Attachment 7 - Research Topics 693JK326RA001.docx

Summary of Pipeline Safety Research Announcement 12 Topics

U.S. Department of Transportation (DOT) RA No. 693JK326RA001 Pipeline and Hazardous Materials Safety Administration (PHMSA) Attachment #7

Pipeline Safety Research and Development (R&D) Program Research Announcement 12 Detailed Topics A. Priority Area: Anomaly and Threat Detection

1. Technology Development – NDE Technologies for Pipeline Seam Toughness Evaluation Objective and Background Many vintage pipeline assets were installed without documented seam toughness requirements. Original material test records, where available, also frequently omit fracture toughness or Charpy V-Notch values. Current regulatory frameworks—such as 49 Code of Federal Regulations (CFR) §§ 192.712 and 195.106—require credible toughness inputs, often forcing operators to rely on conservative assumptions, destructive cutouts, or pressure testing. The primary objective of this project is to develop and validate nondestructive evaluation (NDE) approaches capable of producing credible estimates of pipeline seam toughness for all pipelines, vintage and non.

The project will establish performance limits, data quality requirements, and validation protocols necessary to enable operator use of NDE seam toughness measurements in integrity management.

The project scope must include the following tasks:

· Review existing industry approaches used to infer or estimate seam toughness, including laboratory correlations, surrogate indicators, and available NDE techniques (in-ditch and in-line inspection (ILI)).

· Quantify the sensitivity of commonly used fracture mechanics to seam toughness inputs. Establish target accuracy, repeatability, and uncertainty requirements.

· Assemble a statistically meaningful dataset of pipeline samples that represent vintage manufacturing methods. Datasets will be divided for assessment development and independent validation populations.

· Perform supplemental laboratory testing to ensure consistent seam toughness characterization. Conduct controlled NDE measurements on all samples using techniques suitable for outer-diameter access on in-service pipelines.

· Establish empirically based relationships between NDE responses and laboratory values. Independently evaluate prediction accuracy, repeatability, and robustness against predefined criteria.

· Deliver validated performance results and recommended implementation practices suitable to support technology deployment.

· Coordinate with a pipeline operator or service provider to conduct field testing of the technology in an operational ditch environment. It is anticipated that this task will transition the technology from Technology Readiness Level (TRL) 5 to TRL 6/TRL 7 (System Prototype Demonstration).[footnoteRef:2], [footnoteRef:3] [2: Mid TRLs (4–6): The technology is a rough prototype or a “proof of concept” that works in a controlled setting, such as a laboratory. ] [3: High TRLs (7–9): The technology has advanced beyond laboratory testing. Achieving a TRL 7 implies the development of a full-scale, functional prototype and successfully validated its performance under actual field conditions and real-world operational scenarios.

· Provide tools and technologies that have the best potential for being used “as is” or modified to perform reliably (prioritizing near-commercial solutions) and describe operational tasks for which an operator would use the technology.

· Identify representative implementation costs.

· Include participation and input from stakeholder groups—such as operators, service providers, industry experts, and standards development organizations (SDOs)—to facilitate knowledge transfer.

· Provide a detailed breakdown of project costs and expected deliverables at each stage of development.

· Involve a total project duration not to exceed 12 months.

2. Knowledge Development – Roadmap Development for Complex Pipeline Crack Inspection Objective and Background Despite ongoing advancements in ILI systems, critical gaps persist in the reliable detection, characterization, and sizing of complex crack geometries. The primary objective of this research project is to transform these known limitations into a structured, industry-aligned roadmap with clearly defined and measurable performance targets that drive the development of next-generation inspection technologies.

The expected outcome is a roadmap that drives significant improvement in the detection of challenging crack types (e.g., short penetrators, complex geometries, and interactions with metal loss or hard spots).

The project scope must include the following tasks:

· Perform a comprehensive literature review of current challenges and past research regarding complex crack detection to avoid duplication.

· Quantify current ILI performance limitations for complex crack scenarios—to include but not be limited to off-axis, complex, and circumferential cracks.

· Establish standardized nomenclature of complex cracks and interaction scenarios to ensure alignment across industry stakeholders.

· Define measurable targets (e.g., probability of detection requirements, sizing thresholds) aligned with integrity management needs.

· Evaluate existing and emerging ILI technologies and identify where innovation or complementary technologies are required.

· Deliver a phased roadmap (near, mid, and long-term) supported by stakeholder engagement to guide R&D investment and adoption.

· Include participation and input from stakeholder groups—such as operators, service providers, industry experts, and SDOs—to facilitate knowledge transfer.

· Provide a detailed breakdown of project costs and expected deliverables at each stage of development.

· Involve a total project duration not to exceed 12 months.

3. Technology Development – Standardizing a common ILI Data Format for Run-to-Run Correlation Objective and Background To enhance pipeline safety management, data-driven predictive models are driving a critical shift from reactive to proactive planning. This necessitates advanced artificial intelligence (AI) frameworks capable of integrating vast datasets—specifically pipeline inspection results and environmental factors—to accurately predict historical corrosion growth rates and model pipeline corrosion risks.

The objective of this research is to develop a non-proprietary, high-resolution, three-dimensional (3D) grid format for standardizing ILI data output. This standard will facilitate improved accurate comparison between historical and subsequent inspection datasets (run-to-run correlation), accurate pit-to-pit matching, and reliable corrosion growth assessments across diverse ILI vendors and technologies.

This topic directly supports and enhances data integration requirements under 49 CFR Part 192 and Part 195, as well as consensus standards—including American Petroleum Institute (API) Recommended Practice (RP) 1160, API Standard 1163, and API Bulletin 1178—for all piggable pipelines transporting gas and hazardous liquids.

The project scope must include the following tasks:

· Identify suitable ILI vendors and define the types of tools for standard development.

· Perform a thorough literature review of existing pipeline failure prediction models.

· Determine strategies to overcome the limitations of traditional ILI data formats and implement high-fidelity data fusion and predictive AI analytics to achieve more accurate failure prediction.

· Establish a TRL maturity path that defines a clear framework to advance the standardized 3D grid format and AI predictive model from TRL 3 (Analytical/Experimental Proof of Concept)[footnoteRef:4] to TRL 6 (System Prototype Demonstration in a Relevant Environment) over the course of the project. [4: Low TRLs (1–3): The technology is still in the “foundational” phase, and it consists of basic research, mathematical formulas, or early conceptual testing. ]

· Evaluate whether the standard data format requires the development of a new predictive model, modification of an existing model, or is applicable to a current model.

· Develop requirements for collecting, normalizing, and refining data for the AI-assisted predictive model.

· Define the necessary subject matter expertise for utilizing the model in risk assessment.

· Define the types of defects (e.g., general corrosion, axial or circumferential grooving, pitting) for which the standard data format can properly quantify ILI features and interacting anomalies.

· Evaluate the feasibility of integrating the standardized 3D ILI data with necessary environmental and operational data for the AI model.

· Develop a practical methodology and workflow for ILI vendors to output the processed ILI data, establishing a fully functional software prototype at TRL 5/TRL 6 (Validation of a Technology in a Simulated Multi-Vendor Environment).

· Validate the model accuracy for failure pressure prediction.

· Conduct testing to prove the standard data format successfully overcomes traditional methods for predicting corrosion growth rate and pipeline failure.

· Include participation and input from stakeholder groups—such as operators, service providers, industry experts, and SDOs—to facilitate knowledge transfer.

· Provide a detailed breakdown of project costs and expected deliverables at each stage of development.

· Involve a total project duration not to exceed 12 months.

4. Knowledge Development – Impacts of Reconductoring on Pipeline Safety Objective and Background To meet growing electricity demand, electric utilities are rapidly deploying reconductoring projects to increase the current-carrying capacity of existing high-voltage alternating current (HVAC) transmission lines.

The objective of this research is to investigate the extent and impact of reconductoring, specifically the increased risk of alternative current (AC)-induced corrosion on pipeline integrity management.

This work will develop the knowledge needed to foster industry awareness and facilitate proactive measures to mitigate safety risks for pipelines collocated with the HVAC transmission lines under reconductoring.

The project scope must include the following tasks:

· Conduct a comprehensive study on how reconductoring and the dynamic loading of HVAC transmission lines affect pipeline integrity management and safety according to the Federal regulations in 49 CFR Part 192 and Part 195.

· Perform a thorough literature review of existing risk models developed for AC interference on pipeline integrity and determine if these models need to be updated to address the risks posed by HVAC transmission line reconductoring.

· Investigate the extent to which reconductoring could affect collocated natural gas and hazardous liquid pipelines, including:

· Identify the locations where pipelines could be impacted by the induced AC current.

· Assess how the cathodic protection (CP) system could be disrupted by AC interference.

· Evaluate various pipeline coating types and application standards to determine those that offer superior resistance to AC induced current damage while maintaining optimal CP system functionality.

· Quantify the consequences of increased AC interference, specifically focusing on the pipeline failure modes, their likelihoods, and the associated risks to pipeline facilities.

· Develop the best practice to mitigate AC interference under reconductoring conditions, considering—but not limited to—the following proactive measures:

· Improve communication between pipeline operators and powerline owners for proactive actions when reconductoring projects are planned.

· Monitor and frequently survey the affected areas by HVAC powerlines for changes in AC interference levels and cathodic protection adequacy.

· Determine the financial impacts and future deployment expectations, including the costs of necessary remediation and repairs to mitigate safety risks.

· Include participation and input from stakeholder groups—such as operators, service providers, industry experts, and SDOs—to facilitate knowledge transfer.

· Provide a detailed breakdown of project costs and expected deliverables at each stage of development.

· Involve a total project duration not to exceed 12 months.

5. Technology Development – Non-Destructive Evaluation (NDE) Technologies for Assessing Material Strength, Fracture Toughness, and Length Scale Effects in Pipelines Objective and Background The primary objective is to research, to develop, and to validate an advanced NDE technology or measurement technique capable of accurately quantifying in-situ material strength (yield strength and ultimate tensile strength) and fracture toughness for pipeline steels and vintage assets. The technology must explicitly characterize and resolve “length scale effects,” accounting for how microscopic, localized NDE material measurements translate reliably to macroscopic, full-scale structural performance across gas, hazardous liquid, liquefied natural gas (LNG), and underground natural gas storage (UNGS) infrastructure.

The scope of the project focuses on overcoming the technical limitations of current in-the-ditch and ILI NDE methods, which struggle to provide direct, high-fidelity measurements of material toughness and yield strength without destructive sampling. The research must investigate advanced physical testing and sensing modalities, such as automated ball indentation, acoustic emission, advanced ultrasonic testing (e.g., phased array or electromagnetic acoustic transducers), or magnetic Barkhausen noise (MBN) to establish correlations with mechanical properties.

A critical requirement of the scope is addressing the length scale effect. Because NDE techniques typically sample a micro or meso-scale volume of metal, the project must develop mathematical, multiscale, or micromechanical models to accurately scale these localized readings up to the macro-level geometries of actual operating pipelines. The technology must be viable across a broad spectrum of metallurgical conditions, including vintage legacy steels, seamless or longitudinal weld seams, heat-affected zones, and components exposed to cyclical thermal/pressure environments (such as LNG facilities and UNGS wellheads).

The project scope must include the following tasks:

· Conduct a comprehensive literature review of current global NDE capabilities for in-situ strength and toughness estimation. The contractor must explicitly review and benchmark their proposed technology PHMSA-funded NDE milestones and must clearly articulate how the chosen approach structurally advances beyond these established baselines.

· Formulate a clear theoretical framework for detailing the physics of the chosen NDE modality and its explicit sensitivity to the microstructural features governing yield strength, tensile strength, and ductile-to-brittle transition. If electromagnetic or magnetic modalities (such as MBN or coercimetry) are proposed, the framework must detail a robust mathematical approach to decouple variable operational or residual stress states from inherent microstructural properties. The system must isolate material strength thresholds independently of the asset’s active loading environment. This foundational work establishes the project at approximately TRL 2 (Technology Concept/Application Formulated).

· Develop a robust analytical, statistical, or numerical (finite element analysis) multiscale model that bridges localized NDE measurements (micro/mesoscale) with full-scale pipeline component behavior (macroscale). The multiscale model must focus strictly on bridging sensor physics to material properties (yield strength, ultimate tensile strength, toughness); macroscale pipeline structural modeling (such as geohazard displacement, soil-interaction, or overall pipeline strain capacity assessments) is considered outside the technical boundary of this task.

· Establish calibration methodologies to mathematically filter out localized metallurgical anomalies (such as a chemical segregation in micro-banding) from macro-level asset assessments.

· Fabricate or modify prototype NDE testing apparatuses optimized for typical pipeline geometries (curved surfaces, varying wall thickness), effectively advancing the hardware implementation from TRL 2 to TRL 3 (analytical/experimental critical function proof of concept). The hardware implementation must be optimized for complex, multi-axial geometries; proposals focusing solely on standard, linear, outer-diameter line-pipe scanning will be considered technically insufficient.

· Run a comprehensive laboratory testing matrix on a diverse library of pipeline steel samples (including vintage X52, modern X70/X80, and weldments). The testing matrix must dedicate some sample sets to complex component geometries and metallurgical conditions unique to UNGS wellheads and LNG facility piping subjected to extreme cyclical thermal or pressure boundary conditions. Compare the NDE results against standard destructive baselines (such as Charpy V-notch, tensile dog-bone, and compact tension tests) to quantify measurement uncertainty, achieving TRL 4 (Component/System Validation in a Laboratory Environment).

· Conduct full-scale blind testing on real-world pipeline sections or sacrificial pull-tubes that contain unknown material properties, vintage classifications, or mechanical damage.

· Evaluate the prototype system’s accuracy, repeatability, and sensitivity thresholds under simulated field environments (e.g., temperature swings relevant to LNG or varying constraint conditions typical of UNGS assets). This phase validates the technology at TRL 5 (Component/System Validation) and prepared it for field implementation.

· Define field implementation protocols that outline the explicit operational steps, equipment footprint, and surface preparation requirements needed for pipeline operators to implement the system “as is” or with minor field-ruggedization during routine in-ditch integrity assessments (targeting TRL 6/TRL 7 – Operational Deployment Readiness).

· Deliver a detailed final technical report that compiles all modeling equations, testing methodologies, and validation datasets.

· Provide a drafted set of standard operating procedures and a strategic regulatory adoption roadmap designed to help consensus SDOs—such as the American Society of Mechanical Engineers, API, or ASTM International (formerly the American Society for Testing and Materials)—integrate the developed NDE technique into standards, ensuring a smooth commercial transition from technology development into industry implementation. The testing matrix must dedicate a minimum of 30 percent of the sample sets to complex component geometries and metallurgical conditions unique to UNGS wellheads and LNG piping subjected to extreme cyclical thermal or pressure boundary conditions.

· Include participation and input from stakeholder groups—such as operators, service providers, industry experts, and SDOs—to facilitate knowledge transfer.

· Provide a detailed breakdown of project costs and expected deliverables at each stage of development.

· Involve a total project duration not to exceed 12 months.

B. Priority Area: Liquid Leak Detection

6. Technology Development – Innovative Technologies for Filtering Leak Detection False Positives Objective and Background While modern sensors can detect very small liquid pipeline leaks, other external operational factors can mimic leak conditions, triggering false alarms that disrupt operations that impact operations negatively. Operators often avoid false positives by decreasing sensitivity.

This research seeks to improve the understanding of these environments to allow leak detection technology to discern and filter false positive conditions, via advanced data review and allowing operators to increase sensitivity.

The project scope must include the following tasks:

· Perform a literature review of relevant research from private or public efforts regarding pipeline leak detection limitations.

· Ensure that the solution is applicable to hazardous liquid pipelines and utilizes existing sensor technology.

· Examine multiple operating conditions and environments that produce signals detectable by leak sensors at low thresholds. This analytical baseline establishes the software framework at TRL 2 (Technology Concept Formulated).

· Apply machine learning (ML) or AI approaches to review system operations data, advancing to TRL 3 (Analytical Proof of Concept) as the code is developed and tested against simulated leak and environmental data.

· Describe characteristics of false positive conditions such that they can be effectively filtered out of a leak detection system.

· Include participation and input from stakeholder groups—such as control room operators, service providers, and industry experts—to ensure technology transfer feasibility.

· Coordinate with a pipeline operator to pilot or field test the AI/ML application on real-world system operations data. This pilot should represent the core technology demonstration phase, elevating the AI/ML from TRL 4 (Component/System Validation in a Laboratory Environment) to TRL 6 (System Prototype Demonstration in an Operational Environment).

· Identify representative implementation costs and describe operational tasks for which an operator would use the technology.

· Include participation and input from stakeholder groups—such as operators, service providers, industry experts, and SDOS—to facilitate knowledge transfer.

· Provide a detailed breakdown of project costs and expected deliverables at each stage of development.

· Involve a total project duration not to exceed 12 months.

7. Knowledge Development – Standardized Protocols for External Leak Detection Evaluation Objective and Background There is a notable lack of standardized, publicly available frameworks for evaluating external-based leak detection technologies for liquid pipelines. Without an agreed-upon validation approach, pipeline operators are hesitant to adopt these technologies. The primary objective of this project is to create standardized test requirements and performance metrics for evaluating external leak detection systems.

The project scope must include the following tasks:

· Perform a comprehensive literature review covering current and past research on external leak detection baseline testing to complement existing solutions.

· Ensure that protocols are applicable to hazardous liquid pipelines and external (non-computational pipeline monitoring) technologies.

· Develop a protocol that could be adopted to a standard in the future from an organization, such as API.

· Establish minimum functional requirements for diverse external technologies (fiber optics, vapor, acoustic) to ensure they meet basic liquid pipeline safety needs (define technical baseline).

· Define objective key performance indicators for industry-wide benchmarking, specifically focusing on sensitivity, localization accuracy, and response time (formalize performance metrics).

· Develop a methodology to quantify the probability of detection versus the false alarm rate to build operator confidence (establish reliability benchmarks).

· Include participation and input from stakeholder groups, particularly SDOs, to ensure successful knowledge transfer and industry adoption.

· Provide a detailed breakdown of project costs and expected deliverables at each stage of development.

· Involve a total project duration not to exceed 12 months.

C. Priority Area: LNG

8. Knowledge Development – Source Term Modeling for Non-Steady State LNG Releases Objective and Background Federal siting regulations in 49 CFR § 193.2059 require flammable vapor dispersion exclusion zones from each LNG container and transfer system. Calculation of flammable vapor dispersion involves defining the source term and the resulting vapor cloud generation. The source term is the quantified release rate and physical condition of the release.

In September 2024, PHMSA sponsored an LNG research project on a comprehensive evaluation protocol that included source term models. However, the research project excluded non-steady state or transient leak scenarios.[footnoteRef:5] At LNG plants, flammable refrigerants and LNG are stored in pressurized vessels or transported via high-pressure tank trucks. In the event of a loss of containment of the vessel or truck’s contents, system pressure will gradually decrease over time. This pressure drop results in non-steady state or transient conditions. The source terms for these releases were calculated assuming steady-state conditions, which leads to an overprediction. [5: Research & Development Program: Develop an Evaluation Protocol for Non-LNG Release Hazards - Modeling]

This research project will address the current knowledge gap in existing source term model evaluation protocols. The objectives of this research project are to evaluate non-steady state release scenarios, characterize the behavior of fluid releases from pressurized vessels, and establish standardized guidelines for modeling source terms under non-steady state conditions. Ultimately, the research project will provide a framework to accurately quantify source terms in non-steady state or transient conditions, thereby enhancing the safety and overall efficacy of regulatory siting evaluations for LNG facility location selection.

The project scope must include the following tasks:

· Conduct a comprehensive literature review analyzing current research, including existing studies, experimental data, and established industry practices pertaining to non-steady state and transient leak scenarios.

· Identify specific equipment and systems within LNG plants susceptible to non-steady state releases in the event of a loss of containment.

· Conduct field or laboratory experiments to generate empirical data and develop a reference database for source term model validation.

· Include participation and input from stakeholder groups, particularly SDOs, to ensure successful knowledge transfer and industry adoption.

· Provide a detailed cost breakdown and expected deliverables for each stage of development.

· Involve a total project duration not to exceed 12 months.

9. Knowledge Development – Siting Guidance for Mobile and Temporary LNG Facilities Objective and Background Under 49 CFR § 193.2019(a), mobile and temporary LNG facilities are exempt from the broader requirements of 49 CFR Part 193, including the siting regulations in subpart B, provided that these facilities comply with the 2001 edition of National Fire Protection Association (NFPA) 59A, “Standard for the Production, Storage, and Handling of Liquefied Natural Gas.” While 49 CFR § 193.2019(b) requires operators to provide siting details to the State agency that has jurisdiction over pipeline safety, section 2.3.4(g) of NFPA 59A–2001 includes spacing requirements of mobile and temporary LNG equipment and structures. Developing consistent, data-driven best practices for temporary LNG facility siting would effectively mitigate public safety risks in the event of an unintentional LNG release.

The primary objective of this research project is to develop a comprehensive, data-driven siting framework and recommended setback distances for current day mobile and temporary LNG facilities to ensure public safety. This study will establish siting best practices that account for high pressure operation and evolving industry use cases to ensure public safety.

The project scope must include the following tasks:

· Conduct a literature review of existing siting studies and engineering designs of modern mobile and temporary LNG facilities.

· Evaluate the potential hazards from mobile and temporary LNG facilities, evaluate specific hazard endpoints, and provide guidance for conducting a siting evaluation.

· Identify and establish industry best practices for the safe placement of mobile and temporary LNG facility equipment and components.

· Formulate a setback matrix that details minimum safe separation distances based on component type, operating pressures, volume capacities, and specific exposure risks.

· Include participation and input from stakeholder groups, particularly SDOs, to ensure successful knowledge transfer and industry adoption.

· Provide a detailed breakdown of project costs and expected deliverables at each stage of development.

· Involve a total project duration not to exceed 12 months.

10. Knowledge Development – Comparison of Performance Versus Prescriptive-Based Maintenance Programs for LNG Objective and Background Maintenance regulations for LNG facilities incorporate both prescriptive intervals and performance-based methodologies pursuant to 49 CFR Part 193, subpart G. The objective of this research project is to evaluate historical incident data and compare performance-based versus prescriptive maintenance programs for LNG components. Ultimately, the study will identify industry best practices for maintenance programs and provide recommendations to advance facility safety, reliability, and regulatory compliance.

Prescriptive-based maintenance adheres to standardized, time-based intervals, manufacturer guidelines, and checklists. While this approach simplifies audits, minimizes ambiguity for maintenance teams, and provides a clear path for regulatory compliance, it may result in over-servicing. Excessive intervention could introduce unintended operational risks—such as human error during equipment reassembly—and could inadvertently compromise personnel and public safety. Conversely, performance-based maintenance prioritizes asset integrity and equipment health. By leveraging data-driven methodologies, such as predictive analytics and condition monitoring, operators can tailor maintenance actions to real-time equipment performance degradation. While this performance-based methodology optimizes maintenance frequency, it requires advanced digital infrastructure and continuous data analysis to support a higher standard of validation necessary during regulatory audits.

The scope of the project focuses on prescriptive maintenance requirements applicable to LNG facilities. This study will provide a structured framework and recommendations for implementing prescriptive, performance-based, or hybrid maintenance programs across LNG facility components.

The project scope must include the following tasks:

· Conduct a comprehensive literature review of existing studies, experimental data, and industry practices related to both performance and prescriptive-based maintenance programs.

· Evaluate critical LNG facility components, including—but not limited to—controls systems, instrumentation, and electrical components, to assess the safety risks, operational impacts, and cost-benefits associated with each maintenance approach.

· Analyze relevant regulatory requirements and industry standards for component maintenance at LNG facilities, including—but not limited to—49 CFR Part 193 and NFPA 59A (2026 edition) to determine how each maintenance methodology aligns with current regulatory safety requirements.

· Develop a structured framework and recommendations for implementing prescriptive, performance-based, or hybrid maintenance programs across LNG facility components.

· Engage key stakeholders, including LNG operators, safety experts, regulators, and engineering professionals, to validate research findings and ensure industry-wide applicability of findings.

· Include participation and input from stakeholder groups, particularly SDOs, to ensure successful knowledge transfer and industry adoption.

· Provide a detailed breakdown of project costs, schedules, and expected deliverables at each stage of development.

· Involve a total project duration not to exceed 12 months.

11. Technology Development – Assisted Operational Safeguards for LNG Facilities Objective and Background According to PHMSA incident data from 2012 to 2026, incorrect operations accounted for 29.4 percent of the 51 reportable LNG incidents. These events highlight the potential vulnerability caused by the complexity of LNG facility processes, sophisticated equipment interfaces, and demanding environments. Current LNG facility designs and operational protocols do not fully account for human factor engineering, such as cognitive overload or physiological fatigue. The objective of this research topic is to advance deployment-ready technologies, equipment, and procedures to minimize operational risk in LNG facilities through real-time feedback loops.

The research will create an intelligent operational ecosystem for both field personnel and control room operators. Utilizing AI, this system will act as a continuous cognitive guardrail during critical LNG operations, including LNG transfer, storage, and facility maintenance. The technology must be capable of dynamically evaluating human actions against established safety protocols, identifying errors mid-task, delivering instantaneous operator alerts, and guiding personnel through the necessary corrective actions to maintain total asset integrity.

The project scope must include the following tasks:

· Conduct a literature review of existing relevant studies, experimental data, and industry best practices related to human error prevention, real-time machine intent verification, and cognitive ergonomics. This phase establishes the baseline for tools and software frameworks currently at TRL 3 (Analytical/Experimental Proof of Concept).

· Define the facility personnel interacting with the proposed system. Establish a representative matrix of target user roles (e.g., control room operator, field engineer, facility safety personnel) and map the following for each:

· Specific duties.

· Environmental stressors.

· Cognitive demands.

· Identify a high-risk operational process or asset configuration (e.g., control room console interface, valve positioning during maintenance, or compressor valve sequencing) that—when operated or completed incorrectly—has been demonstrated to result in LNG facility incidents.

· Develop a robust development plan for a real-time, non-intrusive safety tool compatible with both control room and live field conditions. The core technology must utilize edge-computed AI capable of:

· Actively monitoring operator inputs or physical steps.

· Dynamically detecting procedural deviations.

· Issuing context-aware haptic or visual alerts.

· Developing adaptive step-by-step instructions. This phase advances the software tool to TRL 4 (Component/System Validation in a Laboratory Environment).

· Establish a continuous feedback loop and technical review process with relevant industry stakeholders, including LNG facility operators, maintenance contractors, SDOs, and academic risk-science experts.

· Formulate a comprehensive validation plan for testing the prototype system under representative or simulated real-world field conditions. Testing must utilize live operational personnel to benchmark error reduction rates and system usability. Executing this validation plan will transition the technology from a lab prototype to TRL 5 (System Validation in a Relevant Environment) and ultimately TRL 6 (System Prototype Demonstration in an Operational Environment).

· Specify the direct relevance to industry’s best practices and detail the technology transfer strategy for facilities regulated under 49 CFR Part 193.

· Include participation and input from stakeholder groups, particularly SDOs, to ensure successful knowledge transfer and industry adoption.

· Provide a detailed breakdown of project costs and expected deliverables at each stage of development.

· Involve a total project duration not to exceed 12 months.

Proposals that address advancements/validations to existing technologies also should:

· Focus on tools and technologies that have the best potential for being used “as is,” modified, enhanced, or added onto, to perform reliably for all, specifically detailing how the advancement elevates the current asset’s baseline TRL to a field-ready TRL 6 or TRL 7.

· Describe operational tasks for which an operator would use the technology, and the typical environments in which it will be utilized.

· Test for application, as appropriate, and provide any pertinent data.

D. Priority Area: Repair and Rehabilitation

12. Knowledge Development – Standardized Evaluation Methods for Composite-Reinforced Transmission Pipelines Objective and Background The objective is to develop and to standardize test methods, material property characterization techniques, and operational frameworks that enable consistent evaluation of hoop strength and failure threshold in composite-reinforced transmission pipelines, where traditional specified minimum yield strength-based approaches may be limited and insufficient.

This research project will establish a defensible and repeatable methodology to quantify the structural contribution of composite liners and translate measured performance into metrics usable for engineering assessment, operational decision-making, and regulatory acceptance.

The project scope must include the following tasks:

· Perform a comprehensive literature review of existing testing and evaluation methods to avoid duplication and build upon existing research.

· Define standardized test protocols for composite-reinforced steel transmission pipe.

· Procure representative pipe samples (seamless and conventional welded, excluding spiral-welded).

· Introduce controlled, repeatable defect types, including wall loss (uniform and localized), longitudinal gashes/gouges, partial-through-wall defects, and weld-related anomalies.

· Prepare paired samples (identical defects): unlined (control) vs. composite-lined (cured-in-place lining).

· Conduct hydrostatic pressure-to-failure testing under consistent conditions.

· Measure key performance metrics: hoop strain, deformation, failure pressure, and failure mode.

· Evaluate failure mechanisms and liner–host pipe interaction and quantify change in failure threshold between lined and unlined conditions.

· Correlate results to material properties and liner contribution.

· Develop guidance for integration into engineering assessments and operational frameworks.

· Include participation and input from stakeholder groups—such as operators, service providers, industry experts, and SDOs—to facilitate knowledge transfer.

· Provide a detailed breakdown of project costs and expected deliverables at each stage of development.

E. Priority Area: Threat Prevention

13. Technology Development – Automation Technologies for Workmanship Error Prevention Objective and Background The objective is to develop technology or equipment that can reduce the frequency of pipeline accidents or incidents caused by human workmanship error. PHMSA data shows that incorrect operation and construction errors, including poor workmanship during asset joining and installation, are frequent causes of pipeline accidents and incidents, carrying an increased risk of injury, death, and severe property or environmental damage. Often, these events are caused by the complexity of assembly processes, equipment parameters, or harsh field environments that do not fully account for human variables and physiological strain.

This topic seeks to develop or to improve automation tools, specialized equipment, or hardware-integrated technology that assists personnel in safely and flawlessly executing physical assembly and installation tasks. Focus must be placed on active automation tools and technology that help workers avoid mistakes by limiting or removing the human element entirely from critical execution steps (e.g., automated plastic pipe fusion (heat fusion), optimized parameter interlocking, or pipe robotic joining tools under welding and joining materials, including all NDE—such as automated ultrasonic testing—under 49 CFR Part 192 and Part 195). This emphasis targets field-centric operations performed in dynamic or harsh environments that are historically prone to manual error.

The project scope must include the following tasks:

· Conduct a literature review of relevant studies, mechanical data, past incident reports, and industry best practices related to workmanship error prevention, automated asset installation, and human-machine variable isolation. This step is anticipated to be considered TRL 2 (Technology Concept Formulation).

· Identify a specific asset type, joining technique, or construction process (such as manual welding, mechanical fitting assembly, or plastic pipe heat fusion) that—when executed with poor workmanship—historically has been demonstrated to result in pipeline or facility leaks, failures, or accidents.

· Create a robust engineering plan for building and testing an active automation tool or mechanical safeguard. The technology must:

· Physically intervene or automate the step to isolate human performance variance.

· Control critical mechanical variables (e.g., temperature, pressure, torque alignments).

· Prevent errors before they become embedded defects. Developing the engineering plan and fabricating the initial functional prototype will advance the technology from TRL 2 to TRL 3 (Analytical/Experimental Proof of Concept) and into TRL 4 (Component Validation in a Laboratory Environment).

· Include continuous technical input and review from relevant industry stakeholders, such as pipeline operators, maintenance contractors, and SDOs.

· Define the construction and field personnel who are the primary users of the target tooling and provide a representative list of field roles likely to utilize the automated equipment.

· Include a comprehensive validation plan for testing the automated equipment or tooling within a representative or real-world field construction environment with relevant personnel to quantify the elimination of manual defects. Executing this validation plan in a simulated or actual field construction environment will transition the tooling from TRL 4 to TRL 5 (System Validation in a Relevant Environment) and TRL 6 (System Prototype Demonstration in an Operational Environment).

· Specify the direct relevance and transition alignment of the developed automation tool to construction, material qualification, and structural integrity requirements regulated under 49 CFR Part 192 or Part 195, including relevant incorporated by reference industry standards. This aligns the TRL 6/TRL 7 prototype with regulatory pathways for commercial implementation.

· Include participation and input from stakeholder groups—such as operators, service providers, industry experts, and SDOs—to facilitate knowledge transfer.

· Provide a detailed milestone breakdown of project costs, direct charges, and expected deliverables at each consecutive stage of development.

· Involve a total project duration not to exceed 12 months.

Proposals that address advancements/validations to existing technologies also should:

· Focus on tools and technologies that have best potential for being used “as is,” modified, enhanced, or added onto to perform reliably for all, explicitly defining how the modification elevates to a field-ready TRL 6 or TRL 7.

· Describe operational tasks for which an operator would use the technology, and the typical environments in which it will be utilized.

· Test for application, as appropriate, and provide any pertinent data.

14. Technology Development – Proactive Supervisory Systems for Pipeline Operations Objective and Background The objective is to develop technology or equipment that can reduce the frequency of pipeline accidents or incidents caused by human error. PHMSA data demonstrates that incorrect operation is a frequent cause of pipeline and facility accidents, carrying an increased risk of injury, death, and severe property or environmental damage. Often, these catastrophic events are caused by the complexity of the processes, equipment, or harsh environments that do not fully account for human factors, cognitive overload, or physiological fatigue.

This research topic seeks to develop or improve equipment, technology, or procedures that can actively assist field and control room personnel in safely doing their jobs through continuous, real-time feedback. Focus should be placed on a deployment-ready ecosystem that functions as a proactive safety partner, essentially an AI monitor, watching actions as they occur, catching mistakes and dynamically alerting the operator immediately and guiding them through the proper next steps to ensure safe task completion.

The project scope must include the following tasks:

· Conduct a literature review of relevant studies, experimental data, and industry best practices related to human error prevention, real-time machine intent verification, and cognitive ergonomics. This phase establishes TRL 2 (Technology Concept Formulated).

· Identify a specific asset type, equipment configuration, or operational process (e.g., control room console layout, manifold alignments, or compressor valve sequences) that —when operated or completed incorrectly—has been demonstrated to result in pipeline or LNG facility incidents.

· Create a robust development plan for a real-time, non-intrusive safety tool capable of operating across both control room environments and live field conditions. The core technology must utilize edge-computed AI capable of:

· Actively monitoring operator inputs or physical steps.

· Catching procedural deviations as they happen.

· Issuing context-aware haptic/visual alerts.

· Providing adaptive instructions for the required next step. Completing the initial software architecture, edge-computing framework, and interface analysis will advance the technology from TRL 2 to TRL 3 (Analytical/Experimental Proof of Concept) and TRL 4 (Component/System Validation in a Laboratory Environment).

· Include continuous technical input and review from relevant industry stakeholders, such as pipeline operators, maintenance contractors, SDOs, and academic risk-science experts.

· Define the operational personnel who are the primary “users” of the target product, outlining a representative list of roles (e.g., console controllers, field mechanics, pipeline compliance technicians) likely to utilize the system as part of their duties.

· Include a comprehensive validation plan for testing the proactive prototype system under representative or real-world field conditions with live operational personnel to benchmark error reduction rates. Executing this validation plan using onsite personnel in simulated or actual environments will transition the tool from a lab prototype to TRL 5 (System Validation in a Relevant Environment) and TRL 6 (System Prototype Demonstration in an Operational Environment).

· Specify the direct relevance and transition alignment of the developed product to pipelines and facilities regulated under 49 CFR Part 192, Part 195, or both. This should align with the finalized TRL 6/TRL 7 prototype and regulatory compliance pathways for immediate control room or field deployment.

· Include participation and input from stakeholder groups—such as operators, service providers, industry experts, and SDOs—to facilitate knowledge transfer.

· Provide a detailed breakdown of project costs and expected deliverables at each stage of development.

· Involve a total project duration not to exceed 12 months.

Proposals that address advancements/validations to existing technologies also should:

· Focus on tools and technologies that have best potential for being used “as is,” modified, enhanced, or added onto to perform reliably for all.

· Describe operational tasks for which an operator would use the technology, and the typical environments in which it will be utilized.

· Test for application, as appropriate, and provide any pertinent data.

15. Technology Development – Continuous Monitoring Systems for Pipeline Threat and Damage Detection Objective and Background The objective is to develop, demonstrate, and validate an advanced scalable technology solution capable of real-time or near real-time detection of external threats, unauthorized tampering, and physical damage across all pipeline asset classes (gas, hazardous liquid, LNG, and UNGS). The resulting system must provide operators with immediate, actionable alerts that safeguard both the structural and functional integrity of the pipeline infrastructure before a catastrophic failure occurs.

The scope of the project encompasses…