Editor’s note: This is the first part of a two-part
article.
As the globe
targets reductions in carbon emissions, the envisaged use of hydrogen as a
primary energy medium for nations is underway. Like other energy sources,
hydrogen will need to be generated, stored, transported and finally, consumed.
Pipelines are a
highly cost-effective method of transportation, and existing pipeline
infrastructures are being assessed for their suitability to transport hydrogen
around the globe, either as blended within natural gas transport or as pure
hydrogen.
The nature of
natural hydrogen itself, as an energy medium, brings new considerations in its
handling throughout its lifecycle. The use of pipelines as a means of primary
H2 transportation directly infers alternative and additional requirements for
public safety and pipeline integrity beyond the natural gas hydrocarbon
infrastructures of the last 80 years.
There is
anticipation within governmental and industry groups to convert and utilize substantial
portions of the existing hydrocarbon infrastructure for hydrogen.
Pipeline
integrity principles and knowledge — in both conversion of service, as well as
ongoing maintenance — may be directly applied in many cases, while others may
be adopted with some specific validation. For the purposes here, these
principles include threat management practices and known techniques for
detection, mitigation, prioritization leading to mitigation (or removal) of a
threat.
Such practices
also include forecasting pipeline integrity at future points in time, namely
through methods for time-dependent flaw growth and remaining life predictions.
A primary method in quantitatively assessing both current and forecasting
future pipeline integrity states is In-line Inspection (ILI).
We outline this
paper in terms of pipeline integrity, threat management practices and the use
of ILI within some stated presumptions for the cases of mass-transport of
hydrogen in pipelines.
Hydrogen Lifecycle in Energy
Infrastructures
The production
of hydrogen to date has been for industrial purposes and consumption, including
fundamental production of modern chemicals and metals as widely used by
society.
A hydrogen-based infrastructure for energy presumes to displace hydrocarbon fuels as a primary distributed source, Figure 1.
Hydrogen does
not occur naturally in abundance and would have to be generated either through
electrolysis or potentially through chemical processes, such as methane
reforming.
Globally, each
nation and region have generated similar strategies for clean energy and the
role of hydrogen. Each broadly considers generation capacity, role in distribution
and usage of hydrogen, in the context of current energy sources and
availability. Each strategy also highlights the needs for significant
investments in the transition.
For the United
States, the Department of Energy (DOE) has created a strategic program and
roadmap for the generation, distribution and use of hydrogen as a primary
energy source.35,36 It presumes growth of hydrogen production through assumed
future capacities of hydrogen generation through “green” renewables, “blue” reforming
and other phased means. It also addresses and presumes a role for Carbon
Capture, which is expected to require its own pipeline network for CO2 capture
and sequestration. Most prominently, it highlights the need for both social
acceptance and broad infrastructure investments.
In 2019, Australia
released its hydrogen strategy, which looks at both national energy interests
and options for energy infrastructure.37 Australia’s strategy and plan also
highlights the possibility of net hydrogen export for international energy
markets.
Canada’s hydrogen
strategy was published in Dec 2020,38 from their Department of Natural
Resources. While it addresses similar topics of national energy interests and requirements,
it focuses highly on transition opportunities based in existing production
industries and energy sectors.
Europe has
outlined goals for energy transition, summarized as the EU Hydrogen Backbone.1 The infrastructure of this backbone presumes reuse and conversion of
its widespread current natural gas infrastructure of transportation pipelines
and distribution networks. It also envisages means for Hydrogen storage,
including repurposing of existing natural salt caverns as used for
hydrocarbons, as well as reinjection of carbon by-products back into depleted
hydrocarbon fields (such as under the North Sea).
Depending on the approach and scale to be adopted in generation and usage, a new parallel role has also emerged for Carbon Capture, where carbon emissions by-products (CO, CO2) are to be captured at points of emissions vs being released. Captured by-products will also need their own infrastructure of transport and sequestration, of which pipelines are expected to play a role.2,3,4,5
Such use of
Carbon Capture is expected in the definition of blue hydrogen production
scenarios, where H2 generation, such as from methane reforming, produces carbon
by-products to be captured. It also is expected for any scenarios where
emissions from current electrical power generation have carbon by-products (so as
to include CO2 transport from combustion to final sequestration).
Descriptors for
sources of hydrogen generation have adopted a colour spectrum terminology (Figure 3).
The role of
transmission pipelines will continue to evolve, including as a means of interim
storage, as pipeline networks are redirected according to new generation
sources, consumption needs and roles in carbon capture (current hydrocarbon
reservoir locations are not presumed to be the same as future hydrogen
generation locations).6
As the
generation of hydrogen scales up, initial methods considered included blending
of hydrogen gas with natural gas, which includes during transport within
pipelines.1,5 Reported experiences and practices today recommend
treating the situation of hydrogen blends as a conversion of service for a
pipeline,6,7,8,9 including an assessment of threats that the presence of
hydrogen brings.
Fundamental
considerations in a conversion of service are:
In lower H2 gas concentrations within a primarily natural gas fluid, studies have highlighted minor operational differences. In high concentrations, including the 100% hydrogen case, the thermal content of hydrogen gas as well as compressibility has caused studies to infer that higher pressures and higher flow speeds will be required to meet the same energy flow of current natural gas pipeline delivery.12
Presumed new pressure levels and operational practices will evolve, though also in accordance with safety considerations. Evolving standards like ASME recommend assuming higher class locations for hydrogen pipelines, as well as specific integrity management processes to consider and factor embrittlement effects on materials (in both line pipe, welds and other components).7
For
completeness, some initiatives have started to investigate hydrogen transport
and storage in an alternative form, such as ammonia. Ammonia pipelines exist in
limited forms today but may be considered as their own type of hazardous
material transport pipeline (high corrosivity, toxicity) and thus are not
considered here.
Pipeline Integrity
To start with an
initial and somewhat alternative premise, for the context of threats for
blended hydrogen pipelines, an assumption can be made that threats are any
forms of stress concentrators. This premise would include such stress
concentrators as classical physical flaws, but they also may be generalized to
any localized region where a change in its mechanical or metallurgical
properties has occurred.
With hydrogen
transportation, the inclusion of threats for areas with atypical compositional
or metallurgical properties may need to be considered, even though they are not
considered active threats with current hydrocarbon pipeline integrity
practices.
Examples include
features such as an arc burn, produced by accidental contact with a welding
electrode, or a grinding burn, produced by excessive force on a grinding wheel
during maintenance. They may also include more distinctive conditions — such as
manufacturing impurities (inclusions, laminations) in line pipe — identified as
sites for hydrogen permeation and concentration.
The integrity
discussion below presumes that there are existing populations of all threats in
some form in the pipeline that are unknown until quantified and calibrated
through various means (typically from ILI, but also pressure testing or direct
assessment/examination modeling).
With geometric,
time-dependent flaws, conventional integrity practices would confer a “critical
flaw” size that is deemed potentially injurious in near to medium term.9,10,11 This approach is applicable for time dependent threats, but cracking
will take the focus here. Critical flaw sizes may be determined for given line
pipe by establishing a safe pressure target, setting properties assumptions of
the strength of materials and using expected operating conditions.
With these
criteria and by working through the relevant failure assessment methodology, a
flaw can be categorized into an equivalent flaw size as “critical.” Hence, it
is presumed that definitions and conditions for tolerable flaw criteria will
also achieve consensus amongst stakeholders, while likely being more stringent
than today.
The presumption
of additional conservatism over equivalent hydrocarbon pipelines, such as for
crack and time dependent features in the near term, due to hydrogen
embrittlement of the materials, would lead to smaller critical flaw sizes and
related acceptability levels (if any) of remaining flaws. If also combined with
the potential accelerated growth rates of time-dependent flaws, such exercises then
present a need for earliest detection, preferably for smallest features,
through regular monitoring activities.
Growth modeling
of a flaw itself, with an assumption of simultaneous crack initiation and
growth in parallel with the flaw, becomes a tangible scenario. This would
include not only corrosion, cracking, deformation and combinations of these,
but it would also include external forces (changing over time) coincident with
conventional, time-dependent flaws and for regions of alternate material
properties.
Susceptibility, Confirmation
The impact of introducing hydrogen into carbon steel pipelines is currently under significant investigation, to establish practical and effective operational conditions and criteria. Understanding a pipeline’s susceptibility to hydrogen induced effects, logically, is recommended to come from conversion-of-service activities or from within fundamental design activities, where a threat/risk model for a given pipeline would be established.6
The conditions
for susceptibility will have their basis in the threats addressed in natural
gas pipeline practices and experiences. This includes known damage mechanisms,
such as cracking, corrosion, mechanical damage, deformation and external forces.
If
susceptibility for hydrogen embrittlement is treated simply as a “Yes” or “No”
for a given location, then the following procedures apply:
Susceptibility considerations must include monitoring for the presence of water (aqueous Hydrogen), as it would be considered a primary factor in steel permeation and embrittlement. 7,11
An assumption is
that the presence of any stress concentrator areas will be immediately
addressed, given presumed higher safety protocols and a lower acceptable
tolerance for any potential injurious anomalies. In context, such practices and
tolerability have similarities in integrity management for sour service and
specialty service pipelines.
For “low” count
populations of potential flaws, immediate remediation programs to address all
reported threats are practical and cost-effective for risk mitigation.
For “high” count populations of potential flaws, additional means of assessments and validation are required to establish criticality and injuriousness within a risk mitigation prioritization framework, which may still involve remediation of all reported threats.13
Quantification, Location
Monitoring
activities are presumed to include practices such as those from current natural
gas practices and procedures. But distinct among those is use of ILI, as a
foundational and quantitative dataset across threat types.6,7 In
previous work,14 guidance was provided in the form of recommended
elements for a reliable assessment based in ILI inspection, including those for
future forecasting and remaining life prediction. With some adaptation to
terminologies used here, these were:
Comprehensive
flaw assessment methodologies — particularly fracture mechanics-based methods
with representative material properties data — ought to be used for
prioritizing excavations and future life cycle/re-inspection intervals
prediction.
Damage Mechanisms
Cracking
Practices for
crack management threats were initiated for liquid lines, where pressure-cycling
and material fatigue are prominent. It quickly evolved to gas pipelines as well,
with external cracking mechanisms being formally classified (SCC – Stress
Corrosion Cracking), in addition to being independent of internal pipeline
product.
CEPA15 and API 117611 address multiple forms of cracking that have factored
hydrogen into different cracking formation mechanisms. It is presumed that
flexure stress (fatigue) is present in the presence of initiators or impurities
in the line pipe material (or weld) as a concentrator site for hydrogen, which
leads to cracking.
A very fundamental point is the notion of the crack feature as a material “discontinuity,” especially with a population of those features present in the pipeline as “growing discontinuities.” With this point in mind, see Figure 4 for a crack growth lifecycle. Modeling of cracking growth presumes a multi-stage “bathtub” behavior, as originally stated by Perkins and adopted by CEPA and API.15, 11
For external
cracking and initiation, current cracking (SCC) stage timing remains as is for
current hydrocarbon pipelines. For hydrogen influences as the internal source,
it is (conservatively) assumed that an acceleration through the stages will
occur as compared to hydrocarbon influences, as hydrogen may permeate within
the material (as line pipe or weld) from the inside to the outside.
In comparison,
SCC (external) conditions for Stage 1 are typically mediated through corrosion
control practices. However, crack initiation may still occur.
Of note is Stage
2, where crack growth is “mechanically driven” and assumed in the presence of
hydrogen embrittlement. Key conditions include stress-dependent loading
interactions and frequency, where the crack is growing at its fastest rate. Growth
mechanism modeling may factor in the localized stress state at a crack tip.
By Stage 3, rapid crack growth of sizable cracks occurs, and failure is imminent. Remediation and integrity management measures are expected to be taken prior to reaching this stage.
In context, H2 has always been a factor in SCC susceptibility, particularly for aqueous hydrogen, but with SCC, it presumes direct contact of the external surface of the pipe with the presence of water. Crack threats are categorized broadly within environmental cracking (including Hydrogen-induced cracking), fatigue cracking and SCC. API outlines an inclusive list of conditions (all must be present) for H2 effects to be applicable. These are: poor coating state, water presence (internal or external), high CP potentials, known high hardness material values and higher observed crack growth.11
Cracking definitions have typically been defined around the formation mechanism of the cracking, as it evolved out of the susceptibility model for conditions to be monitored. However, the physical embodiment of the crack itself is what factors into the (fracture mechanics) assessment for integrity.18
Recent efforts
in the transition to hydrogen pipelines have focused on the threat of cracking,
due to the potential embrittlement of the material caused by the presence of
hydrogen itself. Comprehensive fracture mechanics methods consider pipeline
material properties, with material toughness being a primary factor for and
influence on the sensitivity of results and the determination of severity and
risk.
One study, looking specifically at the EU gas transmission network, concluded that around 70% of European pipelines are API 5L Gr. B, X46 or X52 — steel grades that are expected to show good compatibility with hydrogen transport without modification.16
However, findings by Sandia National Laboratories, on behalf of the U.S. Department of Energy, reported that the deterioration of fracture resistance in pipeline steel is unrelated to the concentration of the hydrogen blend in the pipeline. At a given pressure, the proportion of fracture resistance lost at 1% H2 blend was also like that for 100% H2.17
At any time
through the pipeline operating life, there is the potential for conditions to
initiate for cracking; hence, susceptibility assessment and active monitoring
have been recommended practices. P&GJ
Editor’s note: This paper was first published at the 36th Pipeline Pigging and Integrity Management Conference, February 2024. Organized by Clarion Technical Conferences. Used with permission.
References