RA 693JK320RA0001 Attachment 7 Research Topics.docx

Pipeline Safety Research and Development

Research Announcement # 693JK320RA0001 Proposed Research Topics

Technology Research Sought with Resource Sharing Damage/Threat Prevention (Technology/Product) Minimizing Damage to Underground Plastic Pipe PHMSA is seeking research on investigating and testing various approaches to locate plastic natural gas pipe to support intrinsic detection via above ground methods regardless of:

· Varying soils, moisture and temperature conditions,

· Coverage of concrete with/without rebar and/or through other types of pavement, and

· In congested or rural areas.

PHMSA is seeking a combined solution that can both locate the gas pipe and discern its burial depth and orientation from other utilities buried within the same corridor. The solution should have the following attributes:

· Cost effective;

· Maximizes ease of use for end user;

· Reliable/Repeatable; and

· 3D depiction via a graphical user interface.

Performance goals should be identified in the proposal and the project reporting must document the level of advancement beyond solutions currently in the market. The project scope must include a balanced consultation from pipeline operators, service providers and installation contractors. The timeframe to market this technology solution/method is 24-36 months.

(Technology/General Knowledge) Design and Placement of Compact Service Regulators Some gas service regulators have been, and in certain situations are still, placed inside of occupied structures where very limited outside space exists or where placement outside has been deemed impractical. PHMSA seeks technology solutions for service regulator design improvements or changes to address National Transportation Safety Board (NTSB) Recommendations[footnoteRef:1]. The regulator design must have a sufficiently small footprint to be installed outside where very limited outside space exists and must comply with all applicable regulations. [1: NTSB Recommendations P-19-001 https://ntsb.gov/safety/safety-recs/_layouts/ntsb.recsearch/Recommendation.aspx?Rec=P-19-001 & NTSB Recommendations P-19-002 https://ntsb.gov/safety/safety-recs/_layouts/ntsb.recsearch/Recommendation.aspx?Rec=P-19-002 ]

The proposal should involve a diverse set of Subject Matter Experts (SME) from the gas distribution industry and relevant standards organizations. PHMSA seeks reported results in 18 months.

Leak Detection (Technology) Developing Sensors to Detect Mercaptans PHMSA is seeking research to advance portable technology for detecting mercaptans in field conditions. Mercaptan is an odorant added to easily detect natural gas leaks by a person with a normal sense of smell. The project goal is to develop and validate technology that measures the concentration of mercaptans at levels comparable to those detected by a person with a normal sense of smell. The project scope must include consultation with gas company personnel who odorize gas and who are familiar with current gas chromatography lab tools to characterize mercaptans concentration in gas. This consultation should involve personnel regularly involved in sniff testing to ensure proper mercaptan odorization. The project should produce market ready technology in 18 - 20 months.

Non-Technology Research Sought with Resource Sharing Damage/Threat Prevention (General Knowledge/Modeling) Validating Models for Predicting Gas Migration and Mitigating its Occurrence/Consequence PHMSA is seeking research that can validate existing models or models being developed to predict and mitigate gas migration underground. In order to achieve the research goals, validation field tests with underground and above ground sensors are needed to characterize gas migration at gas flow rates suitable to produce concentrations of natural gas in explosive limits in structures some distance from the gas release/leak.

Background: There is evidence that the driving factors in gas migration incidents are the leak rate and the distance to the structure. The consequence of this behavior is that gas migration flux decreases rapidly with distance from the leak. The intersection of flow rate and distance to the structure are the two most important parameters to determine if a leak can produce a hazardous environment in nearby structures. The leak rate may not be known initially, but visual signs on surface, surface gas readings, or the distance the gas has migrated might be indicators for first responders to understand the incident severity.

The project scope must factor a range of flow rates to be tested. Variables of gas pressure, flow rate, depth of pipe with the leak, soils, soil conditions and migration patterns must be examined and tested to understand migration of gas underground. This will support incident characterization from the below ground and above ground measurements.

The researcher should then develop guidelines and protocols supporting first responders in emergency situations. A timeframe to deliver the model validation is 30 months.

(General Knowledge) Retrofitting Indoor Gas Service Regulators Gas service regulators for multifamily residences, residences in historic areas, and other dwellings are sometimes located inside of the occupied structures for proximity, protection, and/or aesthetic reasons. In support of NTSB Recommendations[footnoteRef:2], PHMSA seeks to develop recommendations on how to retrofit these service regulators accordingly. Solutions must be of minimal impact to gas service operation, and provide an equivalent level of safety to gas service regulators located outside of the structure. [2: NTSB Recommendations P-19-001 https://ntsb.gov/safety/safety-recs/_layouts/ntsb.recsearch/Recommendation.aspx?Rec=P-19-001 & NTSB Recommendations P-19-002 https://ntsb.gov/safety/safety-recs/_layouts/ntsb.recsearch/Recommendation.aspx?Rec=P-19-002]

The proposal should involve a diverse set of SMEs within the gas distribution industry and relevant standards organizations. PHMSA seeks reported results in 12 months.

(General Knowledge/Modeling) Applying Models for Pipeline Safety Management System Practices PHMSA is seeking research to understand how machine learning techniques can be applied to Pipeline Safety Management Systems (PSMS) as described in American Petroleum Institute's Recommended Practice 1173. The project goal seeks to create or improve tools and techniques for implementation and maintenance of PSMS by pipeline operators. Expanding the level of knowledge will lead to improved implementation of PSMS.

The proposal should include a diverse set of PSMS SMEs within pipeline operating companies and standards organizations. PHMSA seeks reported results in 18 months.

Leak Detection (General Knowledge/Modeling) Model to Improve Detection of Liquid Hydrocarbon Pipeline External Leaks PHMSA is seeking research developing a simplified physical model capable of predicting fluid and vapor migration from leaks of buried liquid pipelines. The developed model would provide insight into fluid migration in different soil environments and for different hydrocarbon products. The model output will provide guidance for placement of leak detection sensors, design of spill containment, and selection of external leak detection (ELD) technologies (e.g., acoustic, temperature and hydrocarbon sensing). The model can also be used to establish a baseline leak volume, which represents the expected leak volume from a pipeline leak, assuming no ELD system is deployed. Establishing a baseline leak volume could then serve as valuable input in a cost-benefit analysis by comparing it to the expected leak volume associated with an ELD system. The model output could therefore improve the accuracy of an ELD cost-benefit analysis, thereby enhancing pipeline operators’ ability to make informed decisions regarding a deployment strategy for external leak detection location and technology implementation for new and possibly existing systems. The availability of such liquid migration models could provide a technical basis for improved regulatory guidance on implementing leak detection technologies on liquid pipelines. The researcher should develop this model in 18-24 months.

Anomaly Detection/Characterization (General Knowledge) Developing Inspection Tool Requirements to Assess Non-Conforming Driscopipe ® 8000 PHMSA is seeking a feasibility study to determine inspection technology operational requirements for Non-Conforming Driscopipe (NCDP) ® 8000 in reference to Advisory Bulletin ADB-2012-03[footnoteRef:3] . The project will determine the inspection requirements to assess the integrity of High Density Polyethylene (PE) Pipe. Sensing capabilities for inspections would be integrated on an inline inspection platform with communications for tether-less operations. [3: https://www.phmsa.dot.gov/regulations-fr/notices/2012-5424 ]

The project will be designed around two phases of work. In the initial phase, the project at a minimum, will consider the following two areas of specification:

1) Develop a specification that meets the industry needs for inline inspection of NCDP to examine external and internal degradation under live conditions. NOTE: The most common size system for reported NCDP is a 2" diameter main with some systems having diameters of 4" or larger; and

2) Investigate the feasibility of designing an inspection system based on state-of-the-art sensing systems for PE (Terahertz, X-ray, and other systems) in three areas:

a) Determine platform requirements and locomotion requirements for specific ranges of sizes (may need multiple platforms with different level of complexity to address all sizes), for long range and ability to negotiate obstacles and features in the pipe,

b) Evaluate performance of different sensing systems to identify the defects of interest with different potential platform designs including power requirements, and,

c) Determine feasibility of remote (tether-less) communication and controls for long range operation.

A final report summarizing the initial phase is required for the technical justification of the next phase. A future phase will be required for actual tool development occurring.

A focused team should be assembled to ensure success in the first phase including sensor and robotic inspection experts and pipeline operators who have this specific PE pipe as part of their asset inventory. A report on the initial phase should be delivered within 18 months.

(General Knowledge/Modeling) Applying Models for Improved Assessment and Prioritizing of Stress Corrosion Cracking Threats PHMSA is seeking research to improve the industry's ability to model highly interactive Stress Corrosion Cracking (SCC) threats and to develop field monitoring techniques that can help to identify1ocations where pipeline is susceptible to SCC.

SCC can be found at various locations along a pipeline having the operating conditions that lead to its formation and spread. An over reliance on the currently available inspection methods may not have the sufficient resolution to detect SCC at early stage.

The project must develop a flexible machine learning model for SCC that considers both quantitative numerical models, expert inputs, and field monitoring data. Such a flexible modeling framework may be provided by Bayesian networks, but other machine learning algorithms should be considered. The model should factor dynamic changes in the disbonded coating environment and a field monitoring program that closely mimics the pipeline operating environments. Finally, the model must be validated with the capability of identifying both SCC and non-SCC sites. A timeframe to deliver such an improved model or methodology is 18 months.

Liquefied Natural Gas (LNG) (General Knowledge/Modeling) Vapor Cloud Explosion at Nil Wind PHMSA is seeking research to determine the criteria for “nil wind” dispersion and whether “nil wind” condition should be considered in the siting analysis for LNG facility hazards. The 2017 PHMSA-sponsored research conducted by the UK Health and Safety Executive concluded that a majority of very large vapor cloud incidents occurred in nil or very low wind conditions.

(General Knowledge/Modeling) Assess the Cascading Effects from Flammable Vapor Cloud Explosions PHMSA is seeking research that can assess the cascading effects from flammable vapor cloud explosions (VCE), using information retrieved as part of the historical review of VCE incidents and other studies. Section 5.3.2.14 in NFPA 59A (2019 edition) requires analysis of impacts from vapor cloud explosions and fires that may cause major structural damage to a LNG storage container, LNG marine carrier, refrigerant storage vessel, buildings, or equipment required for the safe shutdown and control of the hazard. While Annex A.6.6.4 explains the effects of different levels radiant heat on steel, NFPA 59A does not provide guidance on the effects of flammable vapor cloud explosions. In addition to determining whether severe VCE could cause structural damage to LNG storage container and other components, the research project also should evaluate projectile impacts from an explosion that may penetrate LNG facilities.

Other - Materials (General Knowledge) Review of Alternative Materials for Non-Steel or Alternative Steel Pipe Connections PHMSA is seeking research to review the safety, materials and design requirements for in-service and future service natural gas transmission and gathering pipelines regulated under 49 Code of Federal Regulations Part 192. A review of such systems is sought that operate between 125 psig and 2,180 psig pressure and over 100 degrees Fahrenheit. The following key questions must be addressed from the project scope:

· What should be the limits for maximum operating pressure and temperature?

· What should be the operating life span? What parameters should be reviewed, tested and updated (maintained) to achieve the operating life span?

· Should these pipe types have a periodic test program to ensure material properties are not degrading? What should be included in an optimal type test program (type of tests, test interval)?

· What material, design, construction, operating and integrity management aspects of Part 192, Part 195 or relevant consensus standards should be used?

· What new items should be added to Part 192 or Part 195 on the unique properties of the pipe - such as repair criteria, operating pressure and safe pressure calculations, bending, depth of cover for prevention of 3rd party damage, leakage where there are multiple layers, effects of ultraviolet rays on the pipe for storage and transportation, loss of strength over time, loss of Maximum Allowable Operating Pressure due to anomaly growth (corrosion, denting, cracking, etc.), pressure cycling and fatigue effects, other chemical/petroleum effects on the pipe, need for cathodic protection, etc.

· Under what conditions should non-steel pipe be allowed in Class 2, 3, and 4 locations, high consequence areas, freeway/railroad crossings, waterways, etc. What type design, construction, maintenance and integrity management activities should be performed, if it is allowed? What type of products should be allowed in non-steel pipelines (sweet gas, sour gas, crude oil, HVLs)?

· What Construction Operator Qualifications (OQ) and Operational OQ requirements should be placed on the Pipeline Operator?

· What should the training program include?

The project final report must specifically answer these questions. PHMSA seeks reported findings in 12 months.

(General Knowledge) Hydrostatic Retesting Optimization for Older Liquid Pipelines PHMSA is seeking research to understand cyclic loading and the balance of sustained load- cracking vs crack retardation as experienced during and after hydrostatic testing of older hazardous liquid pipelines.

Background: Owners of aging liquid pipelines need to balance between the operational safety and the cost of maintaining the fatigue life of their pipelines. One integrity validation method is to hydrostatically test the pipelines at a higher percentage of the Specified Minimum Yield Strength (SMYS). For natural gas transmission pipelines, hydrostatic testing at 90% SMYS or higher is one recommendation; however, many liquid pipelines operate at a much lower pressure level (~30 to 40% SMYS) than the Class 1 natural gas pipelines which are operating at 72% to 80% SMYS. Thus, liquid pipelines that are hydrostatically tested at 90% SMYS are very conservative with a test pressure of 2.25 to 3.0 times the MOP, while the natural gas pipelines are typically hydrostatically tested with a margin of 1.125 to 1.25 times the MAOP. Hydrostatic testing at very high-pressure levels has the advantage of discovering smaller flaws. However, this may prolong and make the hydrostatic test process difficult. In addition, there is a concern about inducing damage to the pipeline from multiple high-pressure cycles and the sustained-load crack growth during the hydrostatic test. For a liquid pipeline that experiences more pressure cycling than a natural gas line, the sustained-load crack growth could be detrimental to its cyclic fatigue life after the hydrostatic test. On the other hand, crack retardation under cyclic loading can be beneficial for the cyclic fatigue life due to the plasticity at the crack from the hydrostatic test.

Specific goals with the project are to understand how the cyclic loading fatigue re-initiation and the cyclic fatigue life are affected after hydrostatic tests. The project will compile the improved analyses into one software package for making the assessment of cyclic fatigue life as a function of the hydrostatic test pressure, operating pressure, cyclic frequency, pipe dimension, pipe grade, and material property input. There are current industry efforts to address multiple aspects that are related to these core goals. This project will leverage the existing and ongoing research that are addressing the above aspects related to the core goals. PHMSA seeks reported findings in 24 months.