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) Preventing the Safety and Damage Prevention Issues Surrounding Unlocatable Plastic Pipe PHMSA is seeking research on investigating and testing various approaches in support of the following outcome: Intrinsic detection via above ground methods regardless of varying soils, moisture and temperature conditions, coverage of concrete with/without having rebar and or through other forms of pavement, in congested or rural areas. PHMSA is seeking a combined solution that can both locate the pipe and discern its burial depth and orientation from other utilities within a 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

The proposal should identify performance goals and the project reporting must document the level of advancement beyond that of solutions in the market today. The project should utilize balanced consultation from pipeline operators, service providers and installation contractors. The timeframe to market of such improvement is 24-36 months.

(Technology/General Knowledge) Design and Placement of Compact Service Regulators For a number of situations, gas service regulators have been placed inside of occupied structures. This practice has occurred due to the limited space available when placing gas service regulators. PHMSA seeks technology solutions in the form of new service regulator designs that allow for a safety based recommendation of installation location in support of NSTB Recommendations P-19-001 and P-19-002. The regulator design must have a sufficiently small footprint to be installed where traditional gas service regulators would be impracticable. Design and implementation must comply with §192.353 Customer meters and regulators: Location, §192.355 Customer meters and regulators: Protection from damage, §192.357 Customer meters and regulators: Installation.

The proposal should indicate diverse involvement of SMEs within the gas distribution industry and relevant standards organizations. PHMSA seeks reported results in 18 months.

Leak Detection

(Technology) Advancing Sensors for Field Quantification of Mercaptans

PHMSA is seeking research to advance portable technology for detecting mercaptans under field conditions. Mercaptan is the odorant additive to natural gas making natural gas leaks detectable by the human nose. The project goal is to develop and validate technology that uniquely measures the concentration of a range of mercaptans at levels comparable to those of the human nose. The project must include consultation with gas company engineering personnel who odorize gas and who are familiar with current Gas Chromatography lab tools to characterize mercaptans in gas. This consultation should involve personnel regularly involved in sniff testing to ensure proper 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 under development for predicting gas migration underground and for mitigating its occurrence/consequence. In achieving this, a validation field test having below-ground and above ground sensors is needed to characterize gas migration at gas flow rates in suitable to produce concentrations of natural gas in explosive limits in structures some distance from the gas release/leak.

Background: The two most important values in a gas migration incident appear to be the leak rate and the distance to the structure. In some analyses, the gas spreads out spherically, the volume (or flow rate since the input is constant) is a cubic function. So, the farther from the leak, the flow rate per square foot of surface area drops off quickly. 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 leak, soil conditions and migration patterns must be studied and examined and tested to understand migration of gas underground. This will support incident characterization from the below ground and above ground measurements.

The project should then develop guidelines and protocols based on the proposed work for first responders to odor or smell of gas call emergency situations. A timeframe to delivery of such improvement is 30 months.

(General Knowledge) Retrofitting Indoor Gas Service Regulators

High density dwellings and historic buildings have sometimes employed a gas service regulator inside of the occupied structures for proximity and aesthetic reasons. In support of NTSB Recommendations P-19-001 and P-19-002, PHMSA seeks to develop recommendations on how to retrofit ventless regulators, or externally venting regulators. Solutions must cause minimal impact to gas service operation, and provide an equivalent level of safety to external gas service regulators.

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

(General Knowledge/Modeling) Applying Computational Statistics to 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 which support pipeline operator responsibilities related to the implementation and maintenance of PSMS. Expanding the level of knowledge here will lead to better and more meaningful implementations of PSMS. The project must address the following items as part of the scope:

· Apply business analysis techniques to model the elements of PSMS and the implementation environment by gathering information from relevant subject matter experts;

· Convert PSMS models into machine-readable agent-based cognitive models;

· Create Artificial Intelligence (AI) software to consume the cognitive models and realize a running AI software system;

· Execute several thousand process simulations using the AI software system and record virtual data sets; and

· Apply machine learning techniques to discover PSMS characteristics and lessons learned from the several thousand simulations.

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

Leak Detection

(General Knowledge/Modeling) A Simplified Subsurface Liquid Leak Model for Improved External Leak Detection on Liquid Hydrocarbon Pipelines

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 insights 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 particular 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 a particular ELD system. The model output could therefore significantly 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 project should develop such model in 18-24 months.

Anomaly Detection/Characterization

(General Knowledge) Developing Integrity Internal Inspection Tool Requirements for Material Degradation of 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 . The project will determine the inspection requirements to assess the integrity of High Density Polyethylene (PE) Pipe. Sensing capabilities for the integrity inspection would be integrated on an inline inspection platform with communications for tether-less operations.

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:

a) 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

b) Investigate the feasibility of designing an inspection system based on state-of-the-art sensing systems for PE (Terahertz, X-ray, and other state-of-the-art systems) in three areas: i) 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, ii) evaluate performance of different sensing systems to identify the defects of interest with different potential platform designs including power requirements, and, iii) 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 via a separate project award.

A focused team should be assembled for success in this first phase including sensor and robotic inspection experts and pipeline operators who have this specific PE Pipe as part of their asset inventory. The initial phase should report out as specified by 18 months.

(General Knowledge/Modeling) Applying Computational Statistics 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 coupon monitoring techniques that can help prognosticate locations of SCC.

Background: SCC can be found at locations and under coatings not suggested to exhibit SCC by the current state of practice seen by nationally recognized consensus standards. An over reliance on inspection may not have the sufficient spatial resolution for early stage SCC.

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 coupon program that closely mimics the pipeline operating environments. Finally, the model must be validated identifying both SCC and no-SCC sites. A timeframe to delivery of such improvement is 18 months.

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. 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 any 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 Pipe

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 CFR Part 192. A review of such systems is sought operating over 125 psig to 2180 psig pressure and over 100 degrees Fahrenheit. The following key questions must be factored and answered 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, tests conducted, and updated (maintained) to achieve the operating life span?

· Should these type pipes have a periodic test program to ensure material properties are not degrading? What should be included in an optimum 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 just for the unique properties of the pipe - such as: repair (when? and how?), 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 or shouldn’t - 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 Retest Optimization for Older Liquid Lines

PHMSA is seeking research to understand cyclic loading and the balance of sustained load-cracking vs crack retardation as experienced during and after hydrotesting of older hazardous liquid lines.

Background: Owners of aging liquid pipelines need to balance between the operational safety and cost of maintaining the fatigue life of their pipelines. One integrity validation method is hydrotesting to a high percentage of the Specified Minimum Yield Strength (SMYS). For natural gas transmission lines, hydrotesting at 90% SMYS or higher is one recommendation; however, many liquid lines operate at a much lower pressure level (~30 to 40% SMYS) than Class 1 natural gas pipelines (operating at 72% to 80% SMYS). Thus, liquid-line hydrotests at 90% SMYS are very conservative at 3.0 to 2.25 times the MOP, while natural gas line tests are typically performed at a margin of 1.25 to 1.125 MAOP. Hydrotesting at very high-pressure levels has the advantage of blowing out very small flaws. However, this may prolong and make the hydrotesting process difficult due to repairs and concern about inducing damage to the pipeline from multiple high-pressure cycles. Additionally, during the hydrotest there can be sustained-load crack growth. For a liquid line that experiences more pressure cycling than a natural gas line, that sustained-load crack growth could be detrimental to the cyclic life after the hydrotest. A separate aspect is that from any plasticity at the crack from the hydrotest, there will be crack retardation for cyclic loading that can be beneficial for the cyclic life.

Specific goals with the project are to understand how the cyclic loading fatigue re-initiation and cyclic life are affected after hydrotests and to compile the improved analyses into one software package for making the assessment of cyclic life as a function of the hydrotest pressure, operating pressure, cyclic frequency, pipe geometry/grade, and material property input. There are current industry efforts to address aspects related to these core goals that should be leveraged. PHMSA seeks reported findings in 24 months.