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 diameter 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 netzero 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.
