September 2023, Vol. 250, No. 9
Features
Challenges of Converting Pipelines to Hydrogen Service
By Gary Yoho, Principal Consultant, Dynamic Risk Assessment Systems
(P&GJ) — Within North America, natural gas and liquid petroleum pipelines have traditionally been designed, constructed, and operated in accordance with the requirements of the American Society of Mechanical Engineers (ASME) B31.8 [3], ASME B31.4 [4] or Canadian Standard Association (CSA) CSA Z662 [5].
These design codes have evolved to meet the needs and challenges of the transmission pipeline industry through decades of research and development, knowledge gained, and lessons learned.
ASME B31.8, ASME B31.4, and CSA Z662 have well-deserved international reputations as best-in-class, evidenced by their frequent reference by documents within other jurisdictions. However, neither the ASME B31 standards nor CSA Z662 contain explicit requirements to address the design, construction and operational challenges presented by transporting gaseous hydrogen at transmission pressures.
As a result, the conversion of liquid or gas pipelines to hydrogen service will likely need to rely on an engineering assessment1/engineering critical2 (EA/ECA) approach.
ASME and the Compressed Gas Association (CGA) have issued two documents that address the construction of new hydrogen pipelines. ASME B31.12 “Hydrogen Piping and Pipelines” is an American National Standard. The scope of CGA G5.6 “Hydrogen Pipeline Systems” is “metallic transmission and distribution piping systems carrying pure hydrogen and hydrogen mixtures,” at hydrogen concentrations above 10%.
Its stated intent is to “further the understanding of those engaged in the safe design, operation, and maintenance of [hydrogen] transmission and distribution systems.” It is not intended to be a mandatory standard or code. It contains a summary of current industrial practices. Each of these documents also provide commentary on the conversion of pipelines.
Using an EA process for the conversion of existing assets to hydrogen service offers a pragmatic avenue for a technically robust, economically feasible approach.
That said, design and conversion through engineering assessment can have some downsides. Current knowledge and experiential gaps within industry have resulted in pipeline operators, engineering consultants, and regulatory bodies deferring to the requirements of other published standards relevant to hydrogen, namely ASME B31.12.
Several of the design, construction, and operational requirements outlined within ASME B31.12 for hydrogen pipelines are inherently more conservative (when compared to ASME B31.8 and/or CSA Z662), sometimes, but not always, justifiably so. At times, the technical problem that a restrictive requirement within ASME B31.12 is intended to address has since been further evaluated and resolved by the industry.
This can lead to an unnecessarily conservative design or evaluation criteria which may offer little or no incremental benefit to the operational risk profile of that given asset. Additionally, there are so few miles of actual operating hydrogen pipeline assets (when compared to natural gas), that meaningful, calibrated quantitative risk assessments that rely on company-specific, or industry-accepted failure rates are not currently possible.
Industry is working at an unprecedented pace to address these technical knowledge gaps, to ensure that existing energy infrastructure is transitioned to hydrogen service in a responsible and sustainable manner. Driven by the potential of hydrogen transportation to contribute to established decarbonization goals, standards organizations will be required to keep pace, possibly publishing revisions on a more frequent basis, to ensure that the requirements for conversion of existing assets are done in the most technically prudent, economically feasible manner.
Likewise, regulatory bodies will need to adopt a flexible, non-dogmatic approach that prioritizes technically sound, adaptable decision-making over bureaucratically driven processes.
Legacy Pipelines
Both natural gas and liquid pipelines have been proposed for conversion to hydrogen service. Understanding the previous operation of these pipelines is key to determining their suitability for conversion.
This includes an in-depth understanding of the integrity history of a given asset, including latent anomalies, with the impact of hydrogen being assessed against each integrity threat. The consensus is that introducing hydrogen will negatively impact ductility, fracture toughness, and increase fatigue crack growth rate, even at relatively low concentrations of hydrogen.
Therefore, it is imperative that the existing material properties and the possible impact that hydrogen will have on those properties are understood and quantified through considerations such as critical flaw size and remaining life calculations.
At first glance, one would presume that a pipeline operating in gas service would be the best candidate for conversion to hydrogen service. However, in-line inspection (ILI) crack detection technologies for gas pipelines are not currently as sensitive or reliable as for liquids lines.
Likewise, gas pipelines are often considered benign from a fatigue perspective. While reasonable for pipelines operating in natural gas (or similar) service, this may not be the case when operating in hydrogen, which may result in a significant decrease in fatigue life.
As hydrogen is known to adversely impact material toughness and fatigue crack growth rate, the difference in remaining fatigue life between liquids and gas pipelines will need to be considered. It may be most beneficial to convert a pipeline which has undergone several detailed crack assessments using ILI ultrasonic technology and has in place an established fatigue management program.
Conversely, gas pipelines may be more beneficial from a capital investment perspective as the associated facilities are more compatible for hydrogen than a liquids pipeline. Also, a gas pipeline will likely continue operating hydraulically in a similar capacity.
Design Concerns
Design requirements for new hydrogen pipelines follow those described for natural gas pipelines in U.S. Department of Transportation Pipelines and Hazardous Materials Safety Administration (PHMSA) Regulations 49 CFR 192 [6], 49 CFR 195 [7], and ASME Standard B31.8.
However, there are specific differences, primarily in the design factors associated with maximum allowable operating pressure (MOP/MAOP) calculations and fracture control for the pipeline. Certain design process points are highlighted in this section for their application to and their impact on decisions related to the suitability of the system for conversion to hydrogen service.
Pipeline designers use Barlow’s formula to determine the maximum operating pressure (MOP/MAOP) for a pipeline based on material characteristics and allowable stresses.
ASME B31.12 requires hydrogen pipelines to use this same formula with the addition of contributing design factors F, relating to fracture control and Hf relating to material performance in hydrogen environments. Both factors tend to derate the MOP/MAOP for a particular pipeline recognizing the potential degrading effects of hydrogen absorption.
The material performance factor is selected from Table IX-5 of ASME Standard B31.12 (2019) in mandatory Appendix IX – Allowable Stresses and Quality Factors for Metallic Piping, Pipelines and Bolting Materials. It should be noted that for systems intended to operate at pressures less than 2200 psi (15.168 MPa), the value of Hf is 1.0 for materials with a grade ≤ API 5L Grade X52 [8] but would be reduced to < 1.0 for higher grades.
Practically, if an operator has an asset that is predominantly X52 material with interspersed bits of higher-grade pipe (from cut-outs, re-routes, etc.), the higher-grade pipe will dictate the material performance factor (Hf), resulting in a reduced design factor and lower operating pressure.
Pipelines with design pressures less than 2200 psi (15.168 MPa) constructed of material with a grade less than or equal to API 5L-X52 are to be considered Class 3, unless they are actually operating in an area designated as Class 4. All pipelines constructed of material grade greater than API 5L-X52 are to be considered Class 4.
As a result, maximum design factors are 0.50 for Class 3 and 0.40 for Class 4 (equivalent to natural gas design factors) vs. the 0.72 allowed for liquids lines. As an example of the derating effect of the material performance factor, the pipe design factor for API 5L-X60 material in a Class 4 location could be reduced further to 0.35. This represents a decrease in operating stress of 12.5% for API 5L grade X60, 12.75” O.D. x 0.375” (324mm x 10mm) wall thickness pipe compared to an existing natural gas pipeline.
Conversion to Service
In the United States, regulations impose specific requirements for the conversion of liquid pipelines to gas pipelines. Paragraph 192.14 of 49 CFR 192 requires that a liquid system proposed for conversion to gas be hydrostatically tested according to the requirements of Subpart J of the regulation to substantiate the maximum allowable operating pressure permitted by Sub-Part L.
Although, this may not be the case elsewhere in the world, the hydrostatic testing of a proposed liquids line conversion offers additional assessment information to operators with an appropriately designed pressure test.
CSA Z662-2023 is expected to have additional requirements relative to hydrogen transportation when released.
Fracture Control
ASME Standard B31.12 (2019) is quite specific with respect to fracture control and arrest in hydrogen pipelines. For pipelines to be operated at a hoop stress of 40% or greater of SMYS, a fracture control criterion is required, and two options are presented.
Option A, the Prescriptive Design Method, is for the design of new pipelines in hydrogen service. Option B, the Performance Based Method can be used for existing pipelines but requires the testing and subsequent qualification of the line pipe material by determining the stress intensity factor, KIH.
Fracture control Option B states that “in any case, KIH shall not be less than 50 ksi*in 0.5.” Legacy line pipe material in the ground often has a carbon content as high as 0.27 and as a result, the requisite threshold stress intensity factor value may not be achievable for some line pipe.
For pipes that cannot meet the qualifications for fracture control described in ASME B31.12 Section PL 3.7.1, MOP/MAOP is restricted to 40% of SMYS for the entire pipeline.
Conversion Process
ASME B31.12 is divided into three sections. Part GR provides General Requirements. Part IP focuses on Industrial Piping (plant and compressor station). Part PL covers cross-country pipelines. Specifically, Section PL 3.21 addresses Steel Pipeline Service Conversions, but other portions of the document include conversion requirements as well, such as sections GR 3.5 and PL 3.7.
Regulated gas and liquid pipelines are assessed for their ability to affect high- consequence areas (HCAs) in accordance with 49 CFR 192 Subpart O and 49 CFR 195.452.
Impact on HCAs may be reduced as a consequence of conversion to gas/hydrogen service. The Standard requires that a “full risk assessment” be conducted if one or more buildings intended for human occupancy are found to be within the potential impact area of a proposed hydrogen pipeline. The potential impact radius is determined according to paragraph 3.2 of ASME Standard B31.8S [9].
The numerical constant to be used in that equation is 0.47 for hydrogen as opposed to 0.69 for natural gas. This makes the impact circle 34% smaller for hydrogen service than for natural gas. However, other safety factors must be considered as hydrogen has a greater flammability range as compared to natural gas and the color of the flame is less visible as hydrogen concentration increases.
A key conversion requirement for pipeline depth of cover is presented in B31.12 Section PL 3.7.3: “When considering converting an existing pipeline transporting other fluids to hydrogen gas transmission services, a depth of cover survey shall be performed to ensure that the existing pipeline has cover that meets the requirements of this section. Although a depth of cover of 48 inches (1.2 meters) is preferred in agricultural areas, any converted pipeline in agricultural areas must have a minimum of 36 inches (0.9 m) of cover, provision must be made to lower the pipeline to provide this minimum cover, or additional cover may be added provided that it remains in place throughout the operation of the pipeline.” This requirement can result in significant costs to operators of vintage pipelines depending on the consistency with which installation procedures were designed and executed.
Integrity Threats
A complete threat assessment is recommended for lines proposed for conversion. An assessment should consider incremental time-dependent, time-independent and stable threats attributable to the conversion to hydrogen service.
When converting from liquid service, additional ultrasonic crack detection technologies should be used to enable optimal feature geometry characterization.
Internal Corrosion
Internal corrosion is the result of an electrochemical reaction where iron is converted to iron oxide or other corrosion products. An ancillary concern arises when the reaction inhibits the formation of the H2 molecule, leading to elemental hydrogen being available to migrate into the steel.
Coupled with discontinuities in the normally present protective surface oxide layer, this can result in atomic hydrogen diffusion into the steel and subsequent reduction in the crack resistance and ductility of the material.
Depending on previous service, internal corrosion may be a significant threat to a subject pipeline. Further, it is possible that internal corrosion features deemed acceptable for liquid service may require further evaluation with respect to hydrogen exposure.
Active internal corrosion provides not only the environment for hydrogen dissociation but also creates crack initiation sites which could be exacerbated by hydrogen embrittlement. Contaminants in the hydrogen gas stream (e.g., water, H2S, CO2) could also add to the internal corrosion threat.
External Corrosion
While external corrosion is considered to be a threat to all underground pipelines, coatings in good condition and cathodic protection usually provide appropriate protection.
However, excessive cathodic protection potentials (i.e., more negative than -1200mV) may accelerate the dissociation of the H2 molecule resulting in atomic hydrogen diffusion and potential hydrogen embrittlement.
Similarly, the presence of microbiologically influenced corrosion may lead to hydrogen formation at external corrosion sites. [10]
Cracking
Susceptibility to Stress Corrosion Cracking (SCC) and long-seam cracking would not be expected to change as a result of converting a legacy pipe to hydrogen service. However, hydrogen absorption will result in reductions in toughness properties and increases in fatigue crack growth rates that reduce the minimum critical flaw size in a given pipe.
Assessment and management of existing threats will have to change considering the revised operation. Additional flaw remediation may be required prior to the change in service.
Third-Party Damage
Potential hydrogen embrittlement and ductility reduction put pipe segments subject to external loading at increased risk for failure. With reduced ductility comes lower acceptable strain levels (axial and circumferential) and smaller deformation tolerance. Waterway crossings with scour and spans and areas along the right-of-way subject to encroachment and third-party excavation activity are also at greater risk.
Embrittlement
One of the key threats associated with hydrogen transportation is hydrogen embrittlement and, therefore, fracture control is a priority issue for ASME Standard B31.12. Pre-existing internal manufacturing flaws such as laminations, inclusions, and voids, both surface breaking and non-surface-breaking, can act as crack initiators following the introduction of hydrogen to the pipeline system because they allow hydrogen ions to reform as molecular hydrogen and increase pressures within the voids or at crack tips.
This phenomenon is more commonly known in pressure vessel applications and referred to as hydrogen-induced cracking (HIC) or stress-oriented hydrogen-induced cracking (SOHIC). In pipeline applications, the phenomenon is more likely in the seam-welded pipe from split skelp (<16-inch outer diameter). Localized martensitic microstructures (i.e., hard spots) resulting from certain vintage line pipe production processes can be particularly susceptible to crack formation and propagation when influenced by atomic hydrogen.
Understanding the fracture toughness of the legacy line pipe material is often a significant challenge for operators. Reviews of material test reports, GIS records, and alignment sheets often reveal that these properties cannot be accurately identified on a joint-by-joint basis. If the pipe material cannot be qualified in accordance with the fracture control requirements of ASME B31.12 Section PL 3.7.1, the MAOP must be selected to limit the hoop stress to 40% of SMYS for all points along the pipeline. Inline and in-ditch testing techniques are gaining traction in the market for assisting in the identification of hard spots and varying material properties.
Assessment Roadmap
Legacy natural gas and petroleum liquids pipelines can offer cost-effective, viable alternatives to new pipes for hydrogen transportation. Given the inconsistent nature of design guidance in these early stages of the energy decarbonization initiative, operators considering the conversion of legacy pipeline assets are left to innovate how best to proceed. Regulators and the general public will look to pipeline operators for assurance that hydrogen pipelines are safe and efficient. This proposed engineering assessment roadmap may aid in the development of a risk-based approach.
Organizational Focus
Ensuring that the operator’s organization has the proper safety and governance focus on the issues associated with hydrogen is critical for legacy pipeline conversion. Included would be upgrading skill sets and training programs so that awareness of hydrogen issues are clearly communicated throughout the operations staff.
Procedures and technical workflows must be revised or developed to specifically address the uniqueness of the hydrogen threat assessment process and repair responses.
At a higher level, safety management systems, including internal audit procedures, and risk-reliability models may require adjustment in a conservative fashion to satisfy regulators and the public. Operators will likely be expected to ensure processes are in place to track procedure compliance and procedure revisions to highlight process steps that may not be followed due to absence, complexity, lack of clarity, or non-applicability.
Knowing The Pipe
Clear understanding of the in-situ pipeline physical component properties (i.e., pipe body, seals, appurtenances, meters, equipment) and condition are vital to the engineering assessment required for design and operation. Operators are tasked with the necessity of understanding the spectrum of mechanical properties of line pipes within the system.
Whether this information comes from traceable, verifiable, and complete (TVC) construction and procurement documentation or from testing processes, the more information available, the greater the understanding of the potential impact of hydrogen on the system. Potential defects associated with the manufacturing process of the legacy line pipe must be identified, itemized, and assessed.
Often, legacy in-situ pipelines do not have sufficiently clear toughness data to allow a thorough fracture control analysis, and operators must rely on dictated conservative estimates. Although random or statistically based sampling toughness tests can be conducted on such line pipe, there is no universally accepted methodology for aligning specific joints with material test reports (MTRs) or material heats.
Conceivably, MTRs could be used in conjunction with positive material identification (PMI) technology to identify a population of pipe spools up to the length specified by the line pipe purchase order documentation.
With this population, a reduced number of mechanical tests (i.e., tensile, yield, toughness) could be performed to confirm the MTR does represent a population of spools. This is one option that could reduce the number of tests required from the one-test-per-mile prescription currently applicable within the United States.
Operators may choose to use Modified Ln-Secant equations [12] as a quick Pass/Fail evaluation screening tool. The equations can be used to produce leak-rupture curves for the pipe material using minimum estimated toughness values for pipe weld and pipe body evaluation respectively when actual toughness values are unknown.
The purpose is to identify an approximate critical flaw geometry for consideration.
For situations in which Ln_Secant curves do not provide adequate rigor, current guidance dictates that critical crack geometries must be determined using an assessment methodology that uses fracture toughness properties (e.g., KIC, etc.), such as the API Standard 579-1/ASME FFS-1 [11] Failure Assessment Diagram (FAD) approach.
Additionally. the pipeline must be examined to verify that no existing cracks are approaching the critical geometric dimensions. For system reliability, crack growth rates must also be calculated so that the anticipated crack size, based on the calculated growth rate will not exceed the critical value in twice the time until the next scheduled evaluation (half-life inspection interval).
ROW Characterization
Understanding the right-of-way (ROW) through which the pipeline runs is critical to an engineering assessment for hydrogen conversion. Characterization of the ROW as rural, isolated, congested, residential, commercial, industrial will inform potential risk controls that can be embedded in the design work.
Location of repair spools with properties that make them more susceptible to hydrogen attack (i.e., higher grade steels), areas of reduced depth of cover or actual exposure, water crossings or other areas prone to dynamic loading conditions all deserve particular attention and potential modification in the design process to mitigate the impact of hydrogen introduction.
Areas known to have third-party damage risks may also require modification to damage prevention plans to manage this threat, up to and including the removal of prior damage repaired with sleeves.
Operations, Maintenance
Conversion project evaluation will involve more than just concern about the line pipe mechanical properties and physical conditions. Operational considerations must also be addressed in the EA.
For example, odorization effectiveness in hydrogen gas is a primary concern for both public safety and leak detection capability. Damage prevention programs may require modification as well, with increased patrol frequency and inclusion of specific components (i.e., valves, flanges, elastomeric materials) becoming part of regular patrols above and beyond what may be dictated by regulations. Intervention responses are likely to change to reflect the heightened awareness of hydrogen-related concerns.
In addition to considering the location and security design for hydrogen injection/blending points, operators must be aware that concentrations of hydrogen may change along longer distances. Changes in flow direction, and the resulting change in hydraulic profile, if required by the proposed converted service must also be addressed as part of the assessment.
Integrity management programs (IMP) must ensure that threat assessment procedures and responses recognize the unique issues that hydrogen transportation introduces.
Operators must be looking for and applying technology to specific threats, not relying merely on inference from earlier assessment methodologies. Threat assessments should be done regularly and be data-driven, (i.e., a threat is only discounted based on known conditions that will not support the threat).
The threat remains active in the absence of information. This may require the introduction of new tools, technology, and procedures not previously employed on the legacy pipeline. Reassessment of residual pipeline anomalies is necessary to ensure that new operating conditions will not impact these latent anomalies negatively. Further, reassessment intervals should be reviewed to determine the value of more frequent condition assessments (i.e., inspections) and anomaly growth information.
Leading Indicators
Development of leading indicators, if included within an operator’s IMP, can also provide assurance of continual improvement with respect to safe hydrogen transportation. Develop metrics to address not just the number of events/observations/responses (i.e., lagging metrics), but also the impact or success rate of early identification and responses (i.e., leading indicators).
There is a need to provide actionable information to reduce risk and guide proactive efforts to prevent incidents or otherwise reduce system reliability.
Leading indicators to consider:
- Increased seal leakage due to elastomer degradation/softening from H2 exposure.
- Increased ILI crack detection at mechanical damage sites (i.e., reduced ductility resulting from onset H2 embrittlement)
- Increased crack depths/profiles based on ILI run comparisons or increased corrosion growth rates.
- Delayed weld cracking at weld repairs or new appurtenances based on hydrogen exposure reducing ductility.
- Measured In-situ hardness/property reductions.
- Higher measured strain in smaller deformation areas
Conclusion
Moving to a more decarbonized fuel supply chain through the conversion of existing transmission pipelines, both liquid and natural gas, to gaseous hydrogen service is possible. Hydrogen transport via pipeline has been successful for decades in limited applications. The industry has good reason to believe that it can be more widely transported in a safe and responsible fashion, provided operators perform the necessary due diligence of their systems prior to conversion.
Guidance is offered in this article on hydrogen-influenced threat assessment considerations and an Engineering Assessment roadmap to organize an operator’s thoughts when embarking on this type of evaluation.
Author: Gary Yoho has 40 years’ service in the pipeline industry with comprehensive experience in pipeline design, construction, integrity management, operations and project management. In his most recent roles, Yoho led the asset integrity departments for midstream operators with both upstream and midstream pipelines and facilities. In addition to his North American work experience, he served as pipeline discipline lead for a low-pressure gas reserves project in Trinidad and directed the HSSE review of pipelines associated with a BP Gas plant in Algeria. He has also provided technical support for multiple PHMSA/DOT audits.
References:
- [1] ASME B31.12, “Hydrogen Piping and Pipelines” American Society of Mechanical Engineers, 2019
- [2] CGA G5.6, “Hydrogen Pipeline Systems” Compressed Gas Association, 2013
- [3] ASME B31.8, “Gas Transmission and Distribution Piping Systems,” American Society of Mechanical Engineers
- [4] ASME B31.4, “Pipeline Transportation Systems for Liquids and Slurries,” American Society of Mechanical Engineers
- [5] CSA Z662, “Oil and Gas Pipeline Systems,” Canadian Standards Association, 2019
- [6] 49 CFR Part 192, “Transportation of Natural and Other Gas by Pipeline: Minimum Federal Safety Standards”
- [7] 49 CFR Part 195, “Transportation of Hazardous Liquids by Pipeline”
- [8] API 5L, “Specification for Line Pipe,” American Petroleum Institute
- [9] ASME B31.8S, “Managing System Integrity of Gas Pipelines”, 2022
- [10] NTSB, “Enbridge Inc. Natural Gas Transmission Pipeline Rupture and Fire”, United States National Transportation Safety Board Pipeline Investigation Report NTSB/PIR-22/02, August 15, 2022
- [11] API Standard 579-1/ASME FFS-1, Fitness for Service Assessment, American Petroleum Institute
- [12] Kiefner, J. F., “Modified Ln_Secant Equation Improves Failure Prediction,” Oil and Gas Journal, October 2008
Comments