September 2024, Vol. 251, No. 9
Features
From Crude to NGL: Understanding the Complexities of Pipeline Conversions
By Richard Nemec, Contributing Editor, North America
(P&GJ) – More than a year ago, Enterprise Products Partners LP decided the prolific Permian Basin in west Texas and southeast New Mexico was going to continue to grow and it had to grow its oil and natural gas products delivery footprint there accordingly.
One of the four major projects Enterprise executives targeted to come online by 2024 was the conversion of the 210,000 bpd Seminole Red crude oil pipeline to carry natural gas liquids (NGL).
This year, Seminole Red transports NGLs after carrying crude during 2019-2023 as either the Seminole Red Pipeline or the Midland-to-ECHO 2 crude oil line. And it is likely to be converted back to crude oil service again once Enterprise’s Bahia Pipeline is built. This is all part of Enterprise’s now year-old plan to expand Permian takeaway capacity. Service on Seminole Red was changed back to NGLs in December 2023.
Various industry analyses have indicated that based on expected Permian NGL production growth, along with the NGL production from the Rockies and San Juan Basin, the partial looping of the Shin Oak Pipeline that was once considered would not have provided sufficient capacity and would have resulted in higher long-term energy and operating costs.
Instead, Enterprise pursued the Bahia NGL pipeline, a 550-mile project with the capacity to transport up to 600,000 bpd of NGLs originating from the Delaware and Midland basins to Enterprise’s fractionation complex in Chambers County.
The pipeline will consist of a 24-inch segment from the Delaware Basin where it will connect to a 30-inch diameter segment from the Midland Basin to Chambers County. This pipeline, which is currently expected to be wholly owned by Enterprise, is projected to begin service in the first half of 2025.
Colorado-based East Daley Analytics has concluded that the Enterprise conversion is adding to the tightening of crude oil takeaway capacity in the Permian when production growth is booming in that basin.
“[The converted line] was originally used to transport NGLs out of the Permian when Enterprise converted the pipeline to crude service in early 2019. Shippers at the time had filled pipeline egress capacity, with spreads between Midland and ECHO2 [or Sealy] averaging nearly $10/bbl.
“Since then, developers have added more than 4 MMbpd of additional pipe capacity to the Gulf Coast, causing spreads to collapse. The Midland-ECHO differential averaged less than 25 cents/bbl in the third quarter of 023.Enterprise and its Permian crude pipeline competitors have been growing into the excess capacity, with current pipeline utilization sitting around 80%, according to East Daly’s ‘Crude Hub’ model.”
Conversions are also a part of other large midstream companies ongoing assessment of their future takeaway capacities and mixes of fuels. At the same time, there are mixed messages from the research sector’s assessments of switching pipeline fuels.
Critics see some real technical and economic challenges to conversions, but with oil and gas production continuing at robust levels, operators aren’t all being swayed away from at least considering more conversions.
In the fall of 2023, the federal Pipeline and Hazardous Materials Safety Administration (PHMSA) developed a list of research recommendations as the result of a public research and development forum to identify technology and knowledge gaps related to various pipeline safety topics including the state of repurposing energy pipelines.
Some of the best pipeline engineering minds in the industry participated in sessions. It was part of a broader effort by the federal agency to generate a national research agenda on pipeline safety and providing an information exchange among various public and private-sector stakeholders.
The workshop had a working group examine pipeline conversions to hydrogen (H2) and carbon dioxide (CO2), according to Tony Lindsay, managing director of energy delivery at GTI Energy. PHMSA made “Research Announcements (RA)” based on the workshop report, which are the federal safety agency’s version of an RFP, looking at about a dozen subjects they potentially could support withy cost-sharing funding.
Lindsay offered examples of RAs, dealing with (a) the development of pipeline system repair/maintenance technologies, (b) modeling analysis for potential impact radius (PIR) from pipeline breaks, and (c) assessing and preventing threats in conversion or repurposing.
The radius areas that could be impacted by a break in traditional oil, gas and gas liquids lines have been studied and modeled, but not necessarily for hydrogen, hydrogen blends and CO2 pipelines, Lindsay notes.
Separate from PHMSA’s recommendations, GTI Energy has identified possible other areas to investigate, including odorization methods, which would be totally new to hydrogen, for example.
‘Line of Defense’
“Our first line of defense in the natural gas stream is the odorant, but pure hydrogen has no odor,” Lindsay noted. “For hydrogen, to add one is possible, but the potential impacts on downstream end uses of gases generally is something that needs to be closely looked at.”
Lindsay cites the example of natural gas-based odorants’ having sulfur-based compounds that could not be used in a hydrogen fuel cell since odorant sulfur compounds would damage most fuel cells. “Other chemicals are being investigated that could be a suitable odorant,” Lindsay said.
In conversions, some companies have raised the issue of the need to examine impurities that potentially remain in a piping system after it switches to another fuel to transport. Things like heavy hydrocarbons that are not an issue in the old service could be significant for the new product being moved, Lindsay notes. “We’re concerned about impurities that remain and may add to problems with moving the new fuel,” he said.
Marathon Pipe Line LLC last year brought in Belleville, Illinois-based Farnsworth Group to provide the engineering and planning services for converting an idled 12-inch diameter products pipeline to carry crude oil as a means of allowing additional flexibility for shipping light crude to Patoka, Illinois, and the storage facility at Hartford Two Rivers Station.
Two Rivers was completely redesigned and Patoka’s Woodpat Station was expanded extensively, according to Farnsworth officials. A 1,200-foot-long, 20-inch diameter pipeline was installed in Hartford, Illinois, to connect Two Rivers to the existing crude source. Another 2,000-foot, 12-inch pipeline was installed in Patoka, Illinois, to connect with the downstream crude oil storage tank farm. It is an example of the considerable issues involved in reactivating and repurposing energy pipelines.
Three new, parallel flow meters with a sampling system were installed at Hartford and at Patoka/Woodpat to facilitate crude oil movements. Farnsworth also completed mechanical and structural design for one new 200-horsepower (hp) deep-well booster pump and two new 2,500-hp centrifugal pumps installed at Two Rivers. The project also included the evacuation and idling of a section of 12-inch products pipeline from Patoka to Lawrenceville in Illinois.
In late 20223, the Federal Energy Regulatory Commission (FERC) approved the Trailblazer Pipeline Co. LLC request to convert its 400-mile natural gas pipeline system to CO2 transportation.
Trailblazer told FERC that it intends to use the pipeline, which originally entered service in the 1980s to bring natural gas from constrained Rocky Mountain supply basins in Wyoming across Colorado and into Nebraska, to transport carbon dioxide from ethanol plants and other emissions sources in Nebraska and Colorado to Wyoming for permanent sequestration in geologic formations, naming it the Trailblazer Conversion Project.
In giving its approval, FERC acknowledged that it has no jurisdiction over the siting, construction, or operation of CO2 pipelines. However, Trailblazer required FERC’s authorization under Section 7(b) of the Natural Gas Act (NGA) before it could “abandon” natural gas service on its pipeline facilities.
The order also authorized Rockies Express Pipeline LLC (REX) under NGA section 7(c) to construct additional facilities and lease to Trailblazer existing capacity that will be used to continue service to Trailblazer’s natural gas transportation customers. Trailblazer also intends to contract for capacity on Tallgrass Interstate Gas Transmission, LLC (TIGT) to serve its firm customers. All three pipelines are operated by a subsidiary of Tallgrass Energy Partners.
Tallgrass Energy’s Trailblazer CO2 Pipeline LLC, in May held a binding open season for shipments on its proposed 10-mtpa Trailblazer Conversion Project. CO2 would be captured in Nebraska and shipped to eastern Wyoming for sequestration at a Denver-Julesburg (DJ) basin site being developed by Tallgrass.
As part of its overall work in carbon capture and storage (CCS) efforts, Tallgrass was awarded funding from the U.S. Department of Energy to study and design “commercial-scale carbon capture from a hydrogen-producing facility utilizing a novel autothermal reforming technology.”
Tallgrass officials say they are also pursuing investments in quality vetted carbon offsets for CO2 emissions from both its business administration functions and pipeline operations.
Washington, D.C.-based energy attorneys like Emily Matten, Stephen Hug and their colleagues noted after FERC’s approval of the Trailblazer project that CO2 pipeline transportation is still not prevalent in the United States, and until 2023 was typically used only to transport naturally occurring carbon dioxide for use in enhanced oil recovery.
“With advances in carbon capture and sequestration technology and decarbonization incentives created by markets and legislation like the federal Inflation Reduction Act, the need for a larger CO2 pipeline network is apparent,” the attorneys wrote. “However, because there is no federal permitting authority for CO2 pipelines akin to FERC’s NGA authority over natural gas pipelines, the authorizations to site, construct and operate new projects must occur on a state-by-state level.”
Technical Issues
Even with all this activity, there are informed skeptics such as Kenneth Medlock, the well-respected Rice University energy researcher who heads the Baker Public Policy Institute’s Center for Energy Studies, along with Rice’s energy economics programs in Houston. “The opportunities here are limited by technical and commercial issues,” Medlock told P&GJ.
One of the examples that Medlock and others often point to involves converting other fuel lines into a hydrogen pipeline, which has drawn a lot of study in recent years. In most cases, feasibility is limited due to steel embrittlement that H2 causes.
“Moving H2 derivatives, such as ammonia or methanol, on existing systems is a different matter,” Medlock notes. “[Nevertheless,] in all cases, a conversion would need to not impose logistical costs on the product being displaced and bring advantages for the product being developed.
“Given the diversity of customers and native demands along almost all pipelines for incumbent products, and the need for customers to all also switch to the H2 derivative products, the commercial case for this is challenged, at least in the medium to short term,” said Medlock, who is a senior director of the energy center and a director/master of economics at Rice.
He emphasizes that it is not just about the cost of converting the pipeline; but also about the cost of converting end-uses.
“Most analysis does not consider the full scope of what conversion means. Of course, there are always special cases, but those do not represent the entirety of energy transition,” Medlock said.
He acknowledges that in the long term, conversions may be more possible, he wants to see more “significant market expansion” before it can be commercially viable.
An official with the Interstate Natural Gas Association of American (INGAA) indicates the national trade group for interstate gas pipeline operators has not developed a policy on conversions, but a number of its individual members are “exploring the potential” to transport alternative fuels through parts of the U.S. gas system.
Shortly after the PHMSA report and workshop, GTI Energy published a broader white paper on U.S. gas infrastructure “evolving toward a net-zero emissions future” through a collaboration called NZIP. The paper’s scope covers pipe repurposing as one of many areas needing to be addressed in seeking a net-zero carbon emissions world. The white paper called for a more “holistic understanding” of the role of gas infrastructure in a net-zero energy world beyond 2050.
“With a highly segmented and diverse range of gas infrastructure, a comprehensive analysis of the current infrastructure is necessary to identify areas that need upgrading, repurposing, retirement, or replacement to achieve full-scale decarbonization,” an abstract of the GTI report noted.
GTI’s Lindsay echoes this observation in summarizing the outlook for conversions, noting that the inherent complexity and redundancy of the overall U.S. natural gas pipeline system is a major inhibitor...” This creates a complexity and interdependency that works against conversions.
“I don’t think we will see broad changes because we either won’t be able to resolve all the risk uncertainties or the fact that the North American system is so highly interconnected and networked,” Lindsay said. “We have done a great job in North America to backfeed and cross-connect portions of our natural gas pipeline grid to create resiliency.”
Also, late last year, the National Renewable Energy Laboratory (NREL) developed sort of an engineer’s tool for conversions involving fuel blending. It is called the Pipeline Preparation Cost Analysis Tool (PPCT) and is designed to estimate the system cost of blended hydrogen conversions on a case-by-case basis.
PPCT is aimed at providing users with the ability to identify potential system upgrades needed to blend various specified proportions of hydrogen with natural gas and to estimate the various capital and operating expenses associated with each level of blending, according to NREL’s report.
It also allows for determining the economic impact of applying design options and modification. For technical guidance on the proper steps to take to evaluate an existing pipeline for suitability for hydrogen service, the national mechanical engineering standards (31.12) from the American Society of Mechanical Engineering (ASME) can be referred to.
ASME underpins the practice of pipeline conversions in its standards for the industry that provide technical guidance on repurposing of pipelines. This is the closest thing the gas industry has to an “engineer’s checklist,” Lindsay noted.
“It allows for two different methods for qualifying a pipeline for conversion,” Lindsay said. “And that largely boils down to the amount of verifiable data, condition information, and records that are available on the existing pipeline in question so it is possible to complete a risk assessment with confidence the line can be repurposed. If you lack adequate records, the ASME standard provides a second method outlining a series of physical inspections to support the feasibility of repurposing.”
Ultimately, the conclusions reached by many pipeline engineers like Lindsay after applying the ASME standard include a realization that the maximum allowable operating pressures (MAOP) will have to be reduced in order to maintain the same operating safety margins in place with natural gas. With conversions, there is often a need to reduce the level of stress that new operations are putting on a given pipeline.
“Because of the action of smaller hydrogen molecules on steel, for example, we want to get into a safer zone, or lower percentage slice we operate in,” Lindsay said. “Since you’re not going to be able to increase the strength or thickness of the pipeline wall, your only option is to reduce the pressure.”
In North America, industry operators are considering liquid to gas and vice versa, conversions. A lot of the ongoing discussions and calculations relate to conversions for gas lines to hydrogen and some other analyses are relevant to CO2. GTI’s Lindsay thinks the ultimate conversions completed will be “selective and not widespread” because of limitations of uncertainties about pipeline conditions and characteristics.
“Another factor working against conversions is the need for underground storage. Converting some lines could conceivably impact the ability to use storage supplies to meet season demand increases.”
Conversions going forward are likely to be “strategic, selective plays,” Lindsay said.
Richard Nemec is a long-time contributing editor to P&GJ, based in Los Angeles. He can be contacted at rnemec@ca.rr.com.
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