Natural CO2 Source Fields

This article is part of the Global Fossil Infrastructure Tracker, a project of Global Energy Monitor.

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McElmo Dome in Colorado. Credit: Purdue University

Natural CO2 Source Fields are reservoirs of carbon, akin to natural gas (methane), which can be drilled out of ground using techniques similar to oil and natural gas.

The carbon produced at those fields is used to facilitate Carbon Capture Utilization and Storage (CCUS), the "U" in which is mostly used as an injectant to facilitate more oil production. That process is called CO2 enhanced oil recovery (CO2 EOR). Until 2012, CCUS was known as Carbon Capture and Storage (CCS), but CO2 EOR was rebranded as CCUS that year by the oil industry and the Obama Administration. Doing CO2 EOR forces out 8-20% more of the original oil in place out of the well. Doing so can extend the lifeline of an oil well for an additional 20-25 years or more.

The United States is the epicenter of both drilling for CO2 and CO2 EOR production and 97% of the industrial marketed carbon is used for CO2 EOR. It is the only place in the world where commercial-scale CO2 drilling is occurring, predominantly located in the southwest, with active commercial production sites located in Colorado and New Mexico. Mississippi is also a major production hub for CO2. Other sites with potential commercial production, identified by the U.S. Department of Energy, include Utah, California, Arizona, Ohio, Montana, and Wyoming.

Natural carbon dioxide is currently the source of over 80% of the CO2 for CO2 EOR in the United States and CO2 EOR currently is the final carbon sink for nine of the ten biggest U.S.-based Carbon Capture and Storage (CCS) projects currently commercially operational. The vast majority of the rest of the CO2 used to do CO2 EOR comes from natural gas plants in Wyoming and Texas in which CO2 is produced as a by-product.

United States CO2 from natural sources map. Credit: U.S. Department of Energy

CO2 EOR and CCUS primarily is a regional market today, with major markets in Texas' Permian Basin and the Houston Metro Area, Mississippi, Louisiana, Montana, and Wyoming. The Permian Basin is by far the biggest CO2 EOR field and Occidental is the top CO2 EOR driller there. Current commercially productive fields include the Jackson Dome in Mississippi, Bravo Dome in New Mexico, McElmo Dome in Colorado, Doe Canyon in Colorado, and Sheep Mountain in Colorado.

A 2020 academic study concluded that CO2 enhanced oil recovery using CO2 source fields like the Jackson Dome, McElmo Dome, Bravo Dome, Sheep Mountain, and Doe Canyon “cannot contribute to reductions in anthropogenic CO2 emissions into the atmosphere.” A study the year before, published by the U.S. Department of Energy echoed that conclusion, writing that CO2 production for CO2 EOR "does not contribute towards a net reduction in CO2 emissions to the atmosphere."

Multiple studies have also called into question the climate benefits of CO2 EOR production even with anthropogenic carbon, pointing to the process as a net-positive greenhouse gas emitting process.

Comparison to Oil, Gas Drilling

An industry engineer told the outlet Capital & Main that CO2 drilling is akin to drilling for oil and gas, at its core.

“It’s really the same tools, the same equipment, the same calculation going on. It’s just using different types of numbers,” the engineer stated. “But you find a CO2 source field, which obviously can be several thousand feet underground, and you move a drilling rig in and you drill for it.”

Present and Future of CO2 Drilling

In 2020, there were 10.05 TCF of production from the CO2 source fields taking place on an annual basis. The most productive field is the McElmo Dome, which produced 2.7 TCF in 2020. The second most is the Jackson Dome, at 1.1 TCF in 2020. Third is Bravo Dome at 1.1 TCF in 2020.

Yet, under most estimates, CO2 sources are slated to run dry at or before mid-century. This has moved the U.S. Department of Energy, and contracting consultancies doing research on its behalf, to examine not only other untapped known CO2 sources beyond the five currently commercially producing fields. But in addition, CO2 found that may exist in still undiscovered reserves, as well.

"Most if not all the subsurface accumulations of CO2 in the United States were discovered unintentionally during exploration operations aimed at finding hydrocarbon resources," explains a 2019 U.S. Department of Energy study. "The science of exploration for CO2 is immature compared to that of exploration for hydrocarbons and CO2 has characteristics that make the search for it different."

Preparing for the inevitability of CO2 eventually running dry in the current commercially active fields, the National Energy Technology Laboratory (NETL) has begun plotting other potential production sites.

In a 2014 report, NETL documented 21 prospective CO2 source fields containing 311 trillion cubic feet of CO2. About half of it, the agency concluded, is “accessible and technically recoverable” and 71% of that CO2 sits in Colorado, Wyoming, and Utah. Outside of the already commercially productive CO2 fields, that leaves an additional 76 trillion cubic feet of CO2 for industrial uses.

Discovered CO2 source fields chart, statistics. Source: U.S. Department of Energy

Discovered CO2 deposits map. Credit: U.S. Department of Energy

Volume two of that report, also published in 2014 by NETL, maps out the potential for natural CO2 sources elsewhere domestically. The study concluded that geological trends point to the fact that CO2 is likely located along “linear belts or fairways” which extend from CO2 sources already discovered by scientists.

Thus, the study points to “leads” where other CO2 basins likely exist along that geographic demarcation. The biggest lead, the paper concludes, is in New Mexico.

Mapped out potential untapped CO2 source field deposits in the United States. Credit: U.S. Department of Energy

In total, NETL pointed to 26 leads in five different geographic regions, a swath of territory estimated to have over 100 additional cubic feet of carbon. The study concludes that “there are likely undiscovered CO2 reservoirs in the United States of a magnitude that could contribute materially to CO2 supply for EOR.”

South of the border, another 2007 scholarly paper by scientists from Mexican state-owned oil and gas company Pemex and oil and gas services company Schlumberger has pointed to the potential for commercial CO2 source extraction at a field called Quebrache, as well.

History

The CO2 at the Bravo Dome was first discovered by accident in 1916 in a search for oil by prospectors in New Mexico. At the time, it was known then as the Bueyeros Field.

Bueyeros Field map. Credit: New Mexico Institute of Mining and Technology

By 1931, the first CO2 wells were drilled in New Mexico for the manufacture of dry ice and the first pipeline was constructed in 1932. The Harding County portion of the Bravo Dome was discovered in 1935. In its early years, the Bravo Dome CO2 was used in fire extinguishers, carbonated water and beverages, and as a food preservative.

"The principal use of solid carbon dioxide, or dry ice, is as a refrigerant. It is especially useful in the long-distance shipment of fruits, vegetables, flowers, chemicals, and medicines," explains a 1959 report published by the New Mexico Institute of Mining and Technology. "Pound for pound, it is from 10 to 15 times as effective as water ice for these purposes, and it is much less bulky."

Witt Ice and Gas Co. Plant near Bueyeros Field. Credit: New Mexico Institute of Mining and Technology

"In recent years, large quantities of dry ice have been and are being used by research laboratories where precise temperature control is necessary," the report continued. "The biggest market for ice produced in New Mexico, reportedly, is with the White Sands Missile Range, Holloman Air Force Base, Sandia Base, and Los Alamos laboratory."

As of 1942, there were 26 commercial CO2 wells in New Mexico. By 1958, Bueyeros Field had 11 operational CO2 wells and the product moved to market via truck or rail.

CO2 EOR is a process first patented in 1952 by Atlantic Refining Company, with the patent titled, "Method for Producing Oil by Means of Carbon Dioxide." In those two decades between 1952 and the first commercial CO2 EOR project in the Permian Basin beginning in 1972, multiple methods of enhanced oil recovery took place. But the first test well for CO2 EOR actually took place in 1951, though with carbonated dry ice, and not pure CO2.

The 1952 patent puts it simply in explaining the goal behind CO2 EOR production: the "object of this invention is to provide an improved method for producing from an oil reservoir whereby a greater amount of oil may be recovered than otherwise might be recovered by previously known methods of" drilling.

Prior to deciding upon CO2 EOR, the oil industry also attempted to use both liquefied petroleum gas (LPG), flue gas, and nitrogen as underground injectants to free up more oil. In 1960, fire-induced enhanced oil recovery was even on the table as a potential solution to free up oil by a research team at Texas A&M University.

LPG EOR pioneers in the 1950's included Mobil, Continental Oil (predecessor to Conoco), and Standard Oil’s Pan American Petroleum Corp. At one point, in West Texas, 7,300 barrels of propane per day were being injected into the field at depths of over 10,000 feet underground to attempt to free up more oil by the company El Paso Natural Gas, now a subsidiary of Kinder Morgan. From 1956-1958, Continental Oil injected 72,000 barrels of LPG into a Wyoming oil field. But the LPG injectant was only able to achieve an 8% volumetric coverage of the oil well when pummeled under the ground, far short of the projected 100% projected coverage range.

In 1959, there were 39 projects in seven states for LPG EOR within 24 different oil fields. The states included Texas, Oklahoma, California, Louisiana, Wyoming, New Mexico, and Nebraska. In 1966, the American Petroleum Corporation obtained a patent from the U.S. Patent Office to do LPG EOR.

Yet just before the CO2 EOR boom began in 1972 at SACROC, LPG EOR was deemed uneconomic and that era came to a close. During this era, the industry called the insertion of LPG into oil wells as a means of doing EOR “health injections,” shorthand nomenclature standing for the long-term economic health of the fields and ability to pull oil from the ground. Some even thought it could mean 100% oil recovery, but the dream never came true either for LPG EOR or for CO2 EOR.

1958 sketch of LPG EOR. Credit: The Odessa American

For flue gas EOR, Atlantic Richfield (ARCO) was an industry leader at attempting to use the drilling technique, building an 8-acre site in the Permian Basin in the 1960's. At its prime, ARCO had 97 flue gas EOR wells in the field and engineers "estimated another 30 years of production from the field with 60 per cent recovery," according to a 1966 article published by The Odessa American. The paper also described the "flue gas acting like a ram pushing the oil and gas out ahead of it."

Nitrogen EOR was also taken under consideration in the 1970's at Texas A&M University. CO2 eventually won out, though, as the key commodity needed for chemically-aided enhanced oil recovery.

During its early days, promoters of CO2 EOR referred to it as a “third crop” of oil drilling after conventional and water flooding. Some promoters also used the “born again” descriptor. CO2 EOR, did in fact help to revive oil fields. Things were looking so bleak that by 1981 for the future of domestic oil production in the United States that The New York Times declared that "King Oil is dying [a] slow, agonizing death in Texas" in a headline. That is, until CO2 EOR hit wide commercialization within a few years thereafter.

In 1970, Chevron sent a seismic shift through the industry in announcing a plan to pour $175 million into CO2 EOR at the Scurry Area Canyon Reef Operators (SACROC). A year later, it announced it would build a 220-mile pipeline for the same amount of money. By 1972, CO2 EOR had arrived on the scene at a field named SACROC and LPG EOR was a thing of the past, as was water flooding at the field, which until that point was a process that involved injecting over 500 million barrels of water into the field in the aim to enhance oil recovery. In industry lingo, doing CO2 EOR at SACROC was called “conservation” of the oil, a means to procure more oil and not let it go to waste. CO2 utilized for CO2 EOR at SACROC originally came from the Vel Verde gas plant. The Texas Railroad Commission was first approached about the idea of doing CO2 EOR at SACROC in 1969 by Standard Oil.

1972 ribbon-cutting photo-op at SACROC field. Credit: Lubbock Avalanche-Journal

In 1976, The Railroad Commission of Texas further opened up the flood gates on CO2 EOR by giving Shell a test pilot permit at the 25,000-acre Denver Unit at the Wasson Oil Field. In seeking that pilot permit, the company told the agency it will ultimately produce 700 billion barrels of crude in the field. The company further stated that only the unitization of the field could make CO2 EOR profitable. At the time, Shell received its CO2 by truck at a rate of 100 tons each day for 100 straight days from the company SEC Corp. Trucking was the initial mainstay way to bring CO2 to market before the era of CO2 pipelines began.

Denver City, Texas would proceed to become a key national hub of CO2 EOR production, fueled by CO2 from the McElmo Dome, and Shell would spend $3.5 billion in its aims to commercialize CO2 EOR at the field.

Concurrently that year, the U.S. Department of Energy's National Petroleum Council published a report exploring the commercial prospects for CO2 EOR and other versions of EOR. Its lead authors included senior officials from Standard Oil, ARCO, Chevron, and the American Petroleum Institute, as well as an independent oil company executive.

"The most plausible source of adequate volumes of CO2, at a cost low enough for carbon dioxide flooding appears to be from either existing known and undeveloped sources of naturally oc­curring CO2, or from future such discoveries," that report declared.

By 1977, with the prospect of a CO2 production boom looming, the Caspar Star-Tribune had shifted from seeing carbon as from "useless and something of a nuisance" into "helping to overcome the energy shortfall." In 1980, Amoco (at the time owned by Standard Oil) launched the world’s largest CO2 EOR regime for $1.5B, with a goal of procuring “several hundred million barrels” of crude with the method. The then-looming Bravo Dome and the CO2 produced there would be the epicenter in that plan, also leased out and produced during those formative days by Amoco. Then in 1980, Amoco (at the time owned by Standard Oil) launched the world’s largest CO2 EOR regime for $1.5B, with a goal of procuring “several hundred million barrels” of crude with the method. The then-looming Bravo Dome and the CO2 produced there would be the epicenter in that plan, also leased out and produced during those formative days by Amoco.

"What we're talking about is the virtual rediscovery of these fields from a reserve growth viewpoint," Earl Morris, then the production manager for the company, told a local Chamber of Commerce at the time.

CO2 production became commercial at the Bravo Dome for Shell Oil's CO2 unit in 1983 after the finalization of the joint pooling agreement among landowners and the building of the Cortez Pipeline, which signed a contract in 1982 to ship oil to the Denver Unit CO2 EOR field in Denver City, Texas. Cortez Pipeline, when created, was a joint venture between Continental Resources, Shell, and Mobil. In 1980, the U.S. Bureau of Land Management approved a right-of-way for 100 miles of public lands for what would become the Cortez Pipeline.

In 1981, CO2 EOR production also began in New Mexico's sliver of the Permian Basin, in a pilot project operated by Conoco. With the development of the McElmo Dome, Bravo Dome, Sheep Mountain, and Doe Canyon, the Permian by the mid-1990's—and into the present—became the global epicenter for CO2 EOR production. With the prospect of CO2 EOR boom on the horizon in the early-1980’s, the industry promoters saw the burgeoning technology as an Arab oil embargo panacea and viewed Denver City, Texas increasingly as the “Carbon Dioxide Capital of the World.”

Permian CO2 EOR market w/ pipelines mapped. Credit: U.S. Department of Energy

Early Tax Incentives

The early days of CO2 EOR were bolstered by the Crude Oil Windfall Tax Act of 1980, which offered windfall tax repireve for injecting CO2 underground.

"A tertiary project will not be certified for purposes of the windfall profit tax unless it is shown to be in accordance with sound engineering principles and is expected to result in more than an insignificant increase in production," explained a 1981 paper by the firm Touche Ross & Co., now known as Deloitte.

Tertiary production tax discount in Crude Oil Windfall Profit Tax of 1979. Credit: Congressional Research Service

The receipt of the windfall tax came as the Oil & Gas Journal noted in 1978 that the economics of scale for CO2 EOR might very well not work for scaling up the technology, according to those in the industry that the publication had surveyed, who were practicing that niche form of oil drilling at the time.

"The weekly trade magazine says costs are monstrous and risks are high for enhanced recovery techniques," The Daily Oklahoman explained of the trade journal's findings. "Compounding the problem are the long lead times and corresponding expenditures requried in nearly every enhanced-recovery project as producers try to choose the most efficient recovery method for each reservoir."

That same year, an ARCO oil executive said at a July 1978 congressional hearing that "under current domestic oil price policy, except for a small amount of thermal oil, essentially no enhanced recovery oil will ever be produced.”

"Welcome to Denver City" sign at dawn of CO2 EOR boom in Denver City, TX in 1981. The field is the largest CO2 EOR production site in the world, now operated by Occidental and previously Shell. Credit: The Odessa American

Shell stated that the Crude Oil Windfall Profit Tax Act of 1980 helped to get the Denver Unit off the ground, the largest CO2 EOR field on planet, now owned by Occidental.

Above-ground view in 1981 of the Denver Unit CO2 EOR production field in Denver City, TX. It's the largest CO2 EOR field in the world, formerly operated by Shell and now operated by Occidental. Credit: The Odessa American

The state and federal government also heavily financed CO2 EOR research and development work in its early years.

1982 Sheep Mountain CO2 Release

In 1982, the Sheep Mountain CO2 field was the source of one of the largest CO2 leakages and the largest recorded industrial release of the chemical compound in human history.

According to a 1985 paper written by engineers employed by ARCO, who operated the field at the time of the release, during the week-long period that the CO2 well on site spewed carbon, it did so in a formation that was “softball-sized" and went "hundreds of feet into the air.” A 2007 science paper discussing the well blowout further detailed that “on one of the first mornings of the blowout period[,] a car engine stopped when being driven through a low spot on the way to the drillsite.” It took an additional nearly two weeks to fully contain the massive leak.

Worried about the possibility of future mass CO2 leakage events, residents formed a group called Huerfano Valley Citizens Alliance to act as a community industry watchdog.

No Accounting for Greenhouse Gas Emissions

CO2 fields disclose their production levels under Subpart PP of the U.S. Environmental Protection Agency (EPA)'s Greenhouse Gas Reporting Rule, which is a self-reporting mechanism. As a CO2 producer under that subpart, the company must only report its production levels and not its emissions under the statute.

The operative language of Subpart PP of the Mandatory Greenhouse Gas Reporting statute reads, "The owner or operator of a CO2 production well facility must maintain quarterly records of the mass flow or volumetric flow of the extracted or transferred CO2 stream and concentration and density if volumetric flow meters are used."

CO2 enhanced oil recovery wells, a key component of Carbon Capture Utilization and Storage, also must report emissions generated via the production activity under the Greenhouse Gas Reporting Rule via Subpart UU of the Mandatory Greenhouse Gas Reporting statute. But it is assumed as a carbon storage mechanism and no companies self-report emissions as part of that process.

The CO2 EOR wells linked to the Bravo Dome report zero emissions, despite numerous scientific studies pointing to contrary evidence.

Climate, Air Quality Impacts

Multiple studies have pointed to the climate change impacts of beefing up CO2 enhanced oil recovery. They come with the backdrop of a 2019 U.S. Department of Energy report concluding that there has been "no official mechanism for reporting leaks" of CO2 for most of the history of CO2 EOR production. "In addition, little information is available on project post-closure status and CO2 behavior in the subsurface post-injection," the report continues.

A 2019 study published in the journal Applied Energy concludes that "from [a] thermodynamics point of view, CO2 enhanced oil recovery (EOR) with CCS option is not sustainable, i.e., during the life cycle of the process more energy is consumed than the energy produced from oil."

A decade earlier, another study came to the same conclusion: CO2 EOR is a carbon-positive emissions drilling process. That paper, published by researchers at Carnegie Mellon University in the journal Environmental Science & Technology, surmised that “without displacement of a carbon intensive energy source, CO2-EOR systems will result in net carbon emissions.”

"We calculated that between 3.7 and 4.7 metric tons of CO2 are emitted for every metric ton of CO2 injected. The fields currently inject and sequester less than 0.2 metric tons of CO2 per bbl of oil produced," the researchers further detailed. "In order to entirely offset system emissions, e.g., making the net CO2 emissions zero, 0.62 metric tons of CO2 would need to be injected and permanently sequestered for every bbl of oil produced. The only way to sequester this amount of CO2 would be to operate a sequestration project concurrently with the CO2-EOR project."

In 2020, researchers June Sekera and Andreas Lichtenberger came to similar summations in doing a survey of over 200 studies done on Carbon Capture Utilization and Storage to date with regards to greenhouse gas emissions in their paper titled, "Assessing Carbon Capture: Public Policy, Science, and Societal Need: A Review of the Literature on Industrial Carbon Removal."

"We found that papers that deem CCS-EOR to be a climate mitigation technique either fail to account for all emissions (i.e., they perform only a partial life cycle analysis) and/or they make an assumption that CCS-EOR-produced oil 'displaces' conventionally produced fossil fuel energy," they wrote, surmising instead that "data show that the process actually results in net emissions."

U.S. Environmental Protection Agency data further shows that at the CO2 treatment facilities servicing some of the major CO2 EOR fields at Texas' Permian Basin, the facilities emit high levels of carbon dioxide and other copollutants into the atmosphere.

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One of them, the SACROC CO2 treatment facility servicing the SACROC CO2 EOR field -- operated by Kinder Morgan Energy Partners -- emitted 425,971.5 metric tons of CO2 into the atmosphere in 2019. That amounts to 92,640 passenger vehicles driven for a year and 77,375 homes' electricity use for one year, according to the EPA's Greenhouse Gas Equivalencies Calculator. The SACROC facility also emits high levels of PM 10, VOCs, ammonia, PM 2.5, carbon monoxide, formaldehyde, methane, NOx, and sulfur dioxide, according to EPA pollution data.

The Denver Unit and Wasson CO2 removal plans, both of which service the Denver Unit CO2 EOR field, also emitted a total of 153,035.7 metric tons of CO2 into the atmosphere in 2019. That equates to 33,282 passenger vehicles driven for one year and 27,798 homes' electricity use for one year.

Occidental's Denver City CO2 removal plant in Denver City, Texas. Credit: Google Maps.

The Denver Unit CO2 removal plant also emits high levels of sulfur dioxide, nitrogen oxides, carbon monoxide, as well as PM 2.5 and PM 10, according to the EPA Air Pollutant Report for the facility. The separation facility is located within three miles of over 5,100 people, 66% of whom are people of color and over 75% of whom have a family income of below $75,000 per year. Only just above 15% of the population in that 3-mile radius has a college degree and 63% of the population in that radius has a Latinx ethnic origin.

Denver City CO2 removal plant next to oil rigs. Photo Credit: Google Maps

According to Texas Center on Environmental Quality data, the Wasson CO2 Removal Plant owned by Occidental also emitted 19,312 pounds of carbon monoxide via designated illegal air pollution incidents into the atmosphere between January 1, 2020 and February 24, 2021. The facility also emitted over 3,400 pounds of H2S; over 15,700 pounds of non-methane, non-ethane natural gas; over 2,250 pounds of oxides of nitrogen; and over 314,000 pounds of sulfur dioxide

Between January 2020 and March 14, 2021, Occidental's Anton CO2 dehydration plant in Shallowater, Texas had 11,800 pounds of carbon monoxide incidents, 637 pounds of H2S; over 9,200 pounds of non-methane, non-ethane natural gas; and over 56,300 pounds of SO2, and 1,672 pounds of NOx.

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And between June 2020 through January 2021, the company's Denver Unit CO2 Recovery Plant had incident events which emitted over 40,400 pounds of carbon monoxide into the atmosphere, more than 65 pounds of H2S, over 23,200 pounds of non-methane/non-ethane natural gas, over 5,000 pounds of NOx, and over 6,000 pounds of SO2.

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Three of the company's CO2 processing plants sit within the top ten most polluting facilities in Texas when ranked by SO2 emissions, according to a 2020 report by the group Environment Texas, when ranked by illegal air pollution events. They include the West Seminole San Andres Unit CO2 facilities, the Seminole Gas Processing Plant, and the Willard CO2 Separation Plant. But when measuring all co-pollutants, five of the top six polluters in the TCEQ's Region 2 (Lubbock) are CO2 separation/removal/recovery plants.

Top 10 polluters for TCEQ Region 2. Credit: Environment Texas

Willard CO2 Plant in Denver City, Texas. Credit: Google Maps

The main Permian-area gas plants which create carbon as a by-product, thusly used for CO2 EOR production, are also highly polluting, according to U.S. Environmental Protection Agency (EPA) data.

The Pikes Peak Gas Plant -- located in Fort Stockton, Texas and operated by Occidental -- is in the 87.8 percentile for PM 2.5 emitted into the atmosphere, 92.7 percentile for ozone, 86.1 for other air toxics, and on the 83.9 percentile for respiratory hazard index. The plant also emits high levels of benzene, formaldehyde, toluene, carbon monoxide, ethylbenzene, xylene, VOCs, hexane and climate change-causing CO2 into the atmosphere, according to other EPA data.

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The Terrell Gas Plant in Sheffield, Texas shows similar attributes, sitting in the 68.9 percentile for PM 2.5, 70.3 for ozone, 67.8 for air toxics cancer risk, and 66.7 for respiratory hazard index. Like Pikes Peak, the plant is operated by Occidental. The facility also emits high levels of VOCs, formaldehyde, CO2, methane, toluene, acetaldehyde, benzene, carbon monoxide, PM 2.5, acrolein, SO2, hexane, methanol, and NOx into the atmosphere. Greenhouse gas emissions data from the EPA shows that the facility emitted 50,011 metric tons of CO2 into the atmosphere in 2019.

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Beyond Texas, at Denbury's Bogue Chitto, Mississippi's CO2 EOR site, the company emits high levels of nitrogen oxides (NOx), hexane, carbon monoxide, VOCs, benzene, formaldehyde, and PM 2.5, according to U.S. Environmental Protection Agency data.

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Southeast Regional Carbon Sequestration Partnership

Denbury participated in the U.S. Department of Energy's Southeast Regional Carbon Sequestration Partnership, which monitored the Carbon Capture Utilization and Storage and CO2 enhanced oil recovery effectiveness of the CO2 injection process at the Cranfield oil field in Natchez, Mississippi. The science experiment, though, did not measure CO2 emissions from the Jackson Dome, even though the origin point of the CO2 came from the field.

According to an April 2020 story published by the outlet Capital & Main, the U.S. Environmental Protection Agency "has not brought any enforcement actions against any companies in [the] carbon drilling space."

Local Economic Dependence

CO2 source fields are located in, without exception, areas with low population levels and thus a non-robust tax base. As such, carbon production consists of a large portion of budget levels in these counties.

The County Assessor's Office for Dolores County, Colorado told Global Energy Monitor that "64% of our revenue comes from CO2 production" via the Doe Canyon CO2 source field as of 2020. As of 2020, Montezuma County, Colorado -- home of the McElmo Dome CO2 source field -- gets over half of its tax revenue from CO2 drilling, according to Assessor's Office data.

A 2007 article by The Denver Post notes that Huerfano County -- home of the Sheep Mountain CO2 source field -- is nervous about what will come next for raising tax revenue in the county with a population of 6,897.

"Services have been cut back, notably in the sheriff’s department, where six deputies represent half the staffing level of the 1980s," reported The Post. The boom-to-bust scenario is reminiscent of earlier in the 20th century when Huerfano County was a coal-mining center and its population burgeoned to 17,000 in the 1930s."

The Post reported that 30% of the county's tax base came from CO2 extraction at the time the article was published and at its peak, it was 50% of the county's tax base. But the Huerfano County Assessor's Office has told Global Energy Monitor that drilling for CO2 at Sheep Mountain now consists of only 1.67% of its tax base as of 2020, with the level of drilling down.

In Union County, New Mexico -- home of the Bravo Dome CO2 source field -- more than 20% of tax revenues stems from the Bravo Dome. Harding County, New Mexico gets 70-80% of its tax dollars from the Bravo Dome.

McElmo Dome, Doe Canyon Community Impacts

The communities located near the McElmo Dome and Doe Canyon have documented many complaints against Kinder Morgan Energy Partners. Those include noise complaints about the Yellow Jacket Compressor Station and growth of community CO2 assets, local road damage, grievances about power lines on agricultural properties, and the sensing of foul-smelling odors which have led to public health impacts.

Yellow Jacket Compressor Station shown in presentation given by Kinder Morgan Energy Partners in 2014 presentation. Credit: Montezuma County Board of Commissioners

“I woke up with a headache, and could hear a constant roar from a well a mile away,” one resident said of public health concerns to a local media outlet. “Gas poured into our ravine, and my 90-year old mother-in-law breathed it in.”

“I can hear it all day and all night right now,” another resident told the same local media outlet. “If you could make the noise go away, that would be nice.”

“There’s no peace of mind when you go out to have a cup of coffee in the morning,” another source told a local independent media outlet. “The noise is 24/7. They shut that plant down maybe three times a year.” The source added that once the compressor station arrived nearby, "our house started vibrating."

Others told that outlet that once the compressor opened for business, they began "experiencing headaches, nose bleeds and sore throats."

Residents have also filed complaints with the state about those issues.

"I often smell an 'industrial gas' smell around this county. It's new in the last 3 yrs," reads one of those complaints, filed with the Colorado Oil and Gas Conservation Commission about the Cow Canyon Compressor Station in the McElmo Dome. "Alot (sic) of people seem to be experiencing sinus conditions that last several wks. at a time and or get sick in the summer. There's a constant greenish/brown haze on the southern and western horizons, when the wind's not blowing."

Another resident said that same compressor station often sounds "like a jet engine."

"Then 4 seconds of silence. Repeat. I could see a white plume coming from 2 stacks, going at least as high as the stacks are high," reads that complaint. "What was being vented? Did they even report this? Kinder Morgan has a reputation for releasing all sorts of gas into the air... sometimes really nasty gas. Any release concerns me."

That complainant, Gala Pock, was several years earlier booted from the Montezuma County Planning and Zoning Board for disputing CO2 pipeline permits and speaking out against the company. After telling a company representative to "Go to hell" at a Board meeting, during debate over a pipeline, she received a letter telling her she had been removed from the Board.

Kinder Morgan also said at a county Board of Commissioners meeting in 2014, of requested duties to pay $1.5 million for local roads by Montezuma County residents who said its trucks had destroyed, that “We're here to make money" and paying for such roads would hinder those ambitions. "We've paid enough. We're being treated unfairly," the company's regulatory manager stated.

The company also filed a lawsuit against the county for its request to build powerlines underground, instead of above ground, which farmers said would drop the value of their land in the area. Kinder Morgan would eventually drop the lawsuit.

In 2014, a local farmer said of this debate over where to lay the powerline that “The area is becoming a chokepoint for pipelines, powerlines, and irrigation...Commercial agriculture here is a huge part of the economy. My fear is that agriculture will die from 1,000 cuts.”

CO2 Pipelines, Regulation

There are 5,000 miles of CO2 pipelines in the U.S. Most of those pipelines connect to CO2 source fields. This compares to over 535,000 miles of hazardous liquid pipelines (predominantly crude oil and oil condensate) and 2.2 million miles of natural gas lines.

Unlike oil and gas pipelines, though, CO2 pipelines are largely unregulated, a precedent set in the permitting and construction of the current longest CO2 pipeline, the Cortez Pipeline. That pipeline, now owned by Kinder Morgan Energy Partners -- and at the time owned by Shell, Mobil, and Continental Resources -- brings CO2 from McElmo Dome to the Permian Basin CO2 EOR fields.

In a ruling made by the Federal Energy Regulatory Commission (FERC), which oversees the interstate regulation of gas pipelines, the agency decided in 1979 that CO2 does not amount to a “natural gas” under the Natural Gas Act and is thus not under FERC's jurisdiction. In 1991, the Office of Pipeline Safety (OPS) -- the precursor to the (PHMSA) -- further ruled that CO2 is not a "hazardous" waste under federal regulatory law. This came after advocacy on behalf of that policy by the American Petroleum Institute and Exxon, according to the Federal Register report for the final rule-making, with API bringing the petition to the agency to amend the law. The Interstate Commerce Commission (ICC), PHMSA's precursor, further "ruled in 1980 that Congress intended to exclude any 'gas' from its jurisdiction, and therefore it did not have authority over CO2."

"On March 16, 1989, the American Petroleum Institute (API) petitioned the Department to amend part 195 to include the regulation of pipelines that transport CO2," the Federal Register details. "The recommendations contained in this petition are the product of a task force formed under API auspices, consisting of representatives of nine companies that own or operate CO2 pipelines. The participating companies were Amerada Hess Corporation, Amoco Pipeline Company, ARCO Pipeline Company, Chevron Pipe Line Company, Enron Corporation, Exxon Pipeline Company, Mobil Pipe Line Company, Production Operators, Inc. and Shell Pipe Line Corporation."

Many of those companies, at the time, were also operators of CO2 fields. States, too, have a patchwork of regulations aimed at CO2 pipelines.

In 2014, the U.S. Environmental Protection Agency also ruled that CO2 was not a "hazardous waste," as defined by Resource Conservation and Recovery Act when injected underground. It was a docket item commented on by companies such as Texas Oil and Gas Association, Chevron, Southern Company, and American Petroleum Institute.

H2S Leakages, Blowouts

A 1993 U.S. Environmental Protection Agency study documented that H2S had leaked out of at least six other CO2 EOR fields between 1972-1993 in ways that had documentable and reportable consequences felt by people and the environment.

One of those, which happened in 1990 in Heidelberg, Mississippi, was a CO2 EOR well blowout and accompanying fire. Three died and 350 residents evacuated. That field is today operated by Denbury. One worker suffered a burn that impacted 40% of his body. A local newspaper reported the air in the surrounding area smelling like "rotten egg odor" in the incident's immediate aftermath.

"From what I have been told, water went into [the well], and when pressure built up, it blew out," Jaspar County Sheriff Tom Green told the media at the time, in the immediate aftermath of the explosion. A resident who lived near the explosion site futher stated that "I thought they were sinking a test well and it shook and shook the house. I looked out my door and saw a fireball in the sky and a lot of smoke," she said, continuing, "Never in my life have I felt anything like this before." A firefighter who was on the scene further detailed, of the exploded oil rig, "Ain't nothing left of that...It ain't nothing but a charcoal pile."

And in 1991 in Yoakum County, home of the Wasson Field for CO2 EOR development serviced by the McElmo Dome and then operated by Shell, a gathering line consisting of 1.2% H2S ruptured. It killed seven cows, a coyote and rabbits.

Jackson Dome Explosions

In February 2020, the 24-inch Delhi Pipeline—which sends CO2 from the Jackson Dome to the Hastings Field in Alvin, Texas—exploded in Yazoo County, Mississippi. Documents obtained via open records request show the CO2 plume stretched for between 30-40 kilometers and the Mississippi Emergency Management Agency revealed the plume stretched all the way northwest stretching beyond Holly Bluff, Mississippi.

Aftermath of Feb. 2020 CO2 pipeline explosion in Yazoo County, MS. Credit: Mississippi Emergency Management Agency

Plume shown from NOAA program showing February 22 CO2 pipeline rupture in Yazoo County, MS from Denbury's Delhi Pipeline.

An on-scene investigator described a “green fog” of both hydrogen sulfide and CO2 leaking into the atmosphere across the highway from the ruptured pipeline at the scene of the incident. Though no one died, 46 people were hospitalized and 300 were evacuated from their homes. Three men passed out in their cars at the scene of the pipeline rupture, knocked unconscious.

A sheriff’s investigator stated that those rescued during the incident were acting “like zombies” and some were “foaming at the mouth.” The sheriff deputy called to the scene also had to be hospitalized. Documents obtained via open records request show over 31,000 barrels of CO2 leaked into the atmosphere.

An incident report obtained via Mississippi Public Records Act from the Yazoo County Sheriff's Department shows that the investigator wrote that he was "having difficulty breathing, as though I'd just run a mile and was out of breath," in explaining his on-scene response. That investigator further wrote that some people he approached on-scene seemed "confused" and did not "understand what I was saying" when he spoke to them. In that state, the investigator said he had to "forcefully" get them into his squad car.

The class-action plaintiffs' law firm Morgan & Morgan is representing victims of the pipeline blowout, saying in a February statement, "Our hope is to uncover all the facts that led to this incident and hold those responsible accountable for their actions or omissions." In October 2020, near the same area in Yazoo County, the same pipeline had another CO2 leak. It led officials to temporarily shut down State Highway 3.

Records obtained via the Mississippi Public Records Act show that this pipeline blowout and leak was even bigger in size: just under 42,000 barrels of CO2 escaped from the pipeline.

Other records obtained from the Chief Operating Officer of the Mississippi Emergency Management Agency, Matthew Hewings, critiquing Denbury. He wrote, "I can't help but wonder if Denbury is being entirely forthcoming in their [National Response Center] reporting, which makes getting accurate information from the field problematic. At some point, H2S was brought into the equation - then it was never spoken of again. I'm not saying it is cover up, but it would be awfully convenient for Denbury .. legally and financially ... if H2S was left out of the discussion."

According to a 2014 report by the U.S. Department of Energy's National Energy Technology Laboratory, the Jackson Dome CO2 stream consists of 5% H2S, the highest concentration for any the CO2 source fields.

In another email, Hewings wrote "It is curious that the HZS or anything other than CO2 is not annotated below, especially since the locals reported a green gas and noxious odor."

"[David] Battaly (Emergency Manager at the agency) reported an orange haze like a sand storm. CO2 is colorless and odorless at low concentrations, yet smells acidic at high concentrations," Hewings continued. "It sure seems as if something other than just CO2 was present. Additionally, the extreme symptoms reported by the victims are consistent with exposure to HZS. Something doesn't add up ..."

A company pipeline also ruptured in 2012 at the Hastings Oil Field in Brazoria County, with no one suffering injuries and no reported spillage or environmental damage relayed to the Houston Chronicle.

In 2007 in Amite County at a Denbury-operated CO2 EOR well, a blowout led to three nearby homes being evacuated. Residents in the area said it sounded like "a loud roaring noise" akin to "when an airplane flies over real low," even a mile and a half from the blowout site. Three days after the blowout started, it was "still spewing so much carbon dioxide, saltwater and oil that officials...closed a state highway and imposed a five-mile no-fly zone indefinitely," a local newspaper reported, also noting detectable levels of benzene in the area surrounding the well.

In an editorial for the Enterprise-Journal, one of the state's biggest local newspapers, the editorial board wrote "If it happened...in Amite County, it certainly can happen anyplace where there's drilling activity. The recovery of oil and natural gas from thousands of feet below the surface—two or three miles below, and sometimes deeper—is an amazing technological achievement that we tend to take for granted. But it is dangerous work, and there is plenty of risk involved." The editorial goes on to ask questions about what the long-term impacts are of plugged CO2 EOR wells, calling on the state and Denbury to "be completely forthcoming about exactly what happened" in the incident.

Half a year earlier in Lincoln County, Mississippi, a CO2 EOR well leaked also owned by Denbury leaked. It led to the evacuation of several homes.

Jackson Dome Legal, Regulatory Issues

James Wagoner and JWW Oil and Gas Exploration argued in the federal case Waggoner v. Denbury Onshore, L.L.C. that Denbury’s vertically integrated business model amounted to a monopoly. In 2015, the U.S. Court of Appeals for the Fifth Circuit ruled that no monopoly existed, even if the arrangement created an “alleged injury of decreased royalty payments due to a conspiracy among oil companies.”

Prior to that ruling, a legislative effort in the Mississippi Legislature also failed for two consecutive sessions in 2014 and 2015. The bills would have mandated common carrier status for Denbury's CO2 pipelines in the state which utilize eminent domain as part of their land use authority.

The company also pays no severance tax in drilling for CO2 at the Jackson Dome and a legislative effort attempted to change that to a rate of 6%, but failed. The author of the bill, Rep. Gary Staples, (R-Laurel), said not having a severance tax on CO2 drilling costs the state $20 million in tax revenue per year.

“Denbury Resources is sending 500 million cubic feet of CO2 a day to Texas, and we’re not making a dime on it,” Staples told a local publication at the time. “The people in this state are not for giving away our natural resources, and they need to be aware that it’s happening.”

Denbury fought against the measure, with a lobbyist for the company stating, "I contend the state is getting something from what we do in the state of Mississippi, regardless of where the carbon dioxide goes. We're bringing so much more to the table than that, that it's almost laughable to be sitting here talking about this." The tax would've yielded $20 million in tax dollars per year to the state.

In Texas, Denbury also sat at the center of a landmark common carrier doctrine Supreme Court ruling on the issue of the use of eminent domain legal doctrine as it relates to common carrier status for its Green Pipeline, which connects to the Jackson Dome. The Court ruled in 2017 that Denbury could utilize the legal authority to condemn privately-held land in building out the CO2 pipeline.

"All that is required is a reasonable probability that the pipeline will, at some point after construction, serve the public by transporting a product for one or more customers who will either retain ownership or sell it to parties other than the carrier," explained an attorney of the ruling in the case Denbury Green Pipeline Texas LLC v. Texas Rice Land Partners Ltd. A 'reasonable probability' is 'more likely than not.'"

Bravo Dome 1985 Tax Legislation Scandal

In 1985, New Mexico Senator Budd Hebert (R-Chavez) proposed legislation that would have eliminated a severance tax for a 12-year period on CO2 production at the Bravo Dome. He proposed the legislation, which did not pass due to a last-minute filibuster in the New Mexico Senate, as he would have personally profited from it.

According to an investigation by the Albuquerque Journal, Hebert had concurrently owned a 25% stake in a company which was a joint venture production partner of Mobil, with ambitions to work with Mobil to do CO2 EOR production using the carbon extracted at the Bravo Dome. Hebert owned the 25% stake alongside a member of the New Mexico House of Representatives, Robert Light (D-Eddy), who served as author of the House version of the legislation. The tax break would have boosted sales to a total of $6 billion from Bravo Dome to the CO2 source fields via the Cortez Pipeline, the Associated Press reported at the time of the proposed bill, SB 207.

In reaction to the Albuquerque Journal's reporting, the state's Attorney General said the state's conflict-of-interest laws were too lax because what Hebert and Eddy did was perfectly legal under the letter of the law. "The public needs confidence in the process, but how can they have it if legislators are allowed to promote bills without disclosing their interest?" the Attorney General, Paul Bardacke, said at the time in an interview with the Journal. Eddy defended himself by saying the bill was written by Shell, then the predominant operator at the Bravo Dome, and not Mobil.

The company Worth Petroleum filed a lawsuit against Mobil in 1986, saying the business connection Hebert had acted as an illegal inducement to push legislation favorable for certain oil companies, with the parties coming to an out-of-court monetary legal settlement just days before a jury trial's slated commencement.

Sequestering vs. Recycling

During the CO2 EOR process, CO2 is not merely stored underground immediately. Instead, it is recycled as part of what the Global CCS Institute describes as a "closed loop," which "reduces the need to purchase additional CO2."

A closed-loop CO2 EOR system, exhibited in a 2013 NETL report.

A 1976 study commissioned by the Federal Energy Administration pointed out that, from the onset, CO2 EOR would not be economically feasible for the oil industry without recycling technology. The study explained the industry will necessitate "major improvements in...recycling...before the full potential of this recovery tech­nique can be realized."

As early as 1981, a petroleum engineering coordinator for Shell told colleagues at the Society for Petroleum Engineers that CO2 for CO2 enhanced oil recovery should be recycled because it "is a very valuable commodity" and "it does involve large amounts for oil recovery."

In 1991, a production supervisor at Shell at the Jackson Dome further explained, "We're recycling everything we produce. Eventually the flood will be mature enough that all we'll be doing is recycling. We won't have to bring any more down from Jackson Dome."

In 2016, the U.S. Department of Interior's Office of Natural Resources Revenue also explained the CO2 EOR process as one centering around recycling in a legal ruling pertaining to disputes over royalty payments at the Bravo Dome. "At the surface, the CO2 is separated from the oil," explains the filing. "The oil is sold and the CO2 reused again in the EOR reservoir. This means the CO2 is part of a continual process and is not sold."

In a 2018 presentation, Denbury further concluded that by 15 years into a CO2 EOR operation, 20% of its CO2 will be recycled. By 20 years, that number goes up to 50%. By 25 years, that number goes up to 70% and by 30 years, that number goes up to 80% recycled.

The U.S. Department of Energy's National Energy Technology Laboratory put it more simply in a 2019 paper on CO2 EOR, writing, "the objective of CO2 EOR operations is not to store CO2, but to maximize oil production. However, some of the injected CO2 ultimately does get stored in the reservoir as part of the process.

“The need for the field to purchase new CO2 is gradually reduced over time,” further explains a 2019 paper published by the U.S. Department of Energy. “As a result, a greater percentage of the CO2 injected is from production, separation, and recycling versus newly-purchased CO2.” That paper further explained that “approximately half has been recovered and recycled” and more broadly “CO2 EOR operators try to maximize oil and gas production and minimize the amount of CO2 left in the reservoir.”

A 2010 paper by the National Energy Technology Laboratory also explains the exact money saved by doing the recycling process, writing that "Because of the cost of naturally sourced CO2—roughly $10-15 per metric ton—a CO2 flood operator seeks to recycle as much as possible to minimize future purchases of the gas."

Articles and Resources

• Nelson, Cody, "Inside the Dirty, Dangerous World of Carbon Flooding", Capital & Main, April 5, 2021
• Nelson, Cody, "Why energy companies are drilling for a greenhouse gas in New Mexico", New Mexico Political Report, Dec. 14, 2020
• P. DiPietro, P. Balash, M. Wallace, "A Note on Sources of CO2Supply for Enhanced Oil Recovery Operations," U.S. Department of Energy, National Energy Technology Laboratory, April 2020
• U.S. Department of Energy, National Energy Technology Laboratory, "Subsurface Sources of CO2 in the Contiguous United States - Volume 1: Discovered Reservoirs", March 5, 2014
• U.S. Department of Energy, National Energy Technology Laboratory, "Subsurface Sources of CO2 in the United States - Volume II: Exploration of CO2 Systems," March 26, 2014
• U.S. Department of Energy, National Petroleum Council, "Carbon Capture, Use, and Storage (CCUS) Report," 2019

Related GEM.wiki articles

• Carbon Capture and Storage
• Carbon Capture Utilization and Storage
• Denbury
• Occidental
• Kinder Morgan Energy Partners
• Jackson Dome
• Bravo Dome
• McElmo Dome
• Doe Canyon
• Sheep Mountain
• St. John's Dome
• SACROC
• Lobos Pipeline
• CO2 enhanced oil recovery