendations on best practices or measures to deploy fiber optics to monitor wellbores through pressure, temperature, and acoustics;

· Develop a model on how fiber optics can be deployed for the use of wellbore monitoring without causing a leak path within the wellbore environment;

· Develop a monitoring system that can use the data from the fiber optics system to continually monitor the wellbore;

· Utilize input from manufacturers, facility operators, service providers, etc.; and

· Deliver reported results within 24 months, with a total project cost of up to $800,000.

4. Knowledge Development – Investigating Cement and Other Materials as a Barrier in UNGS Wells The objective of this project is to determine the appropriate height of barrier material required to mitigate/isolate leak paths. This project should then develop technology to test cement and/or other materials to validate the system integrity.

PHMSA is seeking research to conduct an extensive literary search that can support comprehensive definitions of micro annulus and leak paths in wells. The project must determine the appropriate height of barrier makeup required to mitigate/isolate leak paths. The project should then develop technology to test cement and/or other materials to validate the system integrity, including if cement and production casing can be used in combination as a single barrier system. It should also include the quantification of the combined compressive strength of cement and tubulars. Knowledge and technology from this research will feed new integrity data into the risk assessment process and integrity management programs.

Establishing a true barrier is critical in maintaining well integrity and keeping gas in the desired zones. One major issue with traditional cement barriers is micro-annuli development that leaves a channel for gas to migrate. Detecting or eliminating micro-annulus through technology, best practices, or new materials would be ideal in establishing wellbore integrity.

The project scope must:

· Follow the developments of current PHMSA rulemaking (UNGS Final Rule)2, particularly monitoring the annulus and assessing well's integrity;

· Review any applicability to API Recommended Practices API RP 1170 Design and Operation of Solution-mined Salt Caverns Used for Natural Gas Storage and API RP 1171 Functional Integrity of Natural Gas Storage in Depleted Hydrocarbon Reservoirs and Aquifer Reservoirs;

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

· Involve participation with standards organizations;

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

· Develop best practices to remove micro-annulus while cement is being placed;

· Research and test new material that can be used in place of cement for establishing a barrier;

· Develop a tool that would detect and test for micro annulus;

· Utilize input from manufacturers, facility operators, service providers, etc.; and

· Deliver reported results within 24 months, with a total project cost of up to $500,000.

5. Knowledge Development – Improving Cathodic Protection (CP) as Applied to Well Tubulars The objective of this project is to assess the effectiveness of technology used to monitor cathodic protection (CP) on underground gas storage well tubulars, specifically surface casing; evaluate the overall effectiveness of CP throughout the entire length of production casing; and determine if the CP reaches the casing strings.

The lack of systematic practices of external corrosion protection and monitoring of underground gas storage well tubulars remains a major gap in safety research. Proving that CP can be advantageous in the wellbore system can help prevent unwanted corrosion and ultimately reduce the number of needed wellbore entries. PHMSA seeks methods to improve CP design to prevent corrosion and metal loss of well tubulars. The project aims to address the four areas of investigation: assess technology used to monitor CP on underground gas storage well tubulars; assess the overall effectiveness of CP throughout the entire length of production casing; determine whether CP is reaching the targeted casing strings; and determine whether CP deployment reduces the amount of wellbore entries.

The project scope must:

· Follow the developments of current PHMSA rulemaking (UNGS Final Rule)2;

· Review any applicability to API RP 1170 Design and Operation of Solution-mined Salt Caverns Used for Natural Gas Storage and API RP 1171 Functional Integrity of Natural Gas Storage in Depleted Hydrocarbon Reservoirs and Aquifer Reservoirs;

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

· Involve participation with standards organizations;

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

· Develop a monitoring methodology that would not require wellbore entry through workovers or wirelines;

· Develop a monitoring methodology to ensure that the CP reaches the deepest points of the wellbore;

· Utilize input from manufacturers, facility operators, service providers, etc.; and

· Deliver reported results within 24 months, with a total project cost of up to $500,000.

c) Anomaly Detection/Characterization

6. General Knowledge – Investigate Damage Mechanisms to Determine Inspection Intervals for In-Line Inspection (ILI) Tools The objective of this project is to analyze failure mechanisms for hydrogen and hydrogen/natural gas blends, which are based on previously studied differences between existing integrity threats and those resulting from the presence of hydrogen. In addition, this project will determine any needed changes to integrity management (IM) reinspection intervals. This will involve developing knowledge regarding critical flaw sizes, the availability of in-line inspection (ILI) tools for these pipelines, and understanding the accuracy of such tools. This knowledge will assist with analyzing and recommending any needed changes to reinspection practices for pipelines carrying hydrogen gas and various hydrogen/natural gas blends.

A previous PHMSA funded project reviewed the integrity threat characterization resulting from hydrogen gas pipeline service under Part 192 requirements and ASME B31.8S Standard, “Managing System Integrity of Gas Pipelines.” Information developed from that study, along with any other relevant information, shall be used to determine the level of degradation of an in-service pipeline after an ILI inspection, and determine the time to failure based on analysis of the characteristics of the features. Not all anomalies discovered during an ILI inspection require immediate repair. This study will identify the remaining anomalies in the pipeline and the estimated reinspection intervals. This will include a review of ASME B31.8S (version incorporated by 49 Code of Federal Regulations (CFR) Part 192 currently, and also latest revision, as applicable) Table 3 Integrity Assessment Intervals and other risk assessment tools. This study will also evaluate any needed revisions to ASME B31.8S/B31.12 and 49 CFR Part 192 Subpart M or O, or elsewhere.

The project scope must:

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

· Review ASME B31.8S Table 3 Integrity Assessment Intervals and other risk assessment tools;

· Analyze if revisions may be required to ASME B31.8S/B31.12 (both the currently incorporated version as well as the latest review, as applicable) and 49 CFR Part 192 Subparts M and/or O;

· Based on ASME B31.8S threat algorithms, tool selection, repair criteria, and acceptance limits to understand the integrity management challenges related to hydrogen-blended gases, analyze and determine if changes need to be made to Part 192 IM reinspection intervals;

· Comprise analyses and conclusions that consider representative blends of hydrogen and natural gas from approximately 1 percent to 100 percent hydrogen;

· Consider threats informed by the previous study, which identified and quantified 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.);

· Utilize the outputs from other studies or perform sufficient validation efforts to confirm any unique threats identified in the project scope are resulting from hydrogen service; and

· Deliver reported results within 36 months, with a total project cost of up to $1,500,000.

7. General Knowledge – Dual Purpose Internal Integrity Assessment and Cleaning Tool for Hazardous Liquid Pipelines The objective of this project is to develop a dual-purpose ILI/cleaning tool resulting in time-based data capabilities that provide and refine valuable information to operators on time-dependent issues collected over cleaning cycles.

There is a continuing need to lower the cost of internal pipeline assessment technologies, improve data collection, and ensure safety of hazardous liquid pipelines. This topic seeks an alternative means of enhanced ILI data collection while integrating existing operational maintenance procedures of internal cleaning. The ILI tools are increasingly data-intensive, and are capable of quickly inspecting and characterizing defects. Operators use decision modeling tools for time-dependent repair determinations and conduct operational maintenance of cleaning hazardous liquid pipelines to prevent further corrosion, prepare for a range of ILI inspection runs, or improve throughput and reduce operating costs.

The project scope must:

· Include software tied to the processing of data collected from developed sensors to enable operators to deploy the technology as needed with minimal post-inspection analysis required. The goal is to encourage more repetitive dual-purpose ILI/cleaning runs over a wider use while ensuring safety of the hazardous liquid infrastructure;

· Conduct any further research and development to establish proof-of-concept of the sensing technology capable of being integrated into the tool to demonstrate feasibility of selected components within the tool's configuration requirements;

· Limit development of any heavy magnets, coupling, or other complexities that would increase cost. The solution should provide sufficient resolution for all defects that can be detected with current methods and, ideally, with a substantially improved reliability, including defect sizing;

· Include field testing of the ILI/cleaning tool that is relatively light weight and limited in axial length to enable easy transport, deployment through existing cleaning pig traps, and retrieval. The ideal tool should have low initial and operating costs to enable frequent deployment and must be able to address a substantial percentage of pipelines that are currently inspected. One goal is the capability to use this ILI tool where cleaning tools are normally used; and

· Deliver reported results in 24 months, with a total project cost of up to $1,500,000.

d) Hazardous Liquid Tanks

8. Knowledge Development – Standardize the Application of Vapor Corrosion Inhibitors (VCIs) The objective of this project is to develop methods and standards to qualify vapor corrosion inhibitors (VCIs), establish performance metrics, and develop monitoring best practices for their use in breakout tank corrosion control.

A breakout tank is a tank used to relieve surges in a hazardous liquid 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 its 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 stand-alone method. This project is focused on establishing methods and standards for qualifying VCIs as an alternative to CP systems, identifying performance and monitoring metrics, and establishing best practices for VCIs in breakout tank service.

The project scope must:

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

· Consider methods of VCI application under primary tank bottoms, between bottoms in tanks with multiple bottoms, and under original tank bottoms;

· Establish a method to evaluate the performance of VCIs compared to a functioning CP system and qualify their effectiveness for use in breakout tank applications;

· Establish best practices for VCI application and monitoring in breakout tank application; and

· Deliver reported results in 24 months, with a total project cost of up to $500,000.

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

· API 653 on Inspection of Aboveground Storage Tanks;

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

· API 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; and

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

9. Knowledge Development – Investigate Tank Foundation/Pad Designs to Improve Corrosion Control The objective of this project is to evaluate various tank foundation designs and corrosion control equipment to develop methods and best practices for monitoring corrosion, improve corrosion control, detect leaks, and mitigate damage caused by leaks in tanks with different foundation designs and equipment.

As mentioned, corrosion is one threat to the integrity of breakout tanks and is also the focus of this research. Traditionally, CP systems have provided the best protection against corrosion. However, breakout tanks have been built and modified to include varying characteristics and equipment, including differing foundation designs and materials, tank bottom designs, release prevention barriers, and leak detection methods, which limit the effectiveness of CP or provide challenges with preventing corrosion. This research focuses on establishing methods and best practices for monitoring corrosion, improving corrosion control, detecting leaks, and mitigating damage caused by leaks, particularly in breakout tanks with designs and equipment that limit the effectiveness of CP.

The project scope must:

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

· Consider improvement of corrosion control systems in both new tanks and existing tanks;

· Investigate the effectiveness of CP on tanks with solid pad materials (e.g., concrete or asphalt) and develop best practices for improving corrosion control in these tanks;

· Develop best practices for the design and use of release prevention and leak detection barriers;

· Develop best practices for sealing tank bottoms to prevent water ingress and other foreign materials in single and multi-bottom tanks;

· Investigate the effectiveness of various leak detection methods and develop best practices for use of leak detection equipment; and

· Deliver results in 24 months, with a total project cost of up to $500,000.

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

· API 653 on Inspection of Aboveground Storage Tanks;

· API 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; and

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

e) Liquefied Natural Gas (LNG)

10. Knowledge Development – Develop Methodologies for Cryogenic and Fireproofing Requirements for LNG Facilities The objective of this project is to develop methodologies and criteria for selecting, applying, and maintaining cryogenic and fireproofing systems designed to limit the extent of cryogenic and fire-related consequences at LNG facilities.

The National Fire Protection Agency (NFPA) 59A (2001 edition) Section 6.4.1, incorporated by reference by Part 193 Subpart C for design, requires protecting pipe supports against fire exposure and escaping cold liquid if subject to such exposure. LNG operators have applied a wide range of tools and approaches to determine the extent of these protection measures.

The project scope must:

· Perform a literature review of relevant research efforts and industry standards (current PHMSA research; API RP 2218; Sandia National Lab experiments; Underwriters Laboratory (UL) 1709 Testing; American Society for Testing and Materials (ASTM));

· Conduct a study based on design spills specified in PHMSA LNG Frequently Asked Questions[footnoteRef:3]; [3: https://www.phmsa.dot.gov/pipeline/liquified-natural-gas/lng-plant-requirements-frequently-asked-questions ]

· Analyze the effectiveness of passive protective materials used at existing LNG facilities and proposed for new LNG facilities;

· Conduct a study to determine the failure criteria required to compromise passive mitigation measures that are under extreme heat flux and cryogenic temperature;

· Specify the fire cases (i.e., trench fire, jet fire, pool fire) and conduct case studies involving simulation of fire cases and cryogenic spills to develop minimum requirements;

· Develop thresholds for Boiling Liquid Expanding Vapor Explosion (BLEVE) of pressure vessels and protective measures;

· Review the different piping supports currently used at existing LNG facilities and proposed for new LNG facilities;

· Develop criteria and recommendations for protective measures; and

· Deliver reported results within 12 to 18 months, with a total project cost of up to $350,000.

11. Knowledge Development – Development of Methodologies for Managing Process Safety Risk Using Hazard and Operability (HAZOP) and Layers of Protection Analysis (LOPA) for LNG Facilities The objective of this project is to develop methodologies for managing Process Hazard Analysis (PHA) techniques, such as the Hazard and Operability (HAZOP) and Layers of Protection Analysis (LOPA) for LNG facilities.

While Part 193 is not currently requiring PHA techniques, the results of this research project will support PHMSA's rulemaking effort related to the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2020. Furthermore, PHMSA previously commissioned a research project titled, “Performance Gap Comparison of Process Safety Management Consensus Standards and Regulatory Requirements for LNG Facilities,”[footnoteRef:4] which reviewed process safety management methodologies, and concluded with the researcher recommending that PHMSA incorporate the PHA into the LNG safety regulations. Section 5.2 in NFPA 59A (2019 edition) requires a plant and site evaluation that identifies safety and security measures incorporated in the design and operation of the LNG plant based on a PHA. A PHA is typically a qualitative evaluation of all possible causes that can lead to hazardous events. [4: https://primis.phmsa.dot.gov/matrix/PrjHome.rdm?prj=732 ]

· Review literature and relevant regulations, including the following:

· Guidance from Center for Chemical Process Safety (CCPS);

· Guidelines for Hazard Evaluation Procedures (CCPS);

· LOPA Book, Simplified Process Risk Assessment (CCPS); and

· Occupational Safety and Health Administration (OSHA) 29 CFR 1910.119.

· Identify different PHA techniques;

· Develop criteria and methodologies for conducting the PHA; and

· Deliver reported results within 12 months, with a total project cost of up to $400,000.

12. Knowledge Development – Develop Methodologies on Use of Secondary Containment Methods to Reduce the Effect of Spills and Pool Fires The objective of this project is to study the spill containment systems at different types of LNG facilities and develop appropriate methods to reduce the effects of spills and fire, as well as maintaining LNG plant personnel safety.

NFPA 59A (2001 edition) Section 2.2 provides provisions for minimizing the possibility of LNG accidental spills and leaks from LNG containers, process areas, and transfer areas that could endanger important structures and equipment. In addition, Section 2.2.3.6 requires LNG container impounding areas to be located so that the heat flux from a fire would not cause major structural damage to any LNG marine carrier that could prevent its movement.

The project scope must:

· Review the current design of impounding systems at existing LNG plants;

· Develop a standard model for LNG plants for the study, including impoundment systems;

· Conduct a case study and provide recommendations for the required simulations;

· Identify the hazards associated with fire and cryogenic spills;

· Develop methodologies for locating trench and impoundment sumps and provide recommendations for mitigation methods; and

· Deliver reported results in 12 to 18 months, with a total project cost of up to $500,000.

13. Knowledge Development – Selection and Placement of Remote, Automatic, and Manual Isolation Valves for Personnel Safety and to Minimize Release Volumes The objective of this project is to study the selection and placement of remote, automatic, and manual isolation valves for personnel safety and to minimize the released volume of hazardous fluids.

Section 6.3.3.4 in NFPA 59A (2001) requires consideration in the design of the piping system to the installation of shutoff or block valves as a means of limiting the contained volume that could be discharged in the event of a piping system failure. The project should investigate optimal placement of isolation valves.

The project scope must:

· Perform a literature review of relevant research efforts and industry standards (International Electrotechnical Commission (IEC) Standards 61511 and 61508; International Society of Automation (ISA) Guidance TR84; API 2218);

· Determine the minimum distance between isolation valves in order to prevent overflowing of the impoundment system;

· Examine valve closure times in order to avoid water hammer for different valve sizes;

· Provide recommendations on appropriate use of valve types and a means to ensure fire safety;

· Determine additional key technical details or scope items that would be necessary and recommended to be incorporated into the research project; and

· Deliver reported results within 12 to 18 months, with a total project cost of up to $400,000.

14. Knowledge Development – Acceptable Methods for Modeling Shrouding or Obstructions for Pressurized Liquid Leaks The objective of this project is to study the obstruction of the LNG piping system due to piping shrouds and provide acceptable methods for modeling vapor dispersion with shrouding.

LNG operators install piping shrouds adjacent to the potential release locations to obstruct the pressurized liquid in either the horizontal or vertical direction to minimize the extent of a vapor dispersion cloud. Section 2.2.3.4(d) in NFPA 59A (2001 edition) provides provisions for detaining vapor or other mitigating measures in the flammable vapor dispersion calculations.

The project scope must:

· Review existing literature and experimental data;

· Evaluate the current state of how modeling shrouds and obstructions for pressurized leaks is performed;

· Study different sizes, shapes, and configurations of the shrouds;

· Conduct experiments using representative liquids to confirm the behavior of the release when coming into contact with the shroud;

· Conduct simulations to confirm or demonstrate the effectiveness of the shroud and behavior of release;

· Develop methodologies and criteria for modeling vapor dispersion with shrouding; and

· Deliver reported results in 12 to 24 months, with a total project cost of up to $700,000.

15. Knowledge Development – Hydrogen-Blended Natural Feed Gas Impacts on LNG Plant Design The objective of this project is to evaluate existing and proposed LNG plant designs to ensure safe designs and operations when receiving hydrogen-blended feed gas.

Existing natural gas transmission and distribution pipelines may be considered for transportation of hydrogen or hydrogen-blends in the near future. Additionally, hazardous liquid pipelines could be converted for hydrogen service. Hydrogen-blend products could be feed gas to LNG baseload and peak shaving plants. However, the introduction of hydrogen into the feed gas has technical, economic, and systems-level challenges. Existing LNG facilities will require assessment of components before handling and processing hydrogen-blended natural gas. In addition, operators will need to assess their existing LNG facilities to determine if modifications are required as different hydrogen-blend percentages are added.

The project scope must:

· Review existing literature and studies on the impact of hydrogen-blended gas;

· Assess how hydrogen-blended feed gas could affect the vapor dispersion from design spills;

· Determine how hazard detection system design might need to change to account for a hydrogen-blended feed gas;

· Determine the failure modes and likelihood;

· Determine how hydrogen and feed gas could affect piping, equipment (materials of construction, etc.), and instrumentation and whether it could affect safety integrity levels (SILs);

· Determine what changes would be needed for operation and maintenance (O&M) practices (liquefaction, trucking import of methane refrigerant, leak detection systems, fire detection systems, seal designs, relief systems, storage tank monitoring, etc.);

· Specify acceptable levels of hydrogen and methods to maintain an acceptable level;

· Assess hydrogen impact to the vapor space within the tank; and

· Deliver reported results in 24 months, with a total project cost of up to $700,000.

16. Knowledge Development – Validation of Passive Mitigation Systems for Fires The objective of this project is to conduct experiments to validate the appropriateness and effectiveness of passive fire mitigation systems from fire impingement.

Section 5.3.2.8 in NFPA 59 (2019 edition) provides provisions for the effects of passive mitigation techniques incorporated into the fire models. The research team will conduct experiments for fire impingement on passive mitigation systems. Based on experimental data, the research team will provide criteria for the appropriate mitigation measures for reducing the risk of failures resulting in loss of containment or a BLEVE. While Part 193 is currently incorporating the 2001 edition of NFPA 59A, the results of this research project will support PHMSA's rulemaking effort.

The project scope must:

· Review existing literature and experimental data on passive mitigation methods;

· Conduct experimental testing, as well as mathematical model testing;

· Develop criteria for hazard modeling of fire impingement on passive mitigation systems;

· Develop failure criteria for structural steel and a BLEVE threshold for pressure vessels; and

· Deliver reported results in 12 to 24 months, with a total project cost of up to $900,000.

17. Knowledge Development – Develop Process for Risk-Based Inspection and Establish Recognized and Generally Accepted Good Engineering Practices (RAGAGEP) Relevant to Large-Scale LNG Facilities The objective of this project is to evaluate the OSHA process safety management (PSM) performance-based standards for LNG facilities; establish a methodology for conducting risk-based inspections for large-scale LNG plants to ensure a level of safety that is equivalent to, or greater than, the level of safety required by the current operations and maintenance regulations in 49 CFR Part 193; and provide the recognized and generally accepted good engineering practices (RAGAGEP) and industry standards required for different equipment.

Section 110 in the PIPES ACT 2020 requires the DOT to provide a risk-based regulatory approach for large-scale LNG facilities. The PHMSA-sponsored research project, Performance Gap Comparison of Process Safety Management Consensus Standards and Regulatory Requirements for LNG Facilities, evaluated consensus standards, that included OSHA’s PSM standard 29 CFR 1910.119, as well as best practices and regulatory requirements related to process safety management.[footnoteRef:5] Although the OSHA PSM standard does not apply to LNG facilities and is preempted by PHMSA regulations at Part 193,[footnoteRef:6] PHMSA seeks to evaluate risk-based approaches for demonstrating compliance with performance-based standards for LNG operations and maintenance activities. This will include developing innovative or new approaches that provide demonstrably equivalent or improved safety via risk analyses. [5: https://primis.phmsa.dot.gov/matrix/PrjHome.rdm?prj=732.] [6: U.S. Department of Labor, OSHA. Letter of Interpretation. Issued April 27, 2021: https://www.osha.gov/laws-regs/standardinterpretations/2021-04-27]

· Perform a literature review of relevant regulations (OSHA PSM) and research of PSM;

· Identify relevant large-scale LNG plants;

· Review the equipment used at existing large-scale LNG plants, categorize the equipment by type, and provide a list of RAGAGEP for each type;

· Provide criteria for developing implementation plans for demonstrating compliance with risk-based O&M plans; and

· Deliver reported results in 12 to 18 months, with a total project cost of up to $500,000.

f) Climate Mitigation

18. Knowledge Development – Investigate the Recompression of Compressor Station Operations to Capture and/or Incinerate Fugitive Methane Emissions The objective of this project is to review the standard operational design of a natural gas compressor station facility powered by natural gas or electric power. In addition, this project will determine the design and equipment considerations that can be implemented on new and existing facilities for the measurement, capture and reuse, or incineration of fugitive methane emissions.

Methane is a potent greenhouse gas with a heat trapping potential 30 times greater than carbon dioxide, and reducing methane emissions is a key policy point in Executive Order (EO) 14008 of January 27, 2021[footnoteRef:7]. In response to EO 14008, the Environmental Protection Agency (EPA) is proposing new regulations to reduce pollution from the oil and natural gas industry—the largest industrial source of methane in the United States. Natural gas compressor stations are a significant source of fugitive methane emissions, more than all other facilities associated with gas transmission pipelines and storage. Within a compressor station facility, methane emissions can originate from compressors (from packing, rods, seals, equipment maintenance, etc.), flanges, valves, coolers, separators, controllers, liquid storage tanks, relief valves, and blowdown operations that occur due to emergency or routine maintenance. EPA's proposal requires routine leak monitoring at compressor stations, imposes additional requirements for flares including performance standards and continuous monitoring, and incorporates new requirements for centrifugal compressors, including the regulation of dry seal compressors which are currently unregulated. [7: https://downloads.regulations.gov/EPA-HQ-OPPT-2021-0202-0012/content.pdf ]

· Perform a literature review of relevant design and research from private or public research and operational efforts, along with industry, service providers, and equipment manufacturers outreach to aid in the review of this research project;

· Identify knowledge and limitations surrounding incineration/flaring/reuse of fugitive emissions at compressor stations;

· Identify how fugitive emissions can be minimized or eliminated for natural gas compressor station facilities;

· Include condensate storage facilities and the emissions resulting from the reduction of maximum allowable operating pressure to atmospheric pressure to reduce the condensate to storage conditions;

· Estimate the potential reduction in fugitive emissions by utilizing non- or low-venting controllers and isolation valves for relief valve testing;

· Determine if fugitive emissions can be recaptured and utilized, including low-pressure usage for power generation for existing equipment, or recompressed and injected back into the gas stream. Quantify and compare the emissions captured versus the emissions generated during reuse;

· Investigate if gas is being used as the power driver for the compressor and/or other equipment, and determine if the amount of gas used can be reduced or if new operating procedures can be implemented to capture or flare the fugitive methane emissions;

· Develop or identify new technologies that quantify and/or monitor the amount of emissions being released and captured at compressor stations; and

· Deliver reported results in 18 months, with a total project cost of up to $700,000.

g) Materials

19. Knowledge Development – Investigating the Integrity Impacts of Hydrogen Gas on Composite/Multi-Layered Pipe The objective of this project is to investigate the impact to the integrity of alternative-steel and non-steel composite pipeline systems (composite pipe) when used to transport pressurized hydrogen gas. The project will identify and address safety hazards to the pipeline facilities, people, and the surrounding environment. The project will identify required design, material and construction specifications, maintenance procedures, and a roadmap for using alternative-steel and non-steel composite systems for composite pipelines, including any additional research required for the safe operation using hydrogen transportation in composite pipelines.

Composite pipes have not been used for the transportation of high-pressure hydrogen gas in pipelines. Various types of composite pipes currently exist and are used as stand-alone pipelines or inserted into host pipes for low- and high-pressure natural gas pipelines. These composite pipes mainly consist of two or more dissimilar layers of materials, with one or more of the layers being the pressure-carrying component, while the other layers provide low permeability barriers and mechanical protection.

The project scope must:

· Perform a literature review of relevant private or public research efforts, including information from composite pipe manufacturers, other federal agencies, and U.S. national labs;

· Review information from relevant research material or entities to identify the effectiveness of the composite pipe to:

· Compatibility of the composite pipe with hydrogen;

· Permeability of the hydrogen into the composite pipe;

· Hydrogen leakage rates;

· Blistering or collapse of the composite pipe during blowdowns with rapid pressure changes;

· Composite pipe types where hydrogen reaches the outer reinforcement barrier;

· Bending effect on how any micro-cracking of the inner composite pipe barrier increases permeation and leakage;

· Any degradation of the composite pipes inner pressure barrier from the hydrogen;

· Any hydrogen-induced cracking on reinforcement materials;

· Effects of pressure cycling;

· Effects on composite pipe based upon the type of reinforcement used; and

· Any other integrity matters found in the literature and research reviews.

· Review the types of connectors used for the different types of composite pipe and the effects of hydrogen on leakage, degradation, and cracking from pressure cycling and aging;

· Review all relevant materials for the effects of varying operating pressures, temperatures, and hydrogen blend compositions and the effect of degradation or aging of the composite pipe while operational in service;

· Use information obtained from the literature review and other research to develop any additional tests required to develop composite pipe specifications and procedures for the manufacturing, design, construction, and maintenance of composite pipe transporting hydrogen. The types of composite pipes evaluated must be identified;

· Review and consider relevant standards during the design and execution of this project, including:

· ASTM G142-98(2022):

· Standard Test Method for Determination of Susceptibility of Metals to Embrittlement in Hydrogen Containing Environments at High Pressure, High Temperature, or Both.

· API Specification 15:

· Spoolable Reinforced Plastic Line Pipe; and

· Any other relevant standards identified by the project.

· Deliver reported results in 18 months, with a total project cost of up to $600,000.