The system-wide economics of a carbon dioxide capture, utilization, and storage network: Texas Gulf Coast with pure CO₂-EOR flood

Table 1 shows the four scenarios that are combinations of two operational scenarios and two economic scenarios. This approach provides a means to explore some bounding cases to provide perspective on different CO₂ price and emissions penalty scenarios such that information exists to contemplate possible business relationships and overall system economics.

The 'slow' and 'fast' operational scenarios describe the rate of oil production from the modeled candidate EOR fields. The 'slow' scenarios are designed such that oil is developed over a 20-year time span and the annual needed delivery of CO₂ is approximately constant. In this sense, the 'slow' scenarios approximate an optimal situation for a coal-fired power plant owner that must invest in CO₂ capture capital equipment and wishes that investment to be fully utilized until fully amortized. The 'fast' scenarios are defined such that all EOR fields drill all wells, install all capital, and begin operations at all wells at the beginning of the 20-year period (within the first three years). In this sense, the 'fast' scenarios approximate an extreme case for capital investment of EOR developers in that they would produce the oil as fast as possible (though not necessarily a realistic business case). These 'fast' scenarios estimate an upper bound on the total quantity of capital investment for the whole system in that much more capital is needed to deliver larger quantities of CO₂ during the first few years relative to all years in the 'slow' scenarios. The 'fast' scenarios necessitate larger capital investment for all three parts of the CCUS network: CO₂ capture, pipelines, and oil/CO₂ storage field operations. For a given injection and production well pattern, our CO₂-EOR model (using the Prophet program) models some delay in oil production relative to the delivery of CO₂ to allow for buildup of pressure.

The 'CO₂ sales price' and 'CO₂ emissions penalty' economic scenarios capture two commonly discussed options for reducing CO₂ emissions with different dynamics. They represent internal (CO₂ sales) or external (CO₂ emissions penalties) economic drivers to encourage investment in the CCUS network. In the 'CO₂ sales price' scenarios, there is no penalty (e.g. tax) for emitting CO₂ to the atmosphere, and the 'CO₂ sales price' is that price that an EOR operator pays to the coal-fired power plant for CO₂. Thus, the customer that buys electricity and/or oil does not (in large) notice the effect of this CO₂ sales transaction (via impacts on electricity or oil prices) that is internal to our modeled CCUS network. On the other hand, the 'CO₂ emissions penalty' cases represent the impact upon the modeled CCUS system of a penalty for the CO₂ emissions from burning fossil fuels consumed (for electricity) or produced (for oil) by our modeled CCUS system. Thus, an electricity or oil products (e.g. gasoline) customer would more directly notice price increases in the 'CO₂ emissions penalty' cases, but we do not model any price-related feedbacks on energy demand.

To estimate the CO₂ injection and oil production profiles for an inverted five-spot pattern⁶, we used CO₂-Prophet, a CO₂ flood prediction software that generates streamlines between injectors and producers and estimates displacement and recovery through a finite difference routine. One of the motivations of this work is to consider economic scenarios handling large volume flow rates of CO₂, so our EOR modeling in Prophet is based upon continuous CO₂ injection, not the more common EOR practice of WAG where both water and CO₂, the 'gas', are injected through the same wells in an alternating manner over the life of the well. The choice of EOR candidate fields comes from a coauthor's previous assessments and represents fields with a range of sizes and qualities (Nuñez-Lopez et al 2008). The fields are not specifically chosen to be the most or least profitable prospects. In addition, four of the EOR fields are in south Texas near the Corpus Christi area, and the other six EOR fields lie closer to Houston. Thus, we have included some geographic diversity to consider the connectivity of coal-fired plants in different regions of the state (see figure 1). Table S1 of the supplementary information (available at stacks.iop.org/ERL/8/034030/mmedia) lists the EOR fields, along with the number of wells (oil production, CO₂ injection, and water injection) assumed for each field.

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The assumed profiles for CO₂ and oil flows are based upon recent CO₂-EOR activity in a Texas Gulf Coast oil field (Davis et al 2011). This particular oil field development is somewhat unique in that it employs continuous CO₂ injection, just like we do in our modeling. We do model some water injection wells, but these water injection wells are meant to create a 'curtain' of water and pressure at the edge of the displacement area that minimizes CO₂ loss from the targeted part of the reservoir (Davis et al 2011).

Based on limited CO₂-EOR experience in the US Gulf Coast, specifically related to projects where only CO₂ is continuously injected (not WAG), our main assumptions for EOR are that (i) injection continues until either 20 years is reached or a total quantity of CO₂ injected is an amount equal to 500% of the hydrocarbon pore volume (HCPV) of each reservoir (Davis et al 2011), (ii) approximately 12–16% of the original oil in place (OOIP) is recovered from each field, and (iii) that CO₂ injection occurs at a pressure that is 90% of the fracture pressure of the reservoir. For each well pattern, the injection pressure assumption models the oil production in a close to 'as fast as possible' manner. By staggering the dates to start each pattern of wells, we can design various plans for the development for the entire oil field over time. The supplemental information (available at stacks.iop.org/ERL/8/034030/mmedia) details the capital and operating costs models for well drilling and operation of CO₂ injection and oil production wells. Table S2 of the supplementary information (available at stacks.iop.org/ERL/8/034030/mmedia) lists the oil recovery, CO₂ delivery, and time period of oil production for each EOR field.

Major assumptions for assessing the capital and operating costs for CO₂-EOR are as follows (see the supplemental information for more details).

• Drilling costs. Drilling costs of both oil production and CO₂-EOR injection wells are assumed at 50% of the cost of drilling a new well. This capital cost assumption translates to our assumed use of existing oil production and water injection wells at the EOR candidate fields and that reworking and/or side-track drilling the wells is estimated at half the cost of a new well. Analysis of data in the Joint Association Survey on Drilling Costs supports the idea that wells drilled by side-tracking cost 40%–80% of the cost of a newly drilled well.
• Lease costs. Lease costs are a combination of costs for primary oil production and additional lease costs for CO₂-EOR. We largely follow the method described in ARI (2006) as outlined in the supplemental information.
• CO₂ recycling capital. We assume the full capacity capital costs ($700 000 per peak million cubic feet per day of recycled CO₂) of a CO₂ recycling plant at each EOR field occur during the year that CO₂ recycling is first required. We do not assume the CO₂ plant is upgraded or expanded at any time but it is installed a full capacity even if full capacity is not needed until several years later.
• Electricity and lifting. The quantity of electricity for compressing and pumping CO₂ follows the McCullom and Ogden method for CO₂ compression to supercritical and higher pressures as needed for EOR operations (McCullom and Ogden 2006). Other lifting electricity needs come from (ARI 2009).
• General and administrative costs. Additional costs administrative costs are added equal to 20% of lifting plus both water and CO₂ injection costs (per ARI 2006).

Major assumptions in assessing the capital and operating costs for CO₂ injection into saline reservoirs are as follows (see the supplemental information for more details).

• Drilling costs. The capital drilling costs for CO₂ saline injection wells are assumed the same as the full cost of drilling a new oil well.
• Lease costs (capital and O&M). Both capital and O&M lease costs are assumed equal to the additional lease costs for CO₂-EOR.
• CO₂ pumping electricity. The CO₂ arrives to the saline injection site in supercritical condition in the pipeline, and additional CO₂ pumping electricity is assumed at 5 kWh/BBL of supercritical CO₂ (ARI 2009).

Because the foci of this analysis are the coal-fired power plants with CO₂ capture and EOR/CO₂ storage operations, each scenario uses a relatively simple pipeline network assumption that is not a complete analysis of the requirements for operating the pipeline network. We do not calculate needs for booster pumps or specifically estimate pipeline operating electrical demands. For the construction costs of the pipelines, and determination of the diameter of the pipeline for a given CO₂ flow rate, we follow previous methods (Herzog and Javedan 2010). The sizing and capital cost model for the pipeline is detailed in the supplemental information. Figure 1 shows the conceptual layout of the pipeline network for both the 'slow' and 'fast' scenarios.

This work uses a first-order electricity dispatch model to estimate the wholesale electricity price and dispatch of power plants on the ERCOT grid. In this model, the fixed and variable operating costs for each power plant in ERCOT are used as a basis for economic dispatch. At a given load, these operating costs determine the marginal operating power plant such that all power plants with higher operating costs are not dispatched. We do not model transmission expansion or transmission constraints. Previous work has used the same model to explore the implications of flexible CO₂ capture operations in the ERCOT and Great Britain grids (Cohen 2009, Cohen et al 2009, 2011, Ziaii et al 2008). Please refer to these publications for more detail.

We do not impose retirement or fuel conversion of any ERCOT power plant over the 20-year time horizon of our scenarios. Coal-fired power plants that are likely to sign long-term contracts to provide CO₂ to EOR operators are not likely to retire. ERCOT includes many coal-fired power plants that we did not model with CO₂ capture, and these units not modeled in our scenarios are those that are (i) older, (ii) less efficient, and (iii) without as many criteria emissions controls. Thus, we chose coal-fired power plants that would be most likely to capture CO₂ within the scope of our scenarios. Most of the coal-fired generating units we model with CO₂ capture are less than 40 years old. Clearly, there is a risk of new regulations (e.g., on mercury emissions) that could force these plants to shut down. It is most likely that some coal fired and other power plants will retire during the time frame of our analysis, but considering these changes is outside of the scope of this present work.

We assume the demand for electricity in ERCOT is the same in each of our system scenarios. We ignore impacts on demand of changes in electricity price due to CO₂ sales revenues or CO₂ taxes. The ERCOT annual load for the first year (2012) is 328 TWh, and we forecast it to increase at approximately 2.3% yr⁻¹ to 523 TWh in 2031 (ERCOT 2011).

For each scenario, we specifically chose the CO₂ sales price and CO₂ emissions penalty to equal the approximate level that makes the chosen subset of coal-fired power plants operate at baseload capacity factors. In other words, if the CO₂ sales price were lower, all of the chosen coal-fired power plants would operate at lower than baseload capacity over the 20-year simulation horizon, and if the CO₂ sales price were higher, they would not operate at any significantly higher capacity factor. The same rationale was used to set the level of the CO₂ emissions penalty: the penalty was chosen such that it was just at the level to enable our chosen subset of coal-fired power plants to operate at baseload conditions for the 20-year time horizon.

Table S3 (available at stacks.iop.org/ERL/8/034030/mmedia) of the supplemental information shows the chosen subset of existing ERCOT coal-fired power plants that were modeled with retrofitted amine-based post-combustion CO₂ capture. The amine capture unit is assumed to require 0.27 MWh/tCO₂ to remove 90% of the CO₂ from flue gas, which translates to a 22–32% net power output penalty depending on the base plant efficiency (Ziaii et al 2008). Capacity lost to CO₂ capture energy requirements could be replaced by new generating units, demand response, or increased efficiency and conservation. Examining these options is outside the scope of this work, but other literature suggests replacement capacity might not be necessary if capture systems could be bypassed during infrequent peak demand periods. With the assumed electricity demand and power plant fleet, sufficient capacity exists to substitute for reduced coal-based generation (Chalmers et al 2009, Cohen et al 2010). For the 'slow' scenarios, fewer coal-fired generators need CO₂ capture facilities because less CO₂ is needed per year than in the first few years of the 'fast' scenarios. Thus, in the 'slow' scenarios, only the following three electric generation units are assumed to capture CO₂: Fayette Power Project unit 1, J K Spruce unit 2, and WA Parish unit 7 (see table S3).

For the purposes of this analysis, the marginal generation cost from our dispatch model approximates the wholesale cost of electricity in ERCOT. The assumptions for fuel prices (see figure 2) and other operating costs drive the upward electricity price trends in figure 3. The projected fuel costs were taken from the EIA Annual Energy Outlook (AEO) 2011 (AEO table 1 for oil) (EIA 2011) and AEO 2012 early release (AEO table 3 for natural gas and steam coal for electricity). For all results, prices and costs are presented in constant year 2009 dollars ($2009).

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We present the modeled CO₂ emissions from the ERCOT electric grid (see figure 4) during the 20-year time span of our scenarios to create context for the large flows of CO₂ by our subset of coal-fired facilities. These CO₂ emissions originate primarily from coal and natural gas combustion, with minor quantities from other fossil fuels. The total modeled 20-year CO₂ emissions from the grid for scenarios 1–4 are 4300, 2800, 3200, and 2400 MtCO₂, respectively. The baseline (business as usual) modeled emissions for the grid with no CO₂ capture and no CO₂ emissions penalty is 4500 MtCO₂ over the 20-yr time span.

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Figures S1(a)–(d) (available at stacks.iop.org/ERL/8/034030/mmedia) show the electricity generation mix calculated for each scenario. Note that in all scenarios we assume that the demand for electricity in ERCOT is the same each year (e.g. the quantity of electricity generation that consumers purchase is not affected by prices). This assumption keeps the scenarios simple for straightforward comparison. In reality, the scenarios with $60/tCO₂ emissions penalty have significantly higher wholesale prices of electricity that would reduce demand to some degree.

Due to the variations in marginal price of electricity for each scenario and the assumption of inelastic electricity demand, the total operating profits earned by all generators in ERCOT varies considerably (see figure 5). Here we define operating profits as 'operating revenues minus operating costs', and revenues to generators in ERCOT come from selling electricity. Revenues also come from CO₂ sales for those coal-fired power plants with CO₂ capture in the 'CO₂ sales price' scenarios 1 and 3. Over the modeled 20-year time span, the operating profits for scenarios 1–4 are 96, 181, 107, and 179 billion $2009, respectively. We can reasonably deduce that total ERCOT operating profits are the same between each 'CO₂ sales price' scenario and between each 'CO₂ emissions penalty' scenario.

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Figure 6 shows the oil production and net CO₂ delivered for EOR. One can clearly visualize the front-loaded nature of investment for scenarios 3 and 4 where drilling and oil operations occur as early as possible. Our analysis ends after 20 years, but according to our field-specific modeling, there would still be significant oil production after 20 years for all scenarios, especially in scenarios 1 and 2. The total oil production within 20 years is 350 MMBBL for scenarios 1 and 2 and 480 MMBBL for scenarios 3 and 4. There are slight differences in the oil and CO₂ delivery profiles between scenarios 3 and 4, and these minor differences are driven by the modeled rate of CO₂ capture from the electricity dispatch model. In scenario 3, the CO₂ sales price affects dispatch of the coal-fired plants with CO₂ capture slightly differently than in scenario 4 with the CO₂ emissions penalty. The differences are minor and insignificant when interpreting cash flow results.

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Table 2 lists non-discounted capital, and operation and maintenance (O&M) costs per barrel (BBL) of produced oil, over 20 years, for each of the ten EOR fields and for the aggregated system. Different values exist for scenarios 1 and 2 versus scenarios 3 and 4 because our EOR cost model calculates capital and O&M costs as a function of the assumed exogenous oil price, the drilling sequence is significantly different in the 'slow' versus 'fast' scenarios, and more oil is produced in the 'fast' scenarios 3 and 4 compared to 'slow' scenarios 1 and 2.

Table 2 summarizes capital and operating expenses for our EOR cash flow model. All values are reported in units of total (non-discounted) dollars per barrel of oil produced within our 20-year scenario. The capital costs are generally higher compared to (Kheshgi et al 2010) that report a range of 3–9$/BBL capital expenditures. This discrepancy is consistent with the fact that our $/BBL calculation is based on only 20 years of production, does not include the full expected lifetime oil production from each well pattern, and is not based on the quantity proved reserves associated with the capital investment. The O&M costs in table 2 do not include the cost of an oil producer purchasing CO₂, and the costs are all significantly higher than the ranges quoted in Kheshgi et al (2010) of 6–15$/BBL.

The major parameter that affects operating costs is the cost of electricity to an operator. We assume a constant electricity price of 0.05$ kWh⁻¹ as a lower bound on electricity price. Two higher electricity price assumptions, equal to an industrial and residential price, provide medium and upper bounds on the electricity price. The industrial and residential prices are equivalent to the ERCOT average wholesale cost plus 3 and 7 cents kWh⁻¹, respectively. Even in the lowest-price case, the total O&M costs per field are 18–38$/BBL. The main reason for our higher O&M cost is that we are modeling a CO₂-only EOR operation, instead of WAG, so a much higher quantity of electricity is required to recycle and recompress a larger flow rate of CO₂ per quantity of produced oil. For perspective on the quantity of electricity needed for our modeled scenarios we consider only the separately modeled electricity for three purposes: CO₂ recompression during recycling, CO₂ pumping for injection for EOR and saline sequestration, and lifting of CO₂ and oil during EOR. These three needs peak at 12, 16, and 17 TWh yr⁻¹ for scenarios 1 and 2 (year 19), scenario 3 (year 7), and scenario 4 (year 8), respectively. These peak annual electricity needs are significant on the scale of ERCOT as they equate to approximately 2.3%, 4.1%, and 4.3% of modeled ERCOT electricity demand in each of the respective peak years of need.

In order to approximate the delivery of CO₂ for EOR at a constant rate, we aggregated each well pattern into phases of operation equal to 1/6 the total number of wells needed to develop each field. For example, we assume that there will be 211 production and CO₂ injection wells sidetracked in the Conroe field. Thus, each phase of drilling involves approximately 35 wells. In this way we stagger the operation of each phase as necessary to approximate a need for constant CO₂ delivery from the coal-fired power plants. Staggering drilling phases is done to optimize for constant CO₂ delivery, not profitability (i.e. the more profitable fields are not prioritized first with the less profitable fields later) (see figure 7). This approach is consistent with our system-wide scenario framework where we seek to understand bounding cases for a CCUS network. The cash flows for scenarios 1 and 2 are not significantly different for any ordering of EOR development phases, particularly within the accuracy of our capital and operating cost estimates. The oil production increases to 14 MMBBL yr⁻¹ by year 4 and stays between 17 and 21 MMBBL yr⁻¹ from years 5 to 20 (see figure 8).

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For the 'sales price' scenario 1, the price starts at 15$/tCO₂ in 2012 and increases linearly to 22$/tCO₂ in 2031, year 20 (see figure 8(a)). This CO₂ sales price is relatively small compared to the oil price, with price ratio of ($/tCO₂):($/BBL) of approximately 0.18:1 (or 3.4$ per thousand cubic feet (Mcf) of CO₂ per $/BBL of oil). This sales price largely offsets the increased operating costs of the coal-fired power plants with CO₂ capture and does not materially affect the marginal generation cost of the overall ERCOT grid.

Scenario 2 differs from scenario 1 in that there is an emissions penalty imposed upon CO₂ emissions from EGUs and from assumed combustion of produced oil (at 0.42 tCO₂/BBL). There is also no CO₂ sales price that EOR operators pay to coal-fired power plants. In effect, the CO₂ is delivered to the EOR fields and saline sequestration sites 'for free' to the field operators. This assumption of 'free CO₂' is a simplification based upon the choice of the emissions penalty price. We do charge EOR and saline sequestration operators a pipeline transport fee (0.8$/Mcf = 15.2$/tCO₂).

For the 'emissions penalty' scenario 2, we determined that a constant penalty of 60$/tCO₂ each year incentivized the three coal-fired generators with CO₂ capture to operate (considering only electricity sales for revenue) at near baseload and capture a similar amount of CO₂ as in scenario 1. Because this emissions penalty induces the coal-fired power plants to operate while capturing CO₂, those coal-fired power plants in ERCOT that do not capture CO₂ are at an economic disadvantage having to pay for CO₂ emissions. Economic dispatch modeling does not yet include capital costs for CO₂ capture infrastructure that we include in the system-wide cash flow.

The quantity of CO₂ emissions from the modeled system is shown in figure 8(b). Over 20 years, 240 Mt CO₂ are captured from coal combustion and sequestered in EOR and saline reservoirs, 146 MtCO₂ are emitted from the oil produced from the CO₂-EOR operations, and 27 MtCO₂ are emitted from the power plants with capture. Thus, our modeled system stores a net amount of 66 MtCO₂.

For the same CO₂ sales price trajectory as scenario 1, more base load coal-fired power plants are assumed to engage in CO₂ capture and deliver CO₂ for EOR to the same ten EOR fields but at a much faster rate. The EOR production is assumed to occur at a maximum rate where all phases of oil field operations engage in EOR operations within the first three years. This scenario is meant to be an extreme case indicating the shortest timescale for EOR production. CO₂ capture operations continue after EOR production, necessitating that much higher flow rates of 'excess' CO₂ (compared to scenarios 1 and 2) are captured and injected into saline reservoirs. Figure 9 shows the net total CO₂/yr, or delivered CO₂/yr, for EOR operations in the 'fast' scenarios 3 and 4. The net CO₂ delivered for EOR has a slightly different profile between scenarios 3 and 4 that accounts for the different amount of CO₂ captured in early years. This minor difference exists because coal-fired power plants are dispatched differently between the 'CO₂ sales' (scenario 3) and 'CO₂ emissions penalty' (scenario 4) scenarios.

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Scenario 4 has the same CO₂ emissions penalty as scenario 2. The number of oil production and CO₂ injection wells completed each year is approximately the same as scenario 3. In scenarios 3 and 4, the field location of the saline injection wells occurs approximately in proportion to the amount of modeled oil production at each field (with some adjustment as needed). There are 566 more saline CO₂ injection wells needed in scenario 4 than in scenario 3 because the smaller oil fields (e.g. not Hastings and Conroe) start production 1 or 2 years later than in scenario 3 to better match the CO₂ delivery profile.

Figure 10 shows the annual oil production for scenarios 3 and 4, as well as the assumed oil and CO₂ prices. To continue utilizing the capital investment in CCUS infrastructure, we assume the coal-fired power plants with capture continue to capture CO₂ each year even if it is no longer needed for EOR. Figure 11 shows that the quantity of CO₂ flows for scenarios 3 and 4 are nearly the same, with 80 and 75 MtCO₂ yr⁻¹, respectively. For scenario 3 and 4, respectively, 1540 and 1450 MtCO₂ of coal emissions are sequestered in EOR and saline reservoirs, 200 MtCO₂ are emitted from the oil produced from the CO₂-EOR operations, and 170 and 160 MtCO₂ are emitted from the power plants modeled to have CO₂ capture. Thus, our modeled system stores a net amount of 1090–1170 MtCO₂ over 20 years.

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We developed an integrated discounted cash flow model for the CCUS system described above. We include capital investment in (i) CO₂ capture at several Texas coal plants, (ii) development of a pipeline network to transport the captured CO₂ to stacked storage locations for EOR and sequestration, and (iii) development of the stacked storage EOR and sequestration facilities. There are no revenues realized by the saline operations; saline costs are assumed to be covered by EOR operators. Our goal is not to evaluate commercial viability of each segment but rather to investigate viability of the overall system.

Nevertheless, we impose a 12% rate of return on the pipelines as these would likely be subjected to some rate control if they are accessible to third parties. If pipelines are dedicated to either power plants or EOR operators or both, their costs would be mostly internalized. In any case, the pipeline segment represents a relatively small portion of operating costs (5% in slow scenarios and 14% in fast scenarios)⁷ and a small portion of capital costs in the system (8–10%).

In the 'CO₂ sales' scenarios 1 and 3, the EOR operators buy the CO₂ from the coal-fired power plants that capture it and then pay the pipeline company for transporting the CO₂ to the oil fields. In the 'CO₂ emissions penalty' scenarios 2 and 4, the EOR operators are only burdened by the cost of transporting CO₂.

In the 'CO₂ emissions penalty' scenarios, we can consider two system boundaries. One boundary does not penalize CO₂ emissions from oil combustion because these emissions can be considered to occur outside our CCUS system where oil is refined and consumed as refined products (e.g. gasoline). We also present cash flow results using a second system boundary that includes the cost of emissions from using the EOR oil. These oil emissions assume 0.42 MtCO₂ emissions per barrel of oil consumed at 60$/tCO₂, the same emission penalty used in the power dispatch model.

Table 3 shows key input values for the integrated cash flow analysis of the CO₂-EOR/sequestration value chain. The EOR cash flow model does not include operating costs for capture facilities because these costs are already included in the marginal cost calculations for power plants in our economic dispatch model of ERCOT. In that model, the power plants are dispatched only if revenues from electricity sales recover standard operating costs and the operating cost of CO₂ capture.

CO₂ sales and emission penalties produce different operating costs, especially in the 'fast' scenarios, because emission penalties have a more indirect impact on power plant economics (via raising operating costs) than selling CO₂, which provides direct revenues to the coal-fired power plant. Accordingly, the dispatched amount of electricity, mix of generators on the ERCOT grid, and CO₂ emissions change significantly between the 'CO₂ sales price' and 'CO₂ emissions penalty' scenarios. The difference in ERCOT dispatch is less drastic between the 'slow' and 'fast' scenarios for a given 'CO₂ sales price' or 'CO₂ emissions penalty' scenario.

In addition, the financial assumptions are the following: 10% discount rate, 10-year loans at a rate of 6% (2.5% of the loan amount is paid as the up-front fee), and 0.6% interest during construction for capture plant and pipeline capital. Capital expenses in capture facilities and pipelines are realized over three years (20% first year, 60% second year, and 20% third year) and partially financed via borrowing (50% for capture facilities and 60% for pipelines).

EOR and saline sequestration expenditures are treated differently. In slow scenarios, 50% of annual capital expenditures in EOR facilities are financed for the first six years when more than 80% of total capital is spent; the remainder is not financed because relatively small amounts are needed per year for the following 14 years. In slow scenarios, there is no financing for saline infrastructure because total investment is realized via sporadic and relatively small installments over 20 years. In fast scenarios, 50% of all capital expenditures are financed since all of it is realized within the first three years; in contrast, 50% of annual saline capital expenditures are financed for the first 10 years when more than 80% of total capital is spent; the remainder is not financed because relatively small amounts are needed per year for the following 10 years.

Finally, we assume that 70% of EOR capital costs and 100% of saline capital costs can benefit from intangible drilling cost tax deductions. This is a fairly standard deduction for risky upstream oil and gas projects. There is not much history with application of such deductions to saline operations but we assume all of these costs could be eligible for intangible drilling cost allowances because the sequestration operation does not generate any revenues for the EOR operator. For most cases, these deductions provide marginal benefits in our model and are inconsequential in terms of changing an NPV from negative to positive (or an internal rate of return, IRR, from less than 10% to higher than 10%). The sole exception is when considering joint 'EOR + saline storage' operations under scenario 4 ('fast' scenario with CO₂ penalties) without emissions penalties on oil and industrial electricity rates.

3.6.1. NPV summary (whole system).

Figure 12(a) plots the net present value (NPV) of the CCUS network. In no modeled scenario does the total system have positive NPV (table 4). The 'slow' scenarios have higher NPV than the 'fast' scenarios. These differences in NPV are because the 'fast' scenarios have a large increase in CCUS capital expenditures to add capture to additional coal-fired power plants, drill significantly more CO₂ injection wells, and concentrate EOR capital expenditures in the first three years rather than spread them out over 20 years. Because of the electricity required to pump CO₂ at the EOR and saline sequestration sites, electricity price is also very influential in affecting the total NPV.

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Table 4.  Summary of system-wide economics of CCUS network ($2009 million). A 10% discount rates is used for NPV analysis. Three values for a given scenario represent the three different electricity prices assumed for sensitivity analysis (from top to bottom, 0.05$ kWh⁻¹; industrial; residential).

Scenario	Scenario name	Oil emissions not penalized			Oil emissions penalized
		NPV	IRR	CO2 storage cost ($/tCO2)	NPV	IRR	CO2storage cost ($/tCO2)
1	Slow EOR, CO2 sales	−1 100	6%	5	−1 100	6%	5
		−1 700	3%	7	−1 700	3%	7
		−2 600	—	11	−2 600	—	11
2	Slow EOR, CO2 emission penalties	−1 200	6%	5	−3 600	—	15
		−2 600	—	11	−5 000	—	21
		−3 600	—	15	−6 000	—	25
3	Fast EOR, CO2 sales	−10 100	—	7	−10 100	—	7
		−11 400	—	7	−11 400	—	7
		−14 100	—	9	−14 100	—	9
4	Fast EOR, CO2 emission penalties	−17 200	—	12	−22 100	—	15
		−18 500	—	13	−23 400	—	16
		−21 200	—	15	−26 100	—	18

There is a difference between sales and emission penalty cases mainly because the CO₂ emissions penalties have a significant impact on profitability of coal-fired power plants. To have an internally consistent analysis, the CO₂ emissions penalty is applied to all generating plants using fossil fuels (coal, natural gas, and oil). Thus, our emissions penalty scenarios favor natural gas dispatch over coal generation within ERCOT (renewable generation is already favored in all scenarios due to low operating costs). Recall that we have specifically chosen the penalty of 60$/tCO₂ as level that maintains base load generation for the coal-fired plants with CO₂ capture. As we have chosen only a subset of coal-fired power plants to capture CO₂ (those delivering CO₂ to EOR fields), all other coal-fired power plants shift higher in the dispatch order and earn less operating revenue (see figure S1 of the supplementary information).

One way to interpret the system costs is by calculating the present value cost of CO₂ storage as the NPV divided by the total CO₂ captured and stored (see table 4). This cost of storage is an estimate of the additional money needed to make the system break even. The NPV storage costs range from 5 to 25$/tCO₂. The cheapest values are for 'CO₂ sales' scenarios and the most expensive costs are for 'CO₂ emissions penalties' scenarios when oil emissions are also penalized. The highest cost of storage per tCO₂ occurs for scenario 2, the slow scenario with oil CO₂ emissions penalized. For scenario 4, the costs with oil CO₂ emissions penalized are only 3$/tCO₂ higher than without an emissions penalty for oil.

3.6.2. NPV of each segment of CCUS system.

3.6.3. NPV of EOR with CO₂ emissions from oil internal to system boundary.

Our current analysis provides a valid conceptualization of the 'CO₂ sales price' scenarios because the sale of CO₂ from the coal-fired power plant to the EOR operator is an internal transaction. However, because we do not consider any indirect economic impacts outside of the modeled system in the 'CO₂ emissions penalty' scenarios, a fuller interpretation is needed via an analysis that can consider these indirect impacts. A primary indirect impact to consider is the effect of higher energy (electricity and oil) prices on lowering consumer demand. Thus, future work will more effectively compare the 'CO₂ sales price' (that impacts only the parties involved in our model) and the 'CO₂ emissions penalty' (which impacts entire economy) scenarios. This approach will necessitate enlarging our scope from our well-defined CCUS system to the rest of the economy, especially the power sector and consumers of oil products. Further calculations can also estimate the necessary spacing of injection wells storing CO₂ in saline reservoirs such that we can incorporate the associated capital costs of a distribution network. Recent papers indicate the costs can be several $/tCO₂, and there are different well-spacing configuration and designs to consider (Eccles et al 2012, Pooladi-Darvish et al 2011).