Issues Related to Carbon Dioxide Pipeline Transportation Infrastr

INTRODUCTION

Climate Change, Causes, and Solutions

Anthropogenic carbon dioxide (CO2) emission rates almost doubled between 1970 and

2010 (IPCC, 2014) Emissions have caused the atmospheric CO2 concentration above Mauna Loa,

HI to rise above 400 ppm for the first time in nearly 3 million years (NOAA, 2016a) The role of

CO2 in creating a hospitable climate has been known since John Tyndall’s discovery of the

The greenhouse effect, first identified in the 1800s, has reached a critical tipping point, with increased emissions directly linked to severe environmental consequences (IPCC, 2014) These emissions contribute to rising global temperatures, elevated sea levels, and the pronounced contrast between dry and wet climates, leading to more frequent natural disasters, disease outbreaks, and shortages of food and water, ultimately threatening human lives (IPCC, 2014) The financial impact of climate change is evident in the growing number of billion-dollar natural disasters (NOAA, 2016b) To mitigate these effects, it is essential to significantly reduce CO2 emissions.

Carbon emissions remained stable throughout much of human history but surged dramatically during the Industrial Revolution due to the exploitation of fossil fuels This increase in fossil fuel combustion has been directly linked to rising atmospheric CO2 levels (IPCC, 2014), prompting the need for alternative energy sources that do not emit CO2 Renewable energy options, such as solar photovoltaics, wind turbines, and biofuels, have been proposed as viable substitutes for fossil fuels (Chu and Majumdar, 2012) Over the past decade, there has been a notable increase in the capacity and generation of renewable energy sources (US EIA, 2017).

2 to the total U.S energy budget, renewable energy sources represent less than 10 percent of energy capacity while fossil fuels still supply 73 percent of our overall energy demand (US EIA,

Renewable energy sources face significant challenges, particularly regarding geographic limitations and energy generation consistency The debate over using energy crops for biofuels intensifies as malnutrition remains prevalent globally While solar energy generation thrives in arid regions like Arizona, it struggles in cloudier areas such as Seattle Similarly, wind turbines excel in the Midwest but are less effective in the Southeast Although large transmission systems can mitigate some geographic issues, they cannot address the unpredictability of weather, leading to generation availability challenges Additionally, renewable resources often operate at a kilowatt scale, insufficient to replace large coal baseload facilities that require megawatt-level output Consequently, fossil fuels are expected to continue playing a vital role in the U.S energy landscape for the foreseeable future.

Figure 1 Increases in generation of wind (orange) and solar (green) energy Image obtained from

Carbon Capture and Storage and Enhanced Oil Recovery

Carbon capture and storage (CCS) is an effective strategy for reducing harmful CO2 emissions by capturing and sequestering greenhouse gases underground in saline reservoirs or depleted oil fields This technology enables the U.S to continue utilizing efficient fossil fuels while minimizing climate change impacts However, the primary challenge for CCS is its economic feasibility, with costs estimated by the International Energy Agency (IEA) to range from $50 to $90 per tonne of CO2 sequestered The process of capturing CO2 from fossil fuel combustion contributes significantly to these costs, accounting for 50-75% due to decreased energy production efficiencies Consequently, any increase in energy production costs may lead to higher energy bills for consumers Without economic incentives, such as cost subsidies, CCS remains an unpopular option among both the industry and consumers for mitigating climate change.

Figure 2 Carbon storage in geologic reservoirs Taken from Dooley et al (2006)

Enhanced oil recovery (EOR) significantly boosts the appeal of carbon capture and storage (CCS) processes by injecting CO2 into older oil fields to enhance production Unlike traditional CCS, which stores carbon in saline reservoirs or depleted oil fields, CO2-EOR has been utilized since the early 1970s to extract stranded oil left after primary and secondary recovery efforts The initial pilot tests for this method were conducted in the Mead-Strawn and Scurry Area Canyon Reef Operators Committee (SACROC) units in west Texas, demonstrating the effectiveness of CO2-based EOR in oil recovery.

CO2-enhanced oil recovery (EOR) can yield 4-12% of the original oil in place, utilizing 50% more oil than water flooding alone (Gozalpour et al., 2005) The economic viability of CO2-EOR projects depends on factors such as the cost of CO2 procurement, drilling expenses for injection wells, and the prevailing oil market prices (Norman, 1994; NETL).

2010) When CO2 prices are low and oil prices are high, industry has the incentive to utilize this technique

Since the early pilot tests, CO2-EOR has become widespread with more than 136 operations in traditional producing basins in Texas, Wyoming, Oklahoma, Mississippi and Louisiana (Kuuskraa and Wallace, 2014) Over time the oil and gas industry has been able to expand due to the use of inexpensive, naturally-occurring CO2 sources from underground formations like the Jackson Dome in Mississippi Of the 8.7 million barrels of oil per day produced in 2014, CO2-EOR contributed 300,000 barrels per day, or approximately 3 percent of production, while sequestering 3.5 MMcf/day of CO2 (Kuuskraa and Wallace, 2014) Projections for 2020 predict CO2-EOR production should double and while the majority of projects are currently located in west Texas, the Gulf Coast (including areas outside of Texas) may see significant

The U.S government is dedicated to combating climate change by investing in economical solutions, as evidenced by the allocation of $14 million to research universities aimed at enhancing the efficiency and expansion of Enhanced Oil Recovery (EOR) techniques (Kuuskraa and Wallace, 2014; US DOE, 2014).

Louisiana EOR

Louisiana is well-positioned to leverage CO2-enhanced oil recovery (EOR) due to its rich history in fossil fuel production, abundant underground storage options, and a robust industrial sector In 2014, the state ranked eighth in overall energy production, fifth in natural gas, and ninth in crude oil Since the first well was drilled near Jennings in 1901, the Louisiana Department of Natural Resources has documented around 1,800 oil and gas fields across the state Many of these mature fields have seen minimal crude oil production, making them prime candidates for carbon capture and storage (CCS) or EOR initiatives.

In addition, Louisiana’s large industrial sector contributes 60 percent of the state’s overall

CO2 emissions compared to the average U.S state’s industrial sector which only contributes 18 percent, Figure 3 (US EIA, 2017) South Louisiana’s 58 reporting industrial facilities involved in

Figure 3 CO2 emissions by sector for: 1) average state and 2) Louisiana Data obtained from US EIA (2017) and reported for 2014

In 2015, fossil fuel refining and chemical production in Louisiana contributed 25 million metric tons of CO2 to the atmosphere, making the state the fifth highest in CO2 emissions per capita at 47 metric tons per individual.

2017) The combination of oil and gas fields, as well as large sources of relatively pure CO2, make Louisiana a potential candidate for CO2-EOR projects (Dismukes et al., 2017)

Figure 4 Location of major industrial facilities emitting CO2 in southern Louisiana Data obtained from US EPA (2017).

Research Proposal

Despite extensive research on efficient CO2 capture and enhanced oil recovery (EOR), midstream transportation has received insufficient attention Pipelines are recognized as one of the most efficient, cost-effective, and safe methods for transporting CO2 As of 2015, the Pipeline and Hazardous Materials Safety Administration (PHMSA) reported over 5,200 miles of CO2 pipelines in the U.S., indicating the need for expanded infrastructure to support the growth of CO2-EOR initiatives.

7 estimates midstream companies will need to build 1,000 miles of CO2 pipeline every year until

By 2030, the U.S aims to capitalize on emerging Enhanced Oil Recovery (EOR) opportunities, yet faces challenges due to its limited experience with CO2 pipelines, despite having an extensive natural gas pipeline network Understanding the distinct physical and technical characteristics of CO2 is crucial for accurate pipeline design, cost assessment, and permitting processes This study focuses on the existing CO2 infrastructure in Louisiana, analyzes the costs associated with building CO2 pipelines, explores the complexities of converting natural gas pipelines to CO2, and proposes a methodology to evaluate the feasibility of large-scale conversion projects in the state.

LITERATURE REVIEW

Technical Aspects of Natural Gas Pipelines

Pipeline transportation is the primary method for large-scale natural gas production and usage due to its efficiency and safety, making alternative transportation methods less viable Since the late 1800s, the development of oil and natural gas pipelines has significantly expanded, now totaling approximately 200,000 and 2,200,000 miles, respectively The modern pipeline industry has evolved to also transport industrial gases such as nitrogen, helium, ammonia, hydrogen, CO2, and various refined products and chemicals.

Natural gas pipelines are categorized into three types based on their operational conditions and purposes Gathering lines, typically small in diameter (2-6 inches) and low pressure, transport raw natural gas from production fields to processing plants for impurity removal and refinement Once processed, the natural gas is conveyed through larger diameter (6-48 inches) high-pressure transmission lines, operating at 500-1,400 psi, which facilitate long-distance transportation, both intrastate and interstate.

"Stepped down" refers to the process of reducing pressure through various regulators, allowing for the distribution of gas via smaller diameter lines (ranging from 2 to 24 inches) This lower pressure distribution can occur directly to industrial consumers or through a citygate, which is managed by a local company that owns its own distribution infrastructure.

Pipelines are constructed from a range of materials and protective coatings, with a historical reliance on wrought iron and cast iron However, these older materials are increasingly being replaced by more durable options, such as carbon steel and plastics, to enhance longevity and reliability (PHMSA, 2017).

Pipelines are essential for transporting high-pressure natural gas, though they are costly and primarily utilized for transmission In contrast, plastic pipelines, which are more affordable and flexible, are mainly used for distribution but are unsuitable for high-pressure applications exceeding 100 psi To combat corrosion and rust, specialized coatings such as epoxy or polyethylene, along with cathodic protection, are applied to carbon steel pipelines after manufacturing Additionally, factors such as welding materials, the number of compressor stations, and the implementation of Supervisory Control and Data Acquisition (SCADA) systems are crucial for effective product management and emergency response.

Figure 5 Parts of the pipeline industry from upstream to downstream Image taken from PHMSA

The capacity of a pipeline to transport natural gas is influenced by its Maximum Allowable Operating Pressure (MAOP), which depends on the design specifications of the pipe and the surrounding terrain MAOP can be determined using a specific equation.

The Specified Minimum Yield Strength (SMYS) is the lowest pressure a pipeline can endure before deformation, determined by the steel grade, while the design factor, typically 0.72 for rural pipelines, is crucial for minimizing the risk of incidents by accommodating unexpected pressure changes In high consequence areas (HCA), this factor is reduced to between 0.72 and 0.4 to enhance safety Consequently, natural gas pipelines are rated significantly below their manufacturing capacity to prioritize public safety.

The construction of pipelines is a complex and often controversial process that requires companies to apply for permits well in advance This involves securing Right of Ways (ROW), which are permissions from both private and public landowners to allow pipelines to be installed on their property Typically, pipelines are situated at a minimum distance from sensitive areas to mitigate potential impacts.

Pipeline construction requires significant land disturbance, with right-of-way (ROW) widths necessitating up to 50 feet of clearing on either side of the pipeline Pipes are installed 30 inches below the surface, strung along trenches, welded, and shaped to fit the terrain After the pipeline is completed, it undergoes rigorous testing, such as hydrostatic testing and in-line pigging, to ensure there are no leaks The final steps involve backfilling and restoring the area Overall, developing a pipeline demands years of meticulous planning and substantial financial investment, often reaching millions or even billions of dollars, before natural gas can be effectively transported.

Costs are broadly separated into capital expenditures (CAPEX) and operational expenditures (OPEX) CAPEX are the upfront expenses to build the pipeline and are further

Natural gas pipeline costs are categorized into four main areas: construction labor, miscellaneous expenses, right-of-way (ROW), and materials Construction labor represents the largest portion at 47% of the total budget, followed by miscellaneous costs at 34%, materials at 13%, and ROW at 6% (Smith, 2016) Miscellaneous expenses encompass surveying, engineering design, administrative costs, filing fees, and interest Over the past decade, while construction labor costs have remained high, material costs have significantly decreased, even falling below miscellaneous expenses (Smith, 2016) Additionally, operational expenditures (OPEX) include regular maintenance, repairs, and fuel for compressors.

Differences in CO 2 and Natural Gas Pipelines

Natural gas and CO2, while both gases at standard temperature and pressure, exhibit distinct transportation characteristics in pipelines due to their physical phase changes influenced by temperature and pressure As temperature rises at constant pressure, a molecule transitions from solid to liquid and finally to gas Transporting CO2 as a supercritical fluid is often the most cost-effective method, as it combines the high density of a liquid with the low viscosity of a gas, making it an efficient option (Zhang et al., 2006) The state at which a molecule reaches its supercritical phase is critical for optimizing transport.

12 critical point Methane and CO2 differ with respect to their critical point; -82.3°C/ 673 psi and 30.9°C/1070 psi, respectively (Figure 6)

Figure 6 Phase diagram of CO2 with respect to temperature and pressure Image taken from: Averill and Eldredge (2012)

Natural gas is typically transported via pipelines in its gaseous form at pressures ranging from 800 to 1,160 psi, while supercritical CO2 must be transported at a minimum pressure of 1,070 psi To prevent phase changes due to temperature fluctuations between 40-100°F, CO2 transportation pressures may need to exceed 1,200 psi If the pressure falls too low, CO2 can change phase, and frictional losses in the pipeline can impede transport Currently, all major CO2 pipelines operate at pressures above 1,900 psi Although CO2 can be transported at lower pressures in its gaseous state, this is less economically viable, especially since Enhanced Oil Recovery (EOR) applications specifically require supercritical CO2.

13 time of capture for transportation, the gas will need to be compressed at the injection site (Zhang

CO 2 Material Considerations

CO2 and natural gas pipelines share similar construction methods, but CO2 pipelines necessitate higher quality materials due to the elevated pressures involved According to ASME B31.8, the design specifications for pipe materials are critical, with steel grades classified by the American Petroleum Institute (API) as “X” followed by a number that indicates the specified minimum yield strength (SMYS) For supercritical CO2, pipeline yield strength must range from 60,000 to 80,000 psi, which corresponds to API grades X60 to X80 Cost models indicate that utilizing higher grades of steel, such as X80 and above, can lead to reduced costs for supercritical flow For instance, the Canyon Reef pipeline, which supplies the SACROC unit, features pipelines with a maximum allowable operating pressure (MAOP) of 2,194 psi for a 16-inch, 0.375-inch wall X65 pipe and 2,526 psi for a 12.75-inch, 0.344-inch wall X65 pipe, based on a Class 1 design factor.

Supercritical CO2 poses significant challenges for pipeline components, as it can be absorbed by polymers and lubricants, leading to swelling and potential cracking of o-rings and seals when pressure is released To mitigate these issues, Boot-Handford et al (2014) suggest using more durable materials such as Teflon and Viton polymers Additionally, higher-rated flanges are necessary to endure the increased pressure (Antaki, 2003) Transporting CO2 over long distances or through difficult terrain requires costly additional compression, as CO2 pipelines necessitate booster stations with fluid pumps, unlike natural gas pipelines that utilize gas compressors (van der Zwaan et al., 2011; WRI, 2008) Consequently, recompression represents the largest portion of operating costs in CO2 transportation (WRI, 2008).

Transportation distances can be minimized by using fewer compressor stations or larger diameter pipelines, which help reduce pressure drop (Leung et al., 2014) Research by Tang et al (2017) indicates that there are no significant differences in pipeline corrosion whether transporting CO2 in supercritical or gaseous phases, making the choice dependent on project requirements and economic factors Although CO2 pipelines necessitate higher quality and more costly components, WRI (2008) asserts that material considerations do not pose a significant barrier to the industry's progress.

Impurities

CO2 is rarely 100 percent pure and often contains impurities such as water (H2O), hydrogen sulfide (H2S), and nitrous oxides (NOx), which can compromise pipeline integrity Among these, water is the most significant contributor to corrosion, as dry CO2 does not pose corrosion risks According to the IPCC (2005), corrosion rates in surveyed CO2 pipelines were found to be 0.01 mm/year However, the presence of wet CO2 can lead to the formation of carbonic acid (H2CO3), which can rapidly corrode pipelines.

The presence of H2O and H2S can lead to the formation of sulfuric acid (H2SO4), resulting in significant corrosion issues However, if the CO2 stream is dry, corrosion problems can be mitigated Research by Bilio et al (2009) indicates that current equations of state for CO2 phases do not account for impurities, which can affect the temperatures and pressures required to maintain CO2 in a supercritical state Variability in impurity levels across different CO2 sources complicates the development of accurate equations of state While natural CO2 sources typically exceed 95% purity, industrial sources exhibit varying impurity levels, as noted by Mahgerefteh et al (2012), Oosterkamp and Ramsen (2008), and Herron and Myles (2013).

There are currently no universally accepted or government-defined standards dictating

CO2 purity specifications are typically established through contracts between suppliers and pipeline operators, with industry best practices recommending CO2 concentrations exceeding 95% (Herron and Myles, 2013) Despite this, pipelines can effectively transport CO2 with certain impurities Research by Schremp and Roberson (1973) indicates that pipelines in the SACROC area have shown no signs of pitting while transporting CO2 with H2O and H2S concentrations significantly higher than standard levels Gill (1982) further supports this, noting that these pipelines have remained operational for over a decade with minimal corrosion Additionally, the Weyburn pipeline has successfully transported CO2 with elevated H2S levels for 30 years without encountering serious issues (Onyebuchi et al., 2017) While alloy steel can be utilized in situations where water accumulation is a concern, it is more costly and should only be employed when absolutely necessary (Boot-Hanford et al.).

2014) Mechleri et al (2017) notes excessive impurities will necessitate the need for more durable materials which ultimately increase overall costs.

Pipeline Regulation

Government oversight has played a crucial role in the natural gas industry due to its natural monopolistic tendencies and public safety concerns Initially, regulation began at the municipal level where natural gas was produced and consumed However, as pipeline networks expanded across towns and states, the need for higher levels of government oversight became evident Originally, pipeline operators owned the gas they transported and sold it to consumers on a bundled basis Over time, regulations limited pipelines' ability to engage in bundled sales, transforming them into pure common carrier transport companies.

1993) Common carriers provide equal access to all parties on an uniform, nondiscriminatory

Common-carrier pipelines, which are subject to state and federal regulations, vary in size from small intrastate operations to extensive interstate systems that cover large areas of the country.

Interstate pipelines are governed by federal regulations, primarily overseen by the Federal Energy Regulatory Commission (FERC) and the Pipeline and Hazardous Materials Safety Administration (PHMSA) The FERC regulates the interstate commerce of wholesale natural gas, focusing on the oversight and approval of new pipelines to ensure reliable and affordable energy for consumers Established in 2004, the PHMSA is responsible for maintaining safety standards and managing the inventory and leak data of the U.S pipeline system.

The Code of Federal Regulations (CFR) Part 192 outlines safety standards for natural gas, while CO2 pipelines are governed by a different set of regulations under CFR Part 195, as CO2 is classified as a hazardous liquid Consequently, the Federal Energy Regulatory Commission (FERC) does not oversee CO2 pipelines; this responsibility is assigned to the Department of Transportation's Surface Transportation Board (STB) However, the STB primarily regulates the transportation of commodities other than water, oil, and gas, and is currently focused on interstate transportation matters.

CO2 pipelines are classified as common carriers, but the Surface Transportation Board (STB) has limited regulatory responsibilities compared to the Federal Energy Regulatory Commission (FERC) The STB only intervenes in pricing disputes, and as no such disputes have been reported, it has yet to rule on any CO2 pipeline cases Consequently, regulation of CO2 pipelines primarily falls to individual states, with the Pipeline and Hazardous Materials Safety Administration (PHMSA) playing a secondary role.

In Louisiana, intrastate CO2 pipelines are regulated by the Department of Natural Resources under the oversight of the Commissioner of Conservation, with design specifications outlined in the Louisiana Administrative Code Title 43: Part XI Subpart 4, which align with 49 CFR 195 but only apply to transmission lines, excluding gathering lines Companies must obtain a Certificate of Public Necessity and Convenience (CPN) from the commissioner before constructing a CO2 pipeline, with prior approval required for Enhanced Oil Recovery (EOR) projects Additionally, the commissioner’s approval is necessary for CO2 pipelines that traverse the state for out-of-state EOR projects While CO2 pipelines possess eminent domain rights in Louisiana, these can only be exercised with an approved CPN To circumvent the need for eminent domain and right-of-way acquisition, repurposing existing pipelines is a viable option As the CO2 pipeline industry grows, state permitting will face increasing legal challenges, prompting discussions about the sufficiency of current regulations, particularly for pipelines crossing state lines.

Environmental Safety Issues

CO2 pipeline ruptures pose significant safety risks due to the susceptibility of highly pressurized lines to longitudinal propagating fractures, which can lead to the rapid release of substantial CO2 volumes The presence of impurities can exacerbate pipe stress by increasing the toughness required to halt these fractures To mitigate the risk of propagating fractures, longitudinal crack arrestors are typically installed every 500 meters along the pipeline.

In-line Emergency Shutdown Valves (ESVs) play a crucial role in minimizing the impact of pipeline ruptures by quickly sealing off affected segments within seconds of a pressure drop Proper placement of ESVs is essential, as greater distances between valves can lead to increased inventory loss during an incident (Mahgerefteh et al., 2016) These measures are designed not only to prevent fractures but also to reduce the duration and severity of any that do occur, ultimately enhancing safety and efficiency in pipeline operations.

Figure 7 Modes of pipeline fracture by specific mechanisms Image obtained from Bilio et al

From a safety standpoint, carbon dioxide (CO2) is non-flammable and poses no explosion risk However, its density—1.5 times greater than air—can lead to accumulation in low-lying areas, creating asphyxiation hazards, especially at concentrations exceeding 15 percent Physiological effects, such as headaches, can occur at levels as low as 3 percent (Harper et al., 2011) A notable historical incident occurred near Lake Nyos in Cameroon, where a sudden release of CO2 suffocated a nearby village (King et al., 1987) While Lake Nyos exemplifies the dangers of CO2, the volume released in such events is significantly greater than what would be expected from a pipeline rupture Notably, the U.S has not reported any CO2-related fatalities in the past two decades.

A CO2 pipeline leak can have severe consequences, as evidenced by a 2017 incident that resulted in 19 fatalities (PHMSA, 2017) One notable event occurred in 2007 when Denbury Resources experienced a well blowout near the Delhi Field in northeastern Louisiana, leading to significant CO2 emissions that harmed local wildlife (Mississippi Business Journal, 2013) To enhance safety, the natural gas industry has implemented the practice of adding mercaptans before transportation, which aids in leak detection.

CO2 transportation has demonstrated a strong safety record, with significantly fewer accidents and fatalities per mile compared to oil and natural gas pipelines, according to WRI (2008) and Duncan et al.

(2008) has noted safety incidents within the realm of CO2 pipelines have been rare and are of little concern

Table 1 Comparison of pipeline accidents and fatalities by commodity type from 1997-2016 Data was obtained from PHMSA (2017)

Carbon Dioxide Crude/Petroleum Natural Gas

United States CO 2 Pipeline Infrastructure

As of 2015, the United States boasted an extensive network of 5,200 miles of CO2 pipelines, capable of transporting around 24.8 billion tons annually (PHMSA, 2017) The majority of this infrastructure is concentrated in three key regions: the Permian Basin, the Rocky Mountains, and the Gulf Coast.

The Canyon Reef Carriers, established in 1972 in the SACROC oil field of West Texas, marked the inception of CO2 pipeline infrastructure Predominantly, Enhanced Oil Recovery (EOR) projects have been concentrated in the Permian Basin, leading to the development of extensive CO2 pipeline networks in the region As more affordable natural sources of CO2 were identified, pipeline systems expanded into states like Wyoming and Mississippi.

The CO2 pipeline industry is primarily dominated by three major companies: Kinder Morgan, Oxy Permian, and Denbury Resources, which collectively manage the majority of the infrastructure (Wallace et al., 2015) Most operators focus on transporting natural sources of CO2 and typically hold ownership stakes in their CO2 supply (Global CCS Institute, 2014) Notably, in the Rocky Mountain region, particularly Wyoming, CO2 pipelines benefit from a substantial influx of CO2 derived from natural gas processing, with a limited number of interconnected owners Additionally, Denbury Resources has a contractual agreement with ExxonMobil for CO2 supply in Wyoming.

In the Rocky Mountain region, CO2 pipelines function similarly to common carriers, although the largest Enhanced Oil Recovery (EOR) producers typically own both the CO2 supply and the pipelines, as well as manage the EOR fields With few exceptions, the majority of these pipelines transport CO2 in a supercritical state, according to the Global CCS Institute.

The NETL projects a significant expansion in CO2 transportation over the next two decades, raising critical questions about optimizing proposed projects There are two main perspectives on future CO2 pipeline development: the first advocates for appropriately-sized pipes, which are cost-effective but limit capacity for additional suppliers, necessitating the construction of more pipelines if demand increases Conversely, oversized pipelines, though more expensive initially, provide the flexibility for multiple suppliers to transport CO2, accommodating future growth in the sector.

CO2 can be transported over time without the need for additional pipelines, potentially achieving economies of scale in unit costs According to Wang et al (2013), building oversized pipelines is advantageous when considering flow rates.

In the near term, 21 increases in flow rates are anticipated; however, without these increases, oversized pipes may remain underutilized Mechleri et al (2017) argue for the use of appropriately-sized pipelines in the UK, noting that as the fossil fuel industry's influence wanes with the rise of renewable energy, the need for oversized systems diminishes due to reduced future CO2 emissions The industry's strategic decisions regarding pipeline sizing will significantly impact market entry for various companies.

Figure 8 Map depicting the current CO2 infrastructure in the U.S Taken from Wallace et al

Louisiana CO 2 Pipeline Infrastructure

Louisiana has approximately 330 miles of CO2 pipeline composed of four individual segments with a total capacity of 38 MMt/yr, (Figure 9) As of 2017, these pipelines are all owned

Denbury Resources operates a network of CO2 pipelines primarily in East Texas for enhanced oil recovery (CO2-EOR), utilizing self-owned, naturally occurring CO2 from the Jackson Dome in Mississippi Notably, the Green Pipeline has been transporting industrial CO2 from a nitrogen plant in Geismar, Louisiana, since 2013, contributing significantly to the supply.

Figure 9 Current extent of CO2 pipelines in Louisiana Data was obtained from MAPSearch (2017) and map was created using ESRI (2017) ArcMap

Louisiana's existing CO2 pipeline capacity is significantly lower than its enhanced oil recovery (EOR) potential The pipeline infrastructure has been designed primarily to connect to the Delhi field in the north and to facilitate CO2 transport to oil fields in eastern Texas across the southern region of the state However, there are currently no lateral pipelines to enhance connectivity.

The future development of carbon capture and storage (CCS) in Louisiana hinges on the establishment of new CO2 pipeline infrastructure, particularly in the oil fields located in the southern region and the northern half of the state, which currently lack such pipelines Denbury Resources, possessing the only natural CO2 source in the area, is well-positioned to lead this development For other companies interested in pursuing enhanced oil recovery (EOR) projects in Louisiana, collaboration with the industrial sector to acquire CO2 and potential partnerships with Denbury to connect to its existing CO2 network will be essential.

CO2 pipelines will be needed in Louisiana in order to keep pace with EOR (Ambrose et al., 2009)

Denbury Resources owns several CO2 pipelines across Louisiana, U.S.A., including the West Gwinville pipeline, which was originally a natural gas line purchased in 2007 and later converted for CO2 transportation.

CO 2 PIPELINE DEVELOPMENT COSTS

Introduction

The significant expenses associated with constructing CO2 pipelines pose a substantial barrier to market entry For instance, the construction of a 140-mile, 36-inch natural gas pipeline in Washington state amounted to $822 million in 2014 Recent reports indicate that development costs can vary widely on a per-unit distance basis.

The cost of building pipelines varies significantly, ranging from $579,000 per mile for a 4-inch pipeline in Colorado to over $24 million per mile for a 42-inch pipeline in New York (Smith, 2014) Due to the substantial financial investment required for pipeline construction, operators need precise cost estimates before commencing projects While extensive cost data exists for natural gas pipelines, there is a notable scarcity of information regarding CO2 pipelines, attributed to their limited number and minimal regulatory oversight (Nordhaus and Pitlick, 2009).

Various models have been developed to estimate the costs of CO2 pipelines, as noted by Knoope et al (2013) These models primarily rely on historical data from natural gas pipeline costs, which may not pose significant concerns due to the minor differences in design specifications and engineering principles between the two types of pipelines.

(2013) have found a general cost and design characteristic common across both natural gas and

CO2 pipelines benefit from economies of scale, where larger projects reduce the unit cost of transport despite higher overall costs Various cost models, including linear and quadratic forms, incorporate parameters such as distance, volume, and pressure drop Costs are categorized into capital expenditures (CAPEX) and operational expenditures (OPEX), with CAPEX further divided into construction labor, materials, miscellaneous expenses, and right-of-way (ROW) costs Some models, like the one used by the Energy Information Administration (EIA), factor in regional differences to account for variations in terrain, climate, and resource availability.

Cost estimation for materials and products can vary significantly due to the use of different models, as highlighted by McCoy and Rubin (2008) and Knoope et al (2013) Optimizing cost models with polynomials enhances the goodness of fit, while other approaches estimate individual parameters to predict costs across various categories and regions This diversity in modeling techniques results in a broad spectrum of costs for the same specifications, leading to considerable discrepancies in cost estimation.

This study utilizes the NETL (2014) engineering-economic model to estimate CO2 pipeline costs in South Louisiana The NETL model incorporates various project-specific parameters such as distance, volume, pressure drop, and financial considerations By applying basic fluid dynamics equations, the model provides a cost-minimized estimate by determining the appropriately-sized pipeline and necessary compression based on the unique inputs of the project.

Methods

The costs associated with CO2 pipelines are mainly influenced by the distance and capacity required for transport According to industry standards, CO2-enhanced oil recovery (EOR) projects typically need to be located within 100 miles of the CO2 source to be economically viable.

In south Louisiana, an additional 5 million metric tons (MMt) of CO2 pipeline capacity is essential to support CO2-enhanced oil recovery (EOR) To assess these needs, various scenarios were modeled, examining capacities from 0.5 MMt to 5 MMt in 0.5 MMt increments, along with distances ranging from 10 to 100 miles in 10-mile intervals.

The NETL (2014) model requires selecting one of three methodologies for cost determination, and this study employs the approach established by McCoy and Rubin (2008) This method is divided into two key components, providing a structured framework for analysis.

The engineering model for determining pipe diameter and necessary compressors incorporates factors such as CO2 density at specified pressures, frictional loss, and pressure drop due to terrain Once the diameter is established, the economic model calculates costs based on FERC natural gas pipeline data Developed by McCoy and Rubin (2008), the cost model employs regression analysis with four independent cost categories and correction factors based on pipeline location The McCoy model utilizes an iterative approach to assess various pipe sizes and compressor configurations to identify the least cost solution, with additional cost inputs detailed in Table A.1.

The McCoy model estimates costs for supercritical CO2 pipeline projects by applying a 12-25 percent correction factor for pipes over 12 inches, reflecting the need for higher quality materials and labor While it assumes the use of X70 carbon steel and does not accommodate other steel grades, studies by Knoope et al (2013) indicate that the model provides moderate cost estimates compared to others Additionally, Serpa et al (2011) demonstrate that the McCoy model outperforms polynomial models in predicting costs for completed CO2 projects.

South Louisiana Pipeline Cost Estimates

The estimated cost to build a new CO2 pipeline in south Louisiana, using the NETL model, ranged from $10.6 million, for a 10 mile, 8 inch pipeline transporting 0.5MMt annually ($1.06

The estimated capital expenditure (CAPEX) for constructing a 100-mile, 20-inch pipeline that transports 5 million tons annually ranges from $27 million to $121 million, averaging $1.2 million per mile CAPEX generally increases linearly with distance, although variations occur due to the use of different pipe diameters; larger pipes are required when costs rise, while smaller pipes suffice when costs decrease Operating expenses (OPEX) also rise linearly with distance, but can fluctuate based on the number of compressor pumps needed, particularly evident at 3.5 million tons over 80-90 miles OPEX increases with added compression and decreases when compression is reduced Notably, larger projects exhibit a lower cost per unit mass transported This analysis assumes an 80% capacity factor; if the average transported capacity falls below this threshold, the costs associated with CO2 transportation will increase.

Figure 10 A) CAPEX as a cost per unit CO2 transported B) OPEX per year on a cost per unit transported

In pipeline projects, capital expenditures (CAPEX) vary slightly across four cost categories depending on project size For large CO2 pipelines (5MMt), labor accounted for the largest share at 38%, followed by materials at 29%, miscellaneous costs at 23%, and right-of-way (ROW) expenses at 9% In contrast, materials were the predominant cost factor for smaller pipeline projects.

(0.5MMt) pipelines at 34 percent, followed by labor (30 percent), miscellaneous (27 percent) and ROW (8 percent)

Figure 11 Total cost of various sized projects over various distances.

Cost Estimation Results and CO 2 Pipeline Development

The development costs for CO2 pipelines are projected at $121 million for transporting 5 million tons over 100 miles, compared to $63 million for 0.5 million tons over the same distance These costs demonstrate economies of scale, with a ratio of 5:1 or 25 percent, indicating that while larger pipelines incur higher costs per mile, they can transport significantly more CO2 Key cost drivers include distance and diameter; although longer distances increase total costs and costs per unit transported, the impact is less pronounced for larger projects For short-distance pipelines (less than 10 miles), the cost difference between small and large capacity pipelines is minimal, but over longer distances, larger diameter pipelines experience a comparatively smaller increase in costs.

CO2 pipeline segments Capacity has a small impact on costs per segment less than 10 miles but is important for pipe segments spanning longer distances

Total costs, encompassing both CAPEX and OPEX, generally increase linearly with distance across all project sizes, with the notable exception of a 3.5MMt pipe segment configured at 80-90 miles In this specific distance range, OPEX experiences a significant spike due to additional fuel expenses linked to operating an extra compressor For distances other than 80 and 90 miles, a 16-inch pipe diameter proves to be the most cost-effective option without requiring compression However, at the 80-90 mile mark, the model suggests that a 12-inch pipe is viable but necessitates the use of one compressor While the model aims to minimize CAPEX, it inadvertently leads to higher ongoing OPEX over the project's 30-year lifespan, primarily due to the costs associated with compressor operation.

Minimizing operational expenditures (OPEX) can significantly impact overall project costs, as demonstrated by the NETL model, which found that a 16-inch pipe is sufficient for transporting resources over 80-90 miles While this choice increases capital expenditures (CAPEX) by $15 million, it simultaneously reduces OPEX by $32 million over a 30-year period, ultimately lowering the total project cost The decision to focus on minimizing either CAPEX or OPEX is influenced by the configuration of the pipeline network, whether oversized or appropriately sized Notably, the NETL model does not provide results for oversized pipeline projects unless specified by the user.

Table 3 Specifications for a 3.5 MMt, 80 mile project when minimizing costs for either CAPEX or OPEX

The NETL model, which utilizes natural gas cost data and pipeline configurations, does not account for the varying contributions of cost components to CO2 pipeline CAPEX Notably, the contributions from miscellaneous and labor components decrease in CO2 pipelines compared to natural gas systems, while material contributions rise significantly CO2 pipelines incur higher material costs (29-34%) compared to natural gas pipelines (13%), due to the necessity for higher quality pipes to withstand the pressures of transporting supercritical CO2 A correction factor is applied in the NETL model to address these material differences, but it is not applied to the miscellaneous component, which remains largely procedural Interestingly, while both labor and material share the same correction factor, labor's relative contribution decreases (30-38% vs 47%) in contrast to the increase in material shares for CO2 pipelines These variations may stem from regional correction factors or project size, as the relative shares of material and labor costs differ based on CO2 project size Additionally, as project capacity increases, total costs rise uniformly across all components, with smaller projects expected to see labor cost decreases alongside material costs However, the relationship between cost and pipe diameter is logarithmic, demonstrating economies of scale where unit costs decline as diameter increases, leading to different rates of change in material and labor costs.

31 overall cost decreases with increasing size when compared to labor; a result not surprising given the capital intensive nature of pipelines and their scale economies

CO2 pipeline cost models primarily draw from data on natural gas pipeline developments, yet significant differences exist, particularly in the need for higher-grade materials for supercritical phase CO2 Despite these differences, CO2 pipelines may benefit from economies of scale, suggesting that developers should factor in the marginal costs of additional capacity during project design (Wang et al., 2013) Operating expenses (OPEX) are also influenced by compression needs, as longer transmission lines or challenging terrains require more compressors To reduce costly compression investments and OPEX, developers might consider constructing smaller pipeline segments or opting for larger pipe diameters The cost estimation method outlined here serves as a foundational reference for project development, highlighting key insights related to project size variations.

THE FEASIBILITY OF REPURPOSING NATURAL GAS PIPELINES

Introduction

Carbon capture and enhanced oil recovery (EOR) technologies are well-established; however, the infrastructure for transporting CO2 from sources to sinks remains significantly underdeveloped In the U.S., there are only 5,200 miles of CO2 pipelines, a stark contrast to the 300,000 miles of natural gas transmission lines Most existing CO2 pipelines are concentrated in west Texas for EOR, with the Rocky Mountains and Gulf Coast expected to be the next key regions for pipeline expansion Projections indicate that approximately 1,000 miles of new CO2 pipelines will need to be constructed annually until 2030 to meet the growing EOR demands in these areas Nonetheless, the development of CO2 transportation infrastructure is likely to be hindered by high construction costs, especially as expenses can reach or exceed $2 million per mile.

CO2 pipelines are emerging as innovative developments that may encounter regulatory and environmental review delays There is uncertainty about the level of public opposition these pipelines might face, similar to the controversies surrounding the Keystone XL and Dakota Access pipelines Nevertheless, given the pressing need for effective climate change solutions, such opposition may be minimal.

Reusing older or underutilized natural gas infrastructure could significantly lower development costs and efforts (Rabindran et al., 2011; Noothout et al., 2014; Onyebuchi et al., 2017) In 2016, Louisiana boasted over 24,000 miles of natural gas pipelines, highlighting the potential for infrastructure optimization (PHMSA, 2017) Additionally, the state's natural gas production capabilities further support the feasibility of this approach.

Since the 1970s, the utilization of natural gas pipelines has significantly declined, prompting concerns about their ongoing effectiveness despite many still having substantial physical lifespan remaining.

Figure 12 Louisiana natural gas infrastructure Data obtained from MAPSearch (2017)

There are a variety of incentives for using or repurposing existing natural gas pipelines for

Repurposing existing pipelines for CO2 transport significantly minimizes the need for new materials, thereby decreasing the extraction of resources from the earth and reducing landfill waste, which helps prevent land degradation Additionally, utilizing natural gas pipelines for CO2 transport lowers the high initial costs associated with establishing new infrastructure.

CO2 projects or potential CO2 transportation companies (Herzog, 2011) Third, the conversion of existing older natural gas pipelines may reduce harmful methane emission which are a significant

34 contributor to climate change and ultimately loss revenue for the natural gas operator (Kirchgessner et al., 1997)

Figure 13 Louisiana natural gas production from 1977-2015 Data retrieved from SONRIS (2017)

There are a number of special considerations for repurposing natural gas pipelines for CO2 transport use (Seevam et al., 2010; Serpa et al., 2011; Noothout et al., 2014; Brownsort et al.,

The transportation of CO2 and natural gas involves distinct physical properties, with CO2 being most efficiently transported in its supercritical phase at pressures of at least 1,070 psi, while natural gas is typically moved at lower pressures ranging from 188 to 1,493 psi To ensure effective transport of supercritical CO2, pipelines must be rated significantly above 1,070 psi to accommodate pressure drops caused by terrain and temperature variations Recommended operating pressures for transporting supercritical CO2 are between 1,200 and 2,200 psi.

2008) CO2 could be transported in its gaseous state if natural gas pipelines are not rated for supercritical CO2 level pressure, but the economies of doing so are less attractive

When considering CO2 transportation, the source of CO2 is crucial due to varying impurities such as H2S, H2O, N2, and CH4, which can impact pipeline performance by reducing transport capacity, causing corrosion, and increasing toxicity in the event of a leak Even water, a seemingly harmless impurity, can react with CO2 to form carbonic acid, leading to significant corrosion of carbon steel at rates of up to 10mm per year To mitigate these risks, CO2 pipeline operators typically require suppliers to provide CO2 with at least 95 percent purity Therefore, existing natural gas pipelines can often be repurposed for CO2 transport if the supply is dry and the pipeline can handle the necessary pressures.

There are a number of regulatory requirements associated with natural gas pipeline conversions The EIA monitors conversion projects taking place around the country (US EIA,

In recent years, the focus has shifted towards converting natural gas projects to oil or natural gas liquids, largely overshadowing CO2 conversion initiatives that receive minimal media coverage A significant point of contention is the Tennessee Gas Pipeline Company's proposal to convert its natural gas pipeline in Kentucky to transport natural gas liquids and reverse its flow (FERC Docket No CP15-88) Stakeholders have expressed serious concerns regarding the aging infrastructure, increased pressure, and the potential for spills that could contaminate local aquifers and agricultural land The primary issues

Residents believe that the pipe designated for conversion is insufficient for repurposing due to the outdated construction standards from the 1940s This concern has prompted stakeholders to advocate for enhanced regulatory oversight on conversion projects, highlighting the need for improved safety and quality standards in such initiatives.

Operators have traditionally followed 49 CFR Part 195.114 for pipeline repurposing; however, the rise in pipeline conversion projects—eleven since 2009, with only one involving CO2—has prompted regulatory agencies to introduce new guidelines The PHMSA Docket No 2014-0040 outlines essential criteria for evaluating pipelines for different commodities, including the requirement to report any changes exceeding $10 million, ensuring CO2 streams are free from corrosives, conducting internal inspections and hydrostatic tests, re-establishing Maximum Allowable Operating Pressure (MAOP), and excluding pipes with no historical records or known failures Although PHMSA notification is only mandatory for projects over $10 million, these guidelines apply to all conversion initiatives.

Repurposing natural gas pipelines for CO2 transport presents significant challenges, primarily due to the complexities involved in identifying suitable conversion candidates Various factors, including regional conditions, pricing, economic influences, and weather trends, can affect pipeline utilization Although annual usage often falls short of design capacity, certain days may see pipelines testing their maximum limits Furthermore, the network of pipelines is divided into numerous smaller segments, complicating the conversion process.

1 https://www.eia.gov/naturalgas/archive/analysis_publications/ngpipeline/usage.html

A pipeline with a design capacity of 100 tonnes per day can have varying entry and exit points along its route For instance, if 50 tonnes of CO2 are introduced at points A and C and exit at points B and D, the pipeline operates at full capacity in terms of volume delivered, yet it is only utilized at 50 percent of its total capacity.

Determining ideal candidates for conversion or repurposing of pipelines is complicated by the need to establish the Maximum Allowable Operating Pressure (MAOP) of various segments In 2012, PHMSA proposed requiring operators to maintain verifiable documentation for the MAOP of older pipelines in High Consequence Areas (HCAs) and Class 3 and 4 regions, but this information remains largely inaccessible to the public and only represents a small fraction of the overall infrastructure The National Pipeline Mapping System (NPMS), responsible for geospatial records of U.S pipelines, historically has not collected MAOP data Although PHMSA sought to incorporate MAOP into NPMS reports in 2014, industry feedback raised concerns about financial burdens and potential national security risks, leading to ongoing revisions without a final ruling as of late 2016 Consequently, while understanding MAOP is valuable, there is currently no public or regulatory database containing this critical information, which is exclusively held by individual operators.

The repurposing of natural gas pipelines to transport CO2 has been suggested by numerous authors and organizations as a way to cut costs Several government agencies have

2 Class designations are determined by proximity to population centers The higher the class designation the lower the value See 49 CFR 192.111

While some organizations have established minimum standards for converting natural gas pipelines, there is currently no comprehensive methodology available to serve as a screening tool for assessing the feasibility of repurposing these segments for CO2 transport A proposed model for this screening tool will be introduced in subsequent sections.

Case Studies

Repurposing pipelines is still a relatively new idea, and the details of the few successful

CO2 projects are relatively rare, but analyzing case studies can offer significant insights A notable example in the U.S is the West Gwinville Pipeline, operated by Denbury Resources, which converted a 50-mile, 16-inch natural gas pipeline in Mississippi to transport CO2 for enhanced oil recovery (EOR) Denbury acquired this pipeline from the Southern Natural Gas Company (SONAT), creating a mutually beneficial arrangement; SONAT sought to sell the pipeline due to declining production and decreasing revenue from natural gas transport, while Denbury aimed to utilize the pipeline for CO2 transport.

Denbury achieved significant cost savings by purchasing and repurposing a natural gas pipeline, avoiding expenses related to right-of-way purchases, materials, and construction labor The total projected cost for this project is approximately $5.2 million With 50 miles of repurposed pipeline and an expected capacity of 3.5 million tons per year, the NETL model indicates that constructing a new CO2 pipeline would have cost around $41 million, resulting in savings exceeding $35 million.

CO2 pipelines are not strictly overseen on the federal level, the West Gwinville Pipeline is a special

3 Several million dollars’ worth of upgrades were also needed to keep the pipeline in regulatory compliance adding to SONAT motivation for selling

39 case Denbury and SONAT had to go through FERC federal permitting procedures According to section 7(b) of Natural Gas Act Section 157.7 and 157.18, Southern Natural Gas had to apply for

On April 26, 2006, the "Abandonment and Sale" of the pipeline to Denbury (CP06-145) was announced As a utility company, SONAT is obligated to provide essential gas services to the public and cannot legally discontinue service to the communities it supplies Throughout the review process, various stakeholders contributed their input and concerns.

Denbury has committed to constructing a smaller pipeline as part of the purchase agreement to maintain natural gas service for a small community in northern Mississippi, ensuring that the sale does not adversely affect local services The West Gwinville pipeline illustrates the necessity for conversion projects to be mutually beneficial, and any changes will require approval from the Federal Energy Regulatory Commission (FERC) if the pipeline was initially designated as a common carrier.

Two notable CO2 conversion projects are currently underway internationally The OCAP Pipeline in the Netherlands, operational since 2004, repurposes a former oil pipeline that had been inactive for 25 years to transport CO2 This 26-inch, 51-mile pipeline delivers CO2 in gaseous form at pressures ranging from 101 to 304 psi, supplying 300 metric tons of CO2 annually from hydrogen production to local greenhouses Meanwhile, the No 10 Feeder in the United Kingdom is a natural gas pipeline designed to transport CO2 captured from the industrial sector for use in offshore carbon capture and storage (CCS).

The No 10 natural gas pipeline, measuring 36 inches in diameter and spanning 174 miles, was originally built to operate at a Maximum Allowable Operating Pressure (MAOP) of 1,160 psi However, a proposal suggests transporting CO2 at a reduced pressure of 493 psi to mitigate the risk of two-phase flow during significant temperature changes, as noted by Element Energy in 2014 Importantly, the projects do not require supercritical CO2 since their primary objective is not Enhanced Oil Recovery (EOR).

40 majority of modifications on the No 10 Feeder are for the replacement of 13 block valves The

The estimated cost for purchasing and converting No 10 Feeder ranges from $71 to $102 million, while the NETL's model indicates that constructing a new facility would amount to $217 million (ScottishPower CCS Consortium, 2011) Although transporting CO2 in its supercritical phase is the most cost-effective method, companies are increasingly opting for gaseous transport when repurposing existing pipelines This gaseous transport is particularly significant for adapting natural gas infrastructure, as it operates at lower pressures, thereby expanding the potential for repurposing opportunities.

Data and Methods

This study utilizes a concentrated geographic scope defined as Louisiana’s southernmost

South Louisiana, encompassing 38 parishes, is a key region for industrial CO2 emissions and has significant potential for enhanced oil recovery (EOR) due to its numerous oil fields and extensive natural gas pipeline infrastructure This study aims to analyze various geospatial datasets to identify pipelines that are optimally located near industrial emission sources and EOR fields The selection process will involve narrowing down potential pipelines based on their CO2 carrying capacity, pipe material, and the status of gas production in the parishes Ultimately, a comprehensive list of candidate pipeline segments will be created, and their specifications will be integrated into the NETL model to evaluate the cost-effectiveness of constructing these pipelines.

Figure 14 Step by step screening methods flow diagram

In South Louisiana, there are 66 industrial CO2 point sources identified through the 2014 USEPA GHG mapping tool A previous study recognized 62 potential Enhanced Oil Recovery (EOR) fields, which were sourced from the LDNR SONRIS GIS Access database Candidate natural gas pipelines were selected to connect these identified sources and sinks The average distance between these sources and sinks is approximately 11 miles, leading to the consideration of only those pipelines within a 10-mile radius for conversion It is more cost-effective to construct a new pipeline to the nearest sink rather than repurpose an existing one and extend it over 10 miles While several candidate segments exist within 5 miles of both sources and sinks, not all pipelines within the 10-mile range are practical The selection process was refined by eliminating segments that are critical to an operator’s overall system.

2) were nonsensical (i.e within the 10 mile buffer but would provide no useful route) or 3) where the distance needed to tie into the repurposed pipeline was greater or equal to the distance of

42 building a new pipeline straight from source to sink (see Figure A.1 and Figure A.2 for clarification)

Table 4 Data sources for proximity screen

Data Layer Source Number of Features

Candidate EOR Fields (Sinks) Identified in Advanced Resources

International (2006) and extracted from SONRIS (2017)

MAOP is not reported in a disaggregated manner, necessitating a proxy method to accurately assess the transportation capacity of candidate segments Jaramillo et al (2009) identified that five EOR projects had daily CO2 purchases ranging from 0.6 to 11.5 Mt Kinder Morgan's CO2 pipelines, with outside diameters between 16 and 30 inches, have transport capacities of 5 to 62 Mt per day For this study, only pipelines capable of supporting an EOR project with a segment capacity of at least 12 Mt were considered.

62 Mt CO2 per day The capacity of natural gas pipelines to transport CO2 can then be calculated by using the Ideal Gas Law Equation given as (2):

The Ideal Gas Law, expressed as PV=nRT, relates pressure (P), volume (V), the amount of gas in moles (n), the universal gas constant (R), and temperature (T) While this equation assumes that gases like CO2 and methane behave ideally, it's important to note that ideal gases are theoretical and do not exist in reality Nevertheless, the Ideal Gas Law serves as a useful tool for approximating the behavior of real gases under various conditions.

43 approximation of the amount of CO2 pipelines can carry (McAllister, 2005) Equation 2 will require proxies for P (MAOP) and n (Capacity) while variables V, R and T are assumed to be constant

Figure 15 Graphical view of all natural gas pipelines, industrial sources and potential EOR fields in southern Louisiana

There is no centralized source for determining the Maximum Allowable Operating Pressure (MAOP) or the necessary parameters, such as steel grade and wall thickness, for individual pipeline segments Publicly accessible information is limited to the outer diameter (OD) of the pipes However, a proxy for MAOP can be established by referencing data from previously constructed pipelines By utilizing applications from the FERC Approved Major Pipeline database, a comprehensive list of pipeline specifications has been compiled.

Between 2009 and 2017, a study analyzed the outer diameter (OD), capacity, and maximum allowable operating pressure (MAOP) of completed projects, revealing no significant correlation between OD and MAOP (β1=5.62, t-stat=1.15, p=0.2552, R²=0.033) Consequently, the average pipeline MAOP will be incorporated into the NETL model to assess whether actual operating conditions incur different costs.

4Pipe OD was gathered from the NMPS (2017) when missing from MAPSearch (2017)

The literature suggests ideal conditions of 1,200-2,200 psi, which have been modeled in Chapter 3 using consistent inputs from Table A.1, such as an 80 percent capacity This resulting Maximum Allowable Operating Pressure (MAOP) information will serve as the proxy for pressure in Equation 2.5.

Total system capacity for operators is publicly available but is not useful for analyzing specific segments Per 18 CFR 284.13, interstate and major non-interstate pipelines are required to publish design and operational capacity for meter stations on their informational websites Segment capacity, typically measured in dekatherms (dth) or occasionally in thousand cubic feet (Mcf), can be estimated by identifying meter stations that connect relevant pipe segments The operational capacity data obtained from these postings serves as a proxy for the gas amount (n) in Equation 2 By applying the FERC MAOP for pressure alongside the capacity data (n) from the informational postings, we can analyze the system effectively.

The capacity of a segment to transport gas under different pressures can be assessed by manipulating the Ideal Gas Law Specifically, the total volume of CO2 that each segment can accommodate will be calculated based on the lowest average Maximum Allowable Operating Pressure (MAOP) identified for pipelines built between 2009 and 2017, focusing on the gaseous phase.

Line Segment Selection by Pipe Characteristics

Limited spatial data exists for specific pipeline segments, but insights can be derived from the 2016 PHMSA Annual Reports Operators must report the mileage of pipes categorized by material—steel, cast iron, wrought iron, and plastic—as well as details on cathodic protection and coatings, along with installation timelines by decade The focus is primarily on carbon steel segments.

5 In the event that an unusual OD had no MAOP data from FERC applications (e.g OD 12.75 in), the lower MAOP of the next higher and lower OD was chosen.

In 2016, an analysis was conducted on 45 pipelines built after 1950, featuring cathodic protection and coatings suitable for high-pressure applications Operators will review annual reports to determine the materials used in these pipelines, the protective measures implemented, and the likely decade of construction Due to the lack of spatial data in PHMSA annual reports, only operators with a significant presence of bare steel, cast/wrought iron pipes, or those installed before 1950, as well as those with minimal corrosion protection, were considered for elimination Ultimately, this process resulted in no pipe segments being excluded from the analysis.

Selection by Natural Gas Production

The lack of detailed flow data on a per-segment basis complicates utilization analysis, as operators are only required to maintain public deliverability data for the last 120 days While transmission data can be sourced from daily deliveries, this limitation hinders trend analysis A viable proxy for assessing pipeline utilization is to analyze parish-level gas production data from SONRIS, which assumes that segments transport gas solely from their respective parishes Monthly production data from SONRIS, covering 1977 to 2016, was aggregated by year, and a percent decline was calculated based on the difference between peak year production and that of 2016, providing insights into potential underutilization of pipelines.

The final set of candidate pipe segments were the ones utilized for cost modeling purposes The final set of candidate repurposing/conversion segments were incorporated into

46 the NETL cost model in order to estimate the avoided cost of converting the identified segments to CO2 transport service.

Results

The candidate screening process for repurposing began with 5,112 pipe segments, which were narrowed down to 509 strategically located segments within a 10-mile buffer These segments represent 39 operators, covering a total of 3,234 geographic miles After eliminating integral and nonsensical segments, the ideal candidate list was further refined to 73 segments across 23 operators, collectively spanning 753 miles.

Between 2009 and 2017, most pipelines approved for construction operated at a maximum allowable operating pressure (MAOP) of 1,440 psi or less, which is notably insufficient for transporting supercritical CO2 Furthermore, linear regression analysis revealed no significant correlation between MAOP and outer diameter (OD) (β1=5.62, t-stat=1.15, p=0.2552, R²=0.033) In the absence of a significant relationship, average MAOP values were derived for specific OD measurements using the Ideal Gas Law, as detailed in Table 5.

When the NETL model was adjusted to account for the lower MAOP (1,200 to 1,400), the cost for constructing pipelines increases substantially Specifically, larger volume (5 MMt) project

30 year OPEX increased by $30 million because additional compressors would be needed over

6 Not all FERC applications contained information about MAOP, only about half of applicants report their MAOP

The cost of capital expenditures (CAPEX) increased by $3 million for shorter distances of 10 miles due to the requirement for larger diameter pipes, while projects with longer distances of 100 miles experienced similar costs for smaller volume projects (0.5 MMt).

Figure 16 509 potential natural gas pipelines within 5 miles of both a source and sink

Table 5 Descriptive Statistics: Average MAOP (psi) from pipelines completed during 2009-2017 Data obtained through the FERC Completed Pipelines Database

After analyzing daily natural gas capacity data from various operators, a list of 73 potential pipe segments was refined, primarily due to the lack of capacity reporting for intrastate pipelines Some segments were also excluded because they had been sold and their operator information was outdated in MAPSearch and NPMS The final selection of pipe segments was influenced by the screening criteria, which is necessary due to data limitations; thus, improved data could yield different outcomes The screening process identified 31 candidate segments for reconversion, with CO2 capacities ranging from 2,700 to 41,000 t/day at a maximum allowable operating pressure of 750 psi Among these, only 16 segments are capable of transporting sufficient CO2 in the gaseous phase to support an Enhanced Oil Recovery (EOR) project, covering a total of 203 miles with diameters between 6 and 30 inches, and a combined capacity of 359 Mt of CO2 per day.

Table 6 Acceptable pipeline CO2 capacity at 750 psi

Pipeline ID Diameter (in) FERC MAOP (psi) Gas Capacity

Pipeline ID Diameter (in) FERC MAOP (psi) Gas Capacity

According to PHMSA annual reports, nearly all companies operating candidate pipeline segments indicate that their pipes are both cathodically protected and coated Most of these segments were constructed between the 1950s and 1970s, with some infrastructure from SONAT and Texas Gas Transmission dating back to the 1940s Before any conversion, it is essential to conduct thorough inspections for wrinkle bends in the selected pipe segments, eliminating the need for further reduction in the number of candidate segments For additional insights into an operator's overall infrastructure, refer to Table 7.

Table 7 2016 PHMSA Annual Report data presented by operator as percent of total infrastructure

Cathodic Protection and Coating (percent)

Natural Gas Pipeline Company of America

Gas production across the 38 parishes of south Louisiana has significantly decreased, with all experiencing declines of at least 58 percent since peak levels Notably, only four parishes—Beauregard, St Martin, Evangeline, and Calcasieu—have seen declines of less than 80 percent, while 32 parishes have suffered declines exceeding 85 percent Furthermore, all 16 candidate pipe segments are situated in parishes that have experienced a minimum decline of 83 percent, indicating that these segments are likely underutilized and that no additional reductions in candidate segments are necessary.

The NETL model analysis revealed that constructing 203 miles of new pipeline would incur a capital expenditure (CAPEX) of $168.85 million, equating to approximately $830,000 per mile Detailed segment lengths and costs for each origin-destination (OD) are outlined in Table 8, while Figure 17 illustrates the final candidates for natural gas repurposing.

Table 8 Capital costs to build new the 16 segments of pipeline identified as ideal candidates for repurposing Costs developed using the NETL model

OD (in) Length (miles) Cost to build new ($)

51 Figure 17 Natural gas pipelines identified as ideal candidates for repurposing to transport CO2 and their location with respect to sources and sinks.

Empirical Results

The U.S natural gas infrastructure built between 2009 and 2017 is generally inadequate for transporting supercritical CO2, as most pipelines were designed for operation at 1,440 psi or less, while supercritical CO2 pipelines typically require 2,200 psi and must maintain at least 1,200 psi throughout Although the existing infrastructure may not meet these requirements, it can still be repurposed through two main options: increasing the number of compressors to reduce the distance between compressor stations or enlarging the pipe diameter While the latter option is more cost-effective, it entails a higher initial investment Overall, while the current infrastructure is rated below the necessary standards for supercritical CO2 transport, repurposing remains a viable, albeit expensive, option.

A viable option for enhancing natural gas pipeline efficiency is to recertify existing segments to operate at supercritical pressures without incurring additional costs By increasing the design factor from the current 72 percent of SMYS to 80 percent, the maximum allowable operating pressure (MAOP) could rise to approximately 1,600 psi (Kuprewicz, 2006) This 8 percent increase in design factor demonstrates that the costs associated with CO2 pipelines operating at pressures between 1,200 and 1,600 psi are comparable to those at 2,200 psi.

53 psi is still well below the recommended pressure for supercritical CO2 transport, it would alleviate the need for additional compressors in the environment and distances needed in south Louisiana

Transporting CO2 in its gaseous phase presents a viable repurposing option, as many existing pipelines have sufficient capacity to support Enhanced Oil Recovery (EOR) projects, even at lower pressures of 750 psi Research by Brownsort et al (2016) indicates that while transporting CO2 in the gaseous phase is generally less economical than in the supercritical phase, it remains a cost-effective alternative compared to constructing new high-pressure pipelines This is particularly significant for smaller oil and gas operators, who may lack the financial resources to build extensive transportation infrastructure If these smaller companies can profit from repurposing existing natural gas pipelines, the potential for growth in the CO2 transportation market could increase substantially.

The methodology for calculating capacity presented here serves as a conservative estimate, primarily due to the selection of 750 psi as the Maximum Allowable Operating Pressure (MAOP) for all pipelines, which reflects the lowest operating pressure observed in natural gas pipelines built in the past eight years Additionally, the capacity proxy relies on reported data from meter stations at receipt and delivery points, which only captures the actual or average volume of natural gas flowing during specific reporting periods, potentially overlooking variations in flow.

Transporting CO2 in its gaseous phase is unsuitable for Enhanced Oil Recovery (EOR) since EOR requires CO2 to be in a supercritical state To facilitate this process, compression must occur at the injection site, a critical factor overlooked in the NETL model Addressing this consideration is essential for the successful implementation of future projects.

The estimated potential additional capacity may be inflated due to the assumption that methane and CO2 behave as ideal gases To improve accuracy, the van der Waals equation could be employed, as it incorporates correction factors for the unique molecular structures of these gases However, this gas-specific equation can be complex and presents its own methodological challenges, making it unnecessary for generating first-order estimates.

According to PHMSA Annual Reports, the pipelines examined in this study are primarily made of steel with protective coatings and cathodic protection, with only 0.7 percent of Louisiana’s transmission pipelines lacking such measures This aligns with PHMSA’s initiative to replace unprotected steel, cast, and wrought iron pipes, as many states are actively removing these older distribution pipelines Additionally, the age of pipelines is a significant concern, particularly for the dominant systems in south Louisiana, SONAT and Texas Gas Transmission Pipelines constructed before 1950 are particularly vulnerable to the relic pipe bending process, which can create wrinkle bends; any such segments found must be thoroughly inspected and should not be considered for repurposing if defects are present.

Ideal Natural Gas Pipelines for Conversion to CO2

It is important to remember 73 candidate pipelines are estimated to be ideally located near a source and sink but only 31 segments had enough information available to be used in the

8 https://www.ferc.gov/industries/gas/indus-act/pipelines/approved-projects.asp

The Ideal Gas Law equation is utilized for estimating capacity, revealing significant potential for repurposing in the 42 segments previously excluded from consideration Approximately half of the 31 segments with complete data were found to possess adequate capacity to transport CO2 volumes necessary for sustaining an Enhanced Oil Recovery (EOR) project If these findings are consistent across all segments, it suggests that 21 additional segments from the excluded candidates could be integrated into the final list of 16 segments Should further information confirm this trend, the broader implementation of repurposing natural gas pipelines may become viable.

Overall, the 16 pipelines identified in this study are expected to have a total capacity of

In 2014, 21 industrial sources within 10 miles of selected pipelines produced 10.7 million tons of CO2 daily, amounting to 359 million tons The chosen pipelines can accommodate all this CO2, utilizing only 8% of their capacity However, an analysis reveals that while many pipelines are capable of supporting an Enhanced Oil Recovery (EOR) project, they may not receive adequate CO2 supply from nearby sources or could be over-supplied Although additional CO2 can be sourced from other industries and not all needs to be purchased, this study indicates that the selected pipelines may not efficiently transport CO2.

This study analyzed two case studies to evaluate capacity and cost estimates, focusing on Denbury Resources and the No 10 Feeder repurposing projects These projects demonstrated significant cost savings, achieving reductions of 88% and 68% on capital expenditures (CAPEX), respectively With the projected expenses for constructing 16 identified pipeline segments in South Louisiana, companies could potentially save between $114 million and more, highlighting the financial benefits of repurposing existing infrastructure.

Repurposing pipelines could yield significant savings, with an estimated $148 million in capital expenditures (CAPEX) However, the potential savings remain uncertain due to the limited number of conversion projects and the challenges in accurately modeling the costs of constructing new pipelines Consequently, it is advisable to consider a range of estimates rather than relying solely on a single point estimate for the capacity and costs associated with repurposed pipelines.

Table 9 Percent of CO2 capacity by segment from industrial sources within 10 miles of each segment

Pipeline ID CO2 Capacity at

The study reveals a significant lack of information regarding segment MAOP, installation year, material, and capacity of pipelines, which is crucial for repurposing decisions, land management, emergency response, and energy industry analysis The analysis highlights the active pipeline market, with notable transactions such as the 2014 sale of Bridgeline Holdings L.P to Enlink Midstream and Chevron Pipe Line Company, encompassing approximately 1,400 miles of pipeline Understanding pipeline design specifications and history is essential for effective management and safety protocols in the energy sector.

The potential loss of 57 records may leave operators uncertain about their infrastructure's design specifications, particularly regarding the Maximum Allowable Operating Pressure (MAOP) Linear regression techniques failed to establish a significant correlation between outside diameter (OD) and MAOP, likely due to the diverse options in pipe materials and varying numbers of compressors For instance, U.S Steel Tubular Products provides pipes with an OD ranging from 1.9 to 24 inches, each with multiple wall thicknesses and grades, leading to a wide range of MAOP values—such as 640 to 2,900 psi for a 20-inch pipe Consequently, accurately determining a specific pipe's MAOP without operator-specific information appears nearly impossible This information may become mandatory in future regulations from the PHMSA under rulemaking Docket No 2014-0092.

Only 1.4 percent of the 5,112 pipeline segments in South Louisiana are co-located near both a sink and a source, indicating potential for repurposing Among the identified candidate conversion segments, roughly half can transport sufficient CO2 for a typical Enhanced Oil Recovery (EOR) project The 16 segments highlighted in this study account for less than one percent of Louisiana’s overall natural gas infrastructure, a surprising finding given the state's extensive network This suggests that the conservative methods used in this analysis may yield similarly limited candidate opportunities in other states with less fossil fuel production history and infrastructure While Denbury Resources successfully repurposed a pipeline in Mississippi, that state has minimal crude oil production compared to Louisiana.

9 https://usstubular.com/connections/sl/

Repurposing natural gas pipelines presents several challenges, including the necessity for the current owner to be willing to sell, as seen with Denbury Resources Additionally, the pipeline must pass an inline inspection to ensure it is free of malformations, a requirement that posed issues for the Tennessee Gas Company Approval from multiple government levels is essential to confirm that the pipeline's sale won't infringe on natural gas purchasing rights or harm the environment For repurposing to be a viable large-scale mitigation strategy, all these factors must align This study supports the findings of Onyebuchi et al (2017), which indicated that repurposing may only be practical during the interim period before new CO2 pipelines are built.

LOCALIZED BOTTOMS-UP PIPELINE CONVERSIONS

Introduction

The previous section of this research detailed a "top-down" methodology for screening and identifying natural gas pipelines suitable for repurposing to CO2 transportation This approach utilized systematic equations and assumptions to estimate the capacity and costs associated with CO2 pipeline repurposing However, like all modeling techniques, its effectiveness relies on the availability of accurate data and assumptions, which is crucial for evaluating a large number of regional natural gas pipelines It is important to note that approximately half of the candidate pipeline segments identified lacked sufficient information, resulting in their exclusion from the final capacity and cost estimation process.

This research section adopts a "bottoms-up" approach to identify candidate natural gas pipeline segments for repurposing for CO2 transport By focusing on a smaller study area, selected sources and sinks, and a more relaxed selection process, this method aims to deliver a more detailed and comprehensive set of results compared to previous models The findings from this bottoms-up analysis will be compared with earlier results to identify limitations and potential biases in the previously discussed methodology.

Bottoms-Up Methods

The bottoms-up method uses a combination of data for CO2 industrial sources (US EPA,

2017) and potential EOR fields (SONRIS, 2017) with natural gas pipeline infrastructure MAPSearch

(2017) to determine the number of repurposing opportunities available within a focused study

The analysis focused on a limited number of enhanced oil recovery (EOR) fields and industrial sources, rather than considering all potential sources and sinks Repurposing opportunities were categorized by various spatial scales, beginning with the systematic elimination of nonsensical pipelines that did not connect sources to sinks This process also accounted for indirect routes formed by connected pipe segments outside the designated buffer After identifying the candidate pipelines, key characteristics were collected from PHMSA reports, with the analysis conducted using ESRI ArcMap software.

This study focuses on two promising Enhanced Oil Recovery (EOR) fields in south Louisiana: Bayou Sorrel and Paradis Both fields, identified as suitable for EOR operations, are part of a U.S Department of Energy-funded study aimed at developing a pre-feasibility assessment for Carbon Capture and Storage (CCS) Bayou Sorrel, located in Iberville Parish, was discovered in 1954, with peak oil production reaching 11 billion cubic feet (bcf) in 1999, declining to 152,000 thousand cubic feet (Mcf) by 2016 Similarly, Paradis, found in Saint Charles Parish, also discovered in 1954, peaked at 2.8 bcf in 1977 and decreased to 193,000 Mcf in 2016 The study selected eight industrial emission sources due to their proximity to the EOR fields and relatively pure CO2 emissions, with emissions ranging from 62,000 to 7,980,000 tonnes CO2 equivalent in 2015, representing a mix of natural gas refining activities.

10 Estimates of specific field peak production may not be accurate because electronic records are only available starting from 1977 but the state peaked as a whole in 1970 (Kaiser, 2010).

61 and hydrogen and ammonia production (US EPA, 2017) The next step in the process was to estimate the average distance between each EOR field and its three closest industrial sources

The natural gas pipeline infrastructure in Louisiana was analyzed using MAPSearch (2017) to identify all commodity pipelines, specifically focusing on natural gas lines By combining three data sources, a graphical representation of the pipeline infrastructure near sources and sinks was created Various buffer sizes (1, 5, and 10 miles) were applied to assess the number of pipeline segments, total mileage, and different operators at multiple spatial scales The analysis within the 10-mile buffer allowed for a systematic narrowing of acceptable pipelines by grouping segments by operator and visually verifying routes between sources and sinks Unlike the previous top-down method that strictly examined direct routes within both source and sink buffers, the new bottoms-up approach considers pipelines in either buffer, thus incorporating segments with indirect routes that connect through a more extensive network of pipelines outside the immediate area.

The PHMSA 2016 Annual Reports provide key insights into the characteristics of selected pipelines, with two distinct reports focusing on gathering and transmission lines, and another solely on distribution PHMSA differentiates these three systems due to variations in gas purity, pressure, and end users Although the annual reports lack geospatial data, they effectively present the total miles of pipelines categorized by operator and type, including factors such as installation decade, material used, and corrosion protection measures.

The analysis focuses on coatings and cathodic protections for pipelines, applicable to both onshore and offshore locations Although not explicitly tied to specific segments, the operator-specific data provides insights into which pipelines require more thorough inspections or can be disregarded Similar to the top-down method, this bottom-up approach targets segments constructed after the 1950s, utilizing steel materials and incorporating corrosive protections The findings will be presented as a percentage of the total infrastructure by operator.

Figure 18 Industrial sources of CO2, potential EOR fields and natural gas infrastructure.

Results

Paradis and Bayou Sorrel are located an average of 10.3 miles and 22.4 miles, respectively, from their three nearest industrial CO2 sources The natural gas pipeline infrastructure within different sized buffers is illustrated in Figure 19.

The 10 mile buffer contains over 1,830 miles of potential natural gas pipelines, while the 1-mile buffer only contains 435 miles of natural gas pipelines As the geographical scope becomes

63 smaller, obviously, fewer pipeline segments and less mileage are available Complete details by individual buffer zone can be found in Table 10

Figure 19 Available natural gas pipelines at various geographical scales (10, 5, and 1 mile zones)

Table 10 Available pipeline characteristics by Buffer Zone

Length (miles) Diameter (in) Number of

Within a 10-mile radius of a source or sink, there are initially 359 possible pipe segments However, after removing impractical segments and those that do not create a viable route between the source and sink, the count is reduced to 189 acceptable pipe segments, spanning a total distance of 1,020 miles.

The analysis covers a distance of 64 miles, with several acceptable segments linked to pipelines beyond the ten-mile buffer Although these external segments are not reflected in the provided figures, their acquisition is essential for repurposing the selected pipelines, as illustrated in Figure 20 Detailed characteristics of the acceptable segments by operator are available in Table 11.

The acceptable pipelines within a 10-mile radius of a source or sink are interconnected by a network of pipelines, as illustrated by the green lines, rather than running directly between the source and sink.

Table 11 General characteristics of acceptable pipeline by operator

Operator Number of Segments Mileage

The majority of selected pipeline segments consist of gathering and transmission lines, with only a small percentage being distribution lines According to annual reports by PHMSA, over 97 percent of the gathering and transmission lines owned by these operators are equipped with coatings and cathodic protection Most of these pipelines possess the optimal characteristics necessary for efficient transportation.

Over 30% of the pipelines operated by Cypress Gas Pipeline and Gulf South Pipeline Company were installed before 1950 or have unknown installation dates Atmos Energy Louisiana Company and Evangeline Gas Corporation are the primary local distribution companies (LDC) in the area While distribution line data indicates that both companies have low levels of corrosive protections, this is largely due to the significant amount of plastic piping included in the assessment When excluding plastic pipes, it is found that 100% of Evangeline’s steel pipes and 95% of Atmos Energy’s steel pipes have corrosive protections A critical concern for the selected gathering systems is their age, as the installation year for 100% of Evangeline’s pipelines remains unknown.

12 provides complete details on these segments

Table 12 Percent of mileage pre-1950s pipe and corrosive protection of acceptable pipelines by operator Data obtained from 2016 Annual PHMSA Report

Cathodic Protection and Coating (percent)

Carbon Steel (percent) Gathering and Transmission

Cathodic Protection and Coating (percent)

Carbon Steel (percent) Gathering and Transmission

Discussion

The bottoms-up methodology identified a greater number of potential natural gas pipelines for repurposing by employing a focused segment-by-segment analysis This approach allowed for a more relaxed selection process, leading to the acceptance of additional pipelines However, due to time constraints, this method cannot be applied to the entire dataset, as it requires examining each segment individually alongside a vast number of sources.

The bottoms-up approach faces challenges due to the significant distances between CO2 sources and sinks, with Bayou Sorrel and Paradis located over 20 and 10 miles away from their nearest CO2 sources, respectively While Paradis aligns more closely with the design study from the tops-down analysis, Bayou Sorrel's distance is notably greater The National Energy Technology Laboratory (NETL) has estimated that the capital expenditure (CAPEX) required to construct a direct pipeline with an annual capacity of 4.38 million metric tons from either Bayou Sorrel or Paradis to their closest CO2 source would amount to $14.3 million.

Bayou Sorrel and Paradis have the potential to save between $9.7-$12.5 million and $5.8-$7.5 million, respectively, through the conversion of existing pipelines The longer distances involved in connecting Bayou Sorrel to its nearest sinks necessitate the purchase of more pipeline segments, which can be costly and may disrupt natural gas operations In contrast, repurposing pipelines near Paradis is more feasible due to the reduced length required, making it a more economical and less disruptive option Therefore, the distance between the source and sink is a critical factor for operators to consider when planning a successful CO2 conversion project.

Using a relaxed, bottoms-up methodology for pipeline selection can present challenges, as many identified segments may require additional segments outside their immediate buffer to be effective This approach often leads to the inclusion of pipelines without a direct route from source to sink, resulting in a greater length of pipe needed for repurposing Natural gas operators may hesitate to remove significant portions of their systems, making these indirect pipelines less appealing A potential solution involves piecing together smaller segments from various operators and constructing new connections as necessary; however, this complicates the process due to the involvement of multiple operators Ultimately, whether acquiring a large pipeline section from a single operator or assembling smaller segments from several, this relaxed methodology may be less beneficial than focusing on segments with direct routes, as seen in a top-down analysis While broadening the selection criteria offers more options, it often comes at the expense of increased segment length and a more complex ownership transfer process.

The positioning of select sources and sinks, particularly with the notable exception of CF Industries, highlights a significant case study due to their placement on opposite sides of the Mississippi River This geographical factor impacts both design specifications and costs, as pipelines typically avoid direct crossings and instead run parallel to the river until suitable crossing conditions arise, such as existing rights-of-way Additionally, operators must drill horizontally beneath the river due to its vast size, which adds complexity and increases construction costs through longer pipe lengths and more intricate processes The challenges associated with crossing major water bodies were exemplified by the Dakota Access Pipeline's crossing of the Missouri River, which attracted international scrutiny, extended construction timelines, and escalated expenses Consequently, pipe segments that traverse significant waterways are likely more valuable than those on land, leading natural gas operators to be hesitant in relinquishing these portions Future research should focus on sources and sinks that do not involve major water crossings.

When considering the repurposing of pipelines for CO2 transport, key factors include the material, corrosion protections, and the age of the pipelines This study found that over 95 percent of the steel pipelines analyzed have effective corrosion protections, making them suitable for CO2 transport However, a significant concern arises from the high volume of plastic pipelines owned by Atmos Energy and Evangeline Energy Company, as these local distribution companies (LDCs) typically use these lines for distribution Since plastic pipes generally operate at pressures below 100 psi, they may not have the capacity required for CO2 transport, potentially limiting their viability for enhanced oil recovery (EOR) projects.

The 69 symptom indicates a broader issue with distribution lines, which primarily serve communities and legally obligate operators to provide natural gas Repurposing these lines is challenging, as it necessitates implementing mitigation measures to maintain service continuity For instance, Denbury Resources had to construct a new, smaller pipeline to ensure ongoing natural gas supply Additionally, the era in which the pipeline was built influences its potential for repurposing.

Approximately 30% of the infrastructure for both the Cypress Gas Pipeline and Gulf South Pipeline Company was installed before 1950 or lacks documented installation dates Pipelines constructed prior to the 1950s often exhibit bending practices that can lead to wrinkle bends, which weaken the steel and heighten the risk of incidents The PHMSA advises against repurposing pipelines with insufficient historical records, including those with unknown installation dates (PHMSA Docket No 2014-0040) Although older pipelines may be acceptable if subjected to thorough inspections or testing, the current methodology aims to offer various alternatives when design issues are identified.

The traditional top-down analysis methodology, while effective for survey studies, offers limited outcomes for repurposing CO2 transport pipelines This study introduces a more flexible approach, focusing on a select few sources and sinks, allowing for the inclusion of segments that provide indirect CO2 transport routes However, this relaxed selection process may lead to impractical segments upon closer inspection Additionally, the research uncovers important aspects of pipeline conversions that the top-down analysis overlooks.

Key findings indicate that avoiding major river crossings and eliminating plastic and distribution lines are crucial to facilitating the conversion process By relaxing the selection methodology, more segments can be evaluated for a specific source or sink; however, it is essential that each segment undergoes a comprehensive inspection.

The analysis reveals that regardless of the approach taken in the pipeline screening process, the availability of pipe segments suitable for repurposing is restricted The conversion of natural gas infrastructure for CO2 transportation appears to be a specialized application, applicable only in select locations and circumstances Therefore, it is essential to moderate the optimism surrounding the repurposing of natural gas pipelines.

CONCLUSIONS

The study focuses on the pipeline infrastructure necessary for transporting CO2 from industrial sources to enhanced oil recovery (EOR) sites, highlighting that CO2-EOR operators will need to construct 1,000 miles of pipeline annually until 2030 to meet demand, particularly in the Gulf Coast region It suggests that repurposing existing natural gas pipelines could significantly reduce the high costs associated with new pipeline development The research specifically investigates the potential for utilizing the extensive natural gas infrastructure in south Louisiana for this purpose.

Repurposing natural gas pipelines for CO2 transport is feasible due to the similarities in construction practices, though CO2 requires pipelines that can handle higher pressures exceeding 1,200 psi This necessitates the use of higher grade steel, which increases costs compared to natural gas pipelines Additionally, regulatory oversight differs significantly; while natural gas pipelines are strictly regulated by the FERC as common carriers, CO2 pipelines primarily follow PHMSA guidelines, leaving much of the construction regulation to individual states.

The costs associated with constructing CO2 pipelines for enhanced oil recovery (EOR) in South Louisiana are influenced by the volume of CO2 transported and the distances involved While larger projects may incur higher total costs, they benefit from economies of scale, resulting in a lower cost per unit transported However, the need for higher pressures in supercritical CO2 transport necessitates either additional compressors or larger diameter pipes, both of which contribute to increased overall expenses Although opting for a larger pipe diameter is the more cost-effective solution over the project's lifespan, it demands a significant upfront investment Given the high costs and the early stage of these projects, operators must explore alternative strategies to reduce expenses.

Repurposing abandoned or underutilized natural gas pipelines for CO2 transport presents a cost-effective solution to reduce capital expenditures (CAPEX) This research introduces a comprehensive top-down model to assess the feasibility of large-scale pipeline conversion projects The findings highlight significant development challenges, primarily the scarcity of public information and data regarding natural gas pipelines Currently, the Pipeline and Hazardous Materials Safety Administration (PHMSA) is the sole government agency collecting nationwide pipeline data, but this information is restricted to location details.

The Pipeline and Hazardous Materials Safety Administration (PHMSA) currently provides pipeline data on a county-by-county basis, making it nontransferable and limiting accessibility The author recommends that PHMSA enhance its data collection efforts to include crucial details such as Maximum Allowable Operating Pressure (MAOP), installation year, and material type This information is vital not only for repurposing pipelines but also serves as an essential resource for emergency responders, industry analysts, and land managers.

Recent studies indicate that transporting CO2 in its supercritical phase is typically the most cost-effective method However, an analysis of pipelines constructed in the past eight years reveals they operate at substantially lower pressures than the standard recommendations This discrepancy raises questions about the efficiency and effectiveness of current CO2 transport practices.

Transporting CO2 in the supercritical phase through pipelines operating at 1,400 psi is not feasible due to higher CAPEX and OPEX costs, necessitating larger pipes or additional compressor stations However, repurposing pipelines for gaseous CO2 transport remains a viable alternative, as demonstrated by the development of proxies for MAOP and pipeline capacity that support Enhanced Oil Recovery (EOR) operations A limitation of gaseous transport is its lower pressure, which reduces the number of pipelines suitable for repurposing and may hinder EOR project sustainability Nonetheless, if Louisiana aims to capitalize on repurposing natural gas infrastructure, gaseous transport is likely to be the most feasible option moving forward.

While the rigid top-down methodology can be applied universally, it tends to be most effective in states with a history of fossil fuel production, like Louisiana In contrast, the bottoms-up approach emphasizes a few select sources and sinks, utilizing a more flexible methodology that incorporates pipelines as indirect routes This relaxed approach identifies more pipeline segments suitable for repurposing, but it risks overestimating available options and complicating the sorting process Ultimately, whether employing a rigid or relaxed methodology, the prospects for successful pipeline conversion projects remain limited.

Repurposing natural gas infrastructure is considered a cost-effective strategy to promote Enhanced Oil Recovery (EOR) while addressing climate change challenges.

The research conducted by Onyebuchi et al (2017) revealed limited options for repurposing infrastructure in south Louisiana, which was unexpected given the extensive existing systems in the region While there are a few success stories globally, they appear to be exceptions rather than the norm The conversion of pipelines for CO2 transport is anticipated to be a niche application Despite this, promoting repurposing as a viable option is important due to its various indirect benefits; however, it is unlikely to serve as a major tool for mitigating climate change.

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On March 30, 2017, an article on the Maripositas blog discussed the role of organic carbon dioxide in plant assimilation, emphasizing its significance in horticulture Additionally, van der Zwaan et al (2011) provided an overview of the economic aspects of transporting methane (CH4), carbon dioxide (CO2), and hydrogen (H2) as part of climate change mitigation strategies, highlighting the costs associated with these processes in their study published in Applied Energy.

Zhang, Z.X., G.X Wang, P Massarotto and V Rudolph 2006 Optimization of pipeline transport for CO2 sequestration Energy Conversion and Management 47:702-715

APPENDIX: SUPPLEMENTAL DATA Table A.1 Inputs used for the NETL model and associated units

Cost of Equity (minimum internal rate of return on equity or

Cost of Debt (id) 0.045 Percent

Depreciation method (DB150 – 150 percent declining balance or

Recovery period for depreciation (15 or 20 years) 15 Years

Starting Calendar Year for Project 2011

Duration of Construction in years 3 Years

Duration of Operation in years 30 Years

Indicate equations to use for capital cost of natural gas pipelines McCoy

Region of US or Canada SW

Figure A.1 Segments which are integral to an operator's overall system (yellow) were excluded from the analysis This study included laterals of the ends of pipelines (blue)

Figure A.2 Segments were excluded from the analysis if they did not provide a direct route from source to sink

Figure A.3 illustrates acceptable pipelines within a 10-mile buffer zone While not all pipelines directly connect to a source or sink, they are still considered acceptable if linked by an external piping system beyond the buffer limit.