February 2024, Vol. 251, No. 2


Hydrogen-Blend Pipelines: Fast-Tracking Innovations Leading Fossil Fuel Resurgence

By Richard Nemec, Contributing Editor, North America  

(P&GJ) — The year 2023 was a time of extremely conflicting messages for the future of fossil fuels and the sundry clean fuel alternatives to meet distance carbon-free climate change goals.

Hydrogen pipelines in use at an H2 facility.

While global oil and gas conglomerates continue to double-down on fossil fuel consolidation in the United States, they also are spending billions of dollars on ways to squeeze the carbon emissions out of their growing portfolios.  

One of the promising alternatives continues to be the harnessing of hydrogen, but the enthusiasm for it ebbs and flows. A fuller hydrogen energy future has many subparts, and pipeline transportation is just one of the many complex facets. 

As an example, in December as the year was fading from memory, the Carbon Capture Coalition (CCC) joined more than 50 other organizations loudly calling on Congress to consider a suite of adjustments to the federal Section 45Q tax credit in proposed legislation.  

CCC Executive Director Jessie Stolark at the time told Pipeline & Gas Journal that the coalition is principally focused on enacting and implementing a supportive portfolio of policies to deploy carbon management technologies economywide, and it is not focused on drivers for the hydrogen industry, per se. But she also noted that many of the group’s member organizations also work on hydrogen policy. 

“While the coalition is principally focused on carbon management policy, we recognize the absolute essential role that carbon capture technology will play in reducing emissions across industrial sectors, including the production of hydrogen,” Stolark said. “While not the only driver of low-emissions hydrogen production, 45Q will be an important driver for the sector. However, small-scale adjustments to the 45Q tax credit are needed to ensure that the credit drives investments in carbon capture across sectors, as originally envisioned by Congress.” 

At about the same time in mid-December in California, state regulators took steps to further turn away from fossil fuels by eliminating a set of decades-long electric line extension subsidies for any new building construction projects using natural gas and/or propane in addition to electrical power.  

Set to be effective in mid-2024, the California Public Utilities Commission (CPUC) indicated this should give contractors time to “adjust their operations accordingly.” The CPUC also went on to extend the life of the state’s only remaining nuclear power plant, Pacific Gas and Electric Co.’s Diablo Canyon, as another way to help seriously reduce carbon emissions below 1990 levels by 2030. 

The U.S. Department of Energy (DOE) and a number of its national laboratories have the ongoing HyBlend program for hydrogen, and many of the nation’s most prestigious private, nonprofit and public sector energy research centers are examining various aspects of the hydrogen conundrum, many focused on the pipeline transportation systems envisioned. 

There are very few U.S. natural gas pipelines that have been repurposed so far to transport 100% hydrogen, according to the GTI’s Tony Lindsay, managing director for energy delivery at GTI Energy. The vast majority of hydrogen moved in pipelines is being done through about 1,600 miles of lines designed exclusively for hydrogen’s use in oil refining and making ammonia for fertilizers, he noted.  

Transport Methods 

“Keep in mind that there are other means of transport being used throughout the United States, namely liquefied hydrogen in cryogenic tanker-trailers on the roads as well as high pressure gaseous hydrogen in tube trailers,” Lindsay said. 

In the recent past, the Interstate Natural Gas Association of America (INGAA)’s foundation supported a comprehensive study of hydrogen blending in transmission pipeline systems and concluded overall that there are “serious issues needing to be addressed, but no fatal flaws,” according to Michael Istre, project director for the INGAA Foundation with 20 years of industry pipeline design experience. “We can fix everything in all the points [the study] identified, they are not out of the realm of the possible. It just takes the dedication and resources to do it.” 

Calling himself a third-generation pipeliner following in the footsteps of his father and grandfather from his roots in southern Louisiana, Istre outlined the focus of INGAA’s recent study that was completed by the North American-focused, Canadian-based engineering/contractor Mott MacDonald. First the study authors harvested and reviewed all hydrogen blending research that was applicable to high-pressure transmission pipelines, he said.  

“The issues are different once you get into high pressures and long distances. Hydrogen is something that we have been actively working to keep out of the pipelines for decades because it’s a small molecule that induces cracking in steel, and now we need to make this paradigm shift and work to include it,” Istre said. 

The key areas of the study were hydrogen properties (it is the smallest molecule on Earth), materials integrity, personnel/public safety, operations/maintenance, and storage. INGAA’s report looks at various options that are available for addressing these areas. Pieces of research and demonstration projects elsewhere – in the United States and Europe – examine various parts of the puzzle which is really aimed collectively at raising the “engineering comfort level” with hydrogen more widely, according to Istre. 

Conventional thinking among gas researchers considers hydrogen blending as well as 100% pure hydrogen delivery systems as key components of a sustainable energy policy and low-carbon future.  

Governments at all levels are planning or mandating the low-carbon transition to address climate change impacts that have become more evident worldwide. Businesses increasingly are supporting the increased production and consumption of hydrogen. “And pipelines are the most cost-effective way to transport H-2,” according to the Virginia-based Pipeline Research Council International (PRCI). 

Like other industry research groups, PRCI readily concedes there are challenges with combining hydrogen and natural gas.  

“The blending of H-2 at any concentration into the natural gas network will require actions to mitigate the impacts to pipelines, compressor stations, storage fields, and meters/regulator/valves,” PRCI noted. “The percentage of hydrogen in a pipe is not the key measure to consider. There is no established percentage that can be blended in an existing natural gas pipeline without first evaluating existing defects, partial pressure, pressure cycling, and the percentage of Specified Minimum Yield Strength (SMYS), all of which are critical for safe operations.” 

In recent years, PRCI has published a series of white papers covering hydrogen blending in existing natural gas pipelines, differences between blends and 100% H-2 lines, storage of H-2 and blends, safety, inspection and maintenance issues with blends, and end-user equipment issues with blends.  

“Industrial and residential end-use equipment fed from the natural gas grid may be a significant limiting factor in blending,” PRCI said. “The impacts from changes in gross caloric value [GCV, or heat value per unit in combustion] and other gas property changes [from blending] must be evaluated to verify that there are no significant adverse impacts.”  

Within DOE’s HyBlend effort, the National Renewable Energy Laboratory (NREL) is leading a collaborative R&D project that includes three other national laboratories – Sandia National Laboratories, Pacific Northwest National Laboratory, and Argonne National Laboratory, along with more than 30 partners from industry and academia.

A hydrogen pipeline to houses could become increasingly common.

Technical Requirements 

The report is assisting the development of models and analytic tools to evaluate the technical requirements of blending hydrogen. This was supposed to include the release of an “open-source natural gas pipeline upgrade tool” at the end of 2023. 

“The findings coming out of the national labs from this program are now being operationalized to help pipeline operators understand what the data means to their operations going forward,” said GTI Energy’s Lindsay, who notes there is publicly available data from the DOE efforts at the federal department’s HyBlend website.  

A S&P Global assessment in the fall of 2023 by Tom DiChristopher cited Argonne Lab reports that cast doubt about the efficacy of hydrogen blending, citing H-2’s tendency to increase pipeline leakage as a “limiting” factor. In Argonne’s modeling, blending 30% hydrogen by volume into gas pipelines yielded a relatively modest 6% decrease in lifecycle greenhouse gas (GHG) emissions, DiChristopher wrote in late October.  

“A major factor in Argonne's estimate was its finding that hydrogen blending at that level can double leakage from transmission lines,” he noted. 

Argonne said the lifecycle benefits of pipeline blending came chiefly from the lower emissions tied to hydrogen production and end-use combustion, according to S&P’s report.  

“However, injecting hydrogen into pipelines led to higher transmission and distribution emissions and greater energy demand in compressor stations, largely wiping out the upstream and downstream benefits,” the report stated. 

According to S&P, NREL has identified ways to overcome the inherent shortcomings, such as replacing pipe segments within sufficient design characteristics to carry hydrogen with pipes of the same diameter but appropriate upgrades in materials and wall thickness.  

Other mitigating options might include reducing system design pressure to a level consistent with the industry standard for hydrogen piping while increasing volumetric flow rates to meet the same end-use demand. 

As part of its research reports, NREL identified two approaches to reduce system design pressure to a level consistent with the industry standard for hydrogen piping while increasing volumetric flow rates to meet the same end-use energy demand. One is pipeline looping, or installing pipes that operate parallel to existing segments that do not align with the hydrogen piping standard. The second approach is to add compressor stations between segments that do not match the standard. These approaches both incur additional right-of-way costs, according to NREL reports. 

Alliance Example 

“In a case study assuming 327 miles of the Alliance Pipeline LP carried a 20% hydrogen blend, NREL found that pipeline looping was the most cost-effective approach,” according to NREL’s Kevin Topolski, a hydrogen infrastructure analyst. “Compared to direct pipe replacement, it required higher capital spending on compressors and more fuel expense. However, looping involved installing less pipe mileage. Adding compressors was substantially more expensive in this case.” 

NREL and other research organizations are unequivocal about the fact that hydrogen’s energy density is only a third that of natural gas, and it can cause a lot more leaks, but there are fixes with enough investments in money and time.  

NREL identified several approaches to overcoming a key constraint to hydrogen blending, namely the changes in maximum allowable operating pressures (MAOP) across segments of pipeline systems. Its modeling used the American Society of Mechanical Engineers' standard for hydrogen piping, which includes MAOP guidance for lines carrying the gas. 

In Canada, a group of researchers headed by Josmar Cristello, et al., published an assessment on hydrogen blending in the International Journal of Hydrogen Energy, underscoring the need for increased volumetric pipeline flows to compensate for H-2’s lower energy value: 

“One of the economically viable ways to transport and distribute hydrogen is by blending it with natural gas using the existing pipeline networks. However, it has been shown that blending hydrogen can reduce the energy [in] transmission of pipelines compared to natural gas. One potential solution is to increase the flow rate or pressure of delivery to compensate for these energy transmission losses, which may require changes to the pipeline or an increase in the number of compressor stations.” 

In addition to NREL’s work, there is a report, “Decarbonizing U.S. Gas Utilities,” by The McKinsey Company and a collaborative work involving GTI Energy, the Electric Power Research Institute (EPRI), and the Low Carbon Resources Initiative (LCRI). The latter examined integrated energy system scenarios by developing models for evaluating “alternative technology strategies for achieving economy-wide net-zero emissions of CO2 in the United States by 2050.”  

The study, as an expansion of past research, argues for a broad portfolio of clean energy technologies to permit an “affordable and reliable clean-energy transition.” 

As part of a published climate change discussion at Massachusetts Institute of Technology (MIT), Emre Gençer, a principal research scientist at the MIT Energy Initiative, indicated the envisioned expanded role for hydrogen in decarbonization was not just a matter of pushing more H-2 into existing pipelines. 

“Many companies have looked to the three million miles of natural gas pipelines as a potential transportation network, but the chemical properties of hydrogen will make that a challenge,” Gencer said. 

Hydrogen’s extremely small molecules mean it can “squeeze into tiny spaces in certain steel alloys in a way that natural gas cannot,” he said. “That can cause embrittlement, making the metal more likely to crack or corrode. Hydrogen molecules are also much more likely to leak from valves, seals, and other connection points on pipelines [risking undermining green hydrogen’s climate benefits by adding GHG emissions]. And hydrogen is transported in a more pressurized state than natural gas, which puts more stress on the pipeline carrying it.” 

Given the preponderance of research in recent years that both questions and endorses hydrogen, P&GJ turned to GTI Energy’s knowledgeable engineering and energy delivery expert, Tony Lindsay to interpret what is known, particularly concerning the limits for the percentage of hydrogen that can be safely blended into existing natural gas systems. 

“The answer can be approached from two different fronts – pipeline system limitations as well as end-use equipment and process limitations,” said Lindsay. “And in both cases, the answer is ‘it depends.’ The dependency of the pipeline system is on compatibility issues with the materials, as well as the methods of construction (welding procedures, mechanical joints, and field bends), operating conditions (temperature, pressure, flow, and other gas constituents), and performance of components (valves, compressors, odorizer, meters and regulators). 

European Effort 

One of the most critical [questions], yet most difficult to assess, is the current condition of the pipeline system already in service.  

“Operators need to have a baseline understanding of any anomalies, wall loss, corrosion, or stresses impacting the current in-situ pipeline/components in order to accurately assess the impact a change to the gas mixture will have going forward,” he said. 

Lindsay thinks the Europeans have done a good job in determining ideal percentages of hydrogen in gas blends and accelerating the prevalence of blended systems. He cites the HyDeploy Project in the United Kingdom. It examined hydrogen blending as part of an assessment of various ways that the amounts of carbon could be reduced coming from U.K. residences.  

Started in 2017 and completed in 2021, the final project report noted a “much greater focus” on hydrogen deployment taking off around the U.K. “Hydrogen deployment is now recognized as a central technological pillar of the U.K.’s decarbonization strategy with blending identified as the early enabler,” project officials wrote in mid-2021.  

“Our researchers at GTI Energy have done a significant amount of work looking at common appliances and end-use equipment in North America,” he said. 

“The basic physics differences in the pipeline movement of hydrogen and methane can’t be changed, but we are learning more about what it takes to deal with their differences in order to deliver the equivalent amount of energy to end-users,” Lindsay said. “Tools now are available and analysis has been completed to better quantify the full techno-economics of transporting energy at varying levels of decarbonization (or percentages of H-2).” 

Given all this, what is Lindsay’s assessment of the results so far of the accelerated global research push for hydrogen? Are blends workable and added end-uses plentiful enough? 

“I would characterize the ongoing global research and demonstrations as fast tracked, growing, and encouraging,” said the veteran gas engineering researcher.  

“This will come as no surprise, though – coming from a research organization [like GTI Energy] – but more research is still needed.”                                            

Richard Nemec is a contributing editor who writes frequently by P&GJ. He can be reached at rnemec@ca.rr.com.

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