Economic Analysis (Task 5.3): Integrated CCUS Project Lifecycle Economics

Transcription

1 Does it make economic sense to capture CO2 and use it for enhanced oil recovery and storage? Objectives Economic Analysis (Task 5.3): Integrated CCUS Project Lifecycle Economics The economic feasibility of an integrated CCUS project in Ohio is highly dependent on projectspecific requirements and source-sink scenarios. The objective of this economic analysis was to evaluate the economic feasibility of specific source-sink scenarios in Ohio by integrating CO2 capture techno-economics for a representative 550-megawatt (MW) power plant with CO2 transport, field-scale CO2-EOR, and potential CCUS-related regulations and tax credits. Analysis Methods and Data Sources The analysis framework used to evaluate the system-wide economics of a CCUS project in Ohio is shown in Figure 1. The analysis incorporated information from reservoir characterization efforts, laboratory measurements, reservoir modeling, and pipeline routing studies conducted as part of this project. Fifty-four CO2 capture and oil field development scenarios were examined, including two capture plant configurations for CO2 capture scenarios of 90%, 50%, and 25% from the 550 MW coal-fired reference plant, and three different injection scenarios for the three oil fields of interest (Table 1). Injection scenario A involved cumulative injection of 3 hydrocarbon pore volumes (HCPV) of CO2 at an injection rate of 39 metric tons (t) per day. To examine the effects of greater cumulative injection volumes on feasibility outcomes, CO2 injection was increased to 5 HCPVs while maintaining the same injection rate of 39 t/day in scenario B. A higher CO2 injection rate of 52 t/day was evaluated in injection scenario C for 5 HCPVs of total CO2 injection. The Integrated Environmental Control Model (IECM) was used to model CO2 capture performance and costs for the 550 MW reference power plant 1. CO2-EOR techno-economics were assessed via simplified reservoir simulation 2 and cost models established in previous phases of this project 3. Per pattern CO2-EOR performance results were aggregated into field-scale development calculations linked to CO2 capture costs and annual storage requirements for each power plant capture scenario over a period of 30 years. The potential economic impact of CCUSrelated policies was evaluated by incorporating costs associated with EOR operations having a dedicated CO2 storage component and CO2 storage tax credits from the 45Q tax law for Class II EOR wells. The costs of CO2 transport via pipeline were calculated using the DOE-NETL CO2 Transportation Cost Model 4. 1 Carnegie Mellon University Department of Engineering and Public Policy. The Integrated Environmental Control Model: A tool for calculating the performance, emissions, and cost of a fossil-fueled power plant. Version Dobitz, J. K., & Prieditis, J. A. (1994). A stream tube model for the PC. In: SPE/DOE Ninth Symposium on Improved Oil Recovery, 1994, Society of Petroleum Engineers: Tulsa, OK. 3 Fukai, I., Mishra, S., & Moody, M. (2016). Economic analysis of CO2-enhanced oil recovery in Ohio: Implications for carbon capture, utilization, and storage in the Appalachian Basin region. International journal of Greenhouse Gas Control, DOE-NETL.FE/NETL CO2 Transport Cost Model. Retrieved from US Department of Energy: Accessed March, of 5

2 Figure 1. Economic analysis framework used in this study to evaluate the techno-economics of power plant CO 2 capture integrated with CO 2 transport and field-scale CO 2-EOR. CO2 capture cost, levelized cost of electricity (LCOE), net present value, and break-even oil price were the primary analysis metrics used to integrate power plant capture and CO2-EOR economic models, compare model outcomes, and determine scenario feasibility. Feasible sourcesink scenarios were defined by scenarios that met the following criteria: 1. had a positive NPV at the end of the operation 2. had break-even oil prices less than $43/stock tank barrel (STB): the lowest average annual crude oil price from years 2008 to were able to meet annual and thirty-year CO2 storage requirements associated with the power plant capture scenario of interest Scenarios that qualified as feasible were then ranked based on NPV to determine the most economically feasible source-sink strategies for implementing 50%, 90%, and commercial CO2 capture from a 550 MW reference plant. The 50% capture scenario was considered to address potentially feasible options for a coal-fired power plant to reduce CO2 emissions to levels that are competitive with those from a natural gas-fired power plant. Outcomes for the 90% capture scenario represent potential strategies for a coal-fired power plant to achieve CO2 emission reductions needed to effectively mitigate greenhouse gas-related climate change. Additional model assumptions and input included: a cost of $50 per ton of coal for the power plant; an oil price of $50 per stock tank barrel (STB); and a CO2 purchase price for EOR equal to the CO2 capture cost incurred by the power plant. Results from the most economically feasible commercial scenario were evaluated with and without the 45Q tax credit. 2 of 5

3 Capture plant, pipeline, and EOR-storage site construction were assumed to begin in 2022 and operations to begin in All scenarios were modeled for a thirty-year analysis time frame. Table 1. Matrix showing the eighteen scenarios analyzed for the three oilfields and the 550 MW power plant. CO 2 -EOR Injection Scenario 550 MW Power Plant Capture Scenario Scenario Designation A B C Injection Rate (t/day): Total HCPV Injected: Intermediate Pressure/ Low Pressure 25% 2 Auxiliary Boiler 25% 3 Intermediate Pressure/ Low Pressure 50% 4 Auxiliary Boiler 50% 5 Intermediate Pressure/ Low Pressure 90% 6 Auxiliary Boiler 90% Results CO2 capture costs modeled for the 550 MW reference plant ranged from $38 to $71/t CO2. The unit costs of CO2 separation decrease with higher capture percentage, reflecting greater economies of scale at 90% capture, whereas the LCOE increased with higher capture percentage due to energy penalties associated with the CO2 capture system. Nineteen out of the fifty-four scenarios examined qualified as feasible, including four scenarios in the GCOF and fifteen scenarios in the ECOF. The size of the MCOF was insufficient to meet 30-year storage requirements associated with 25%, 50%, and 90% CO2 capture from the 550 MW plant. Comparison of feasible and infeasible outcomes for the three different injection scenarios examined in the oil fields of interest suggests changes in CO2-EOR operational strategy can have a potentially significant impact on the techno-economic feasibility of a CCUS project. The net present value results for the most economically feasible 50%, 90%, and commercial CO2 capture scenarios are shown in Figure 2. The most economically feasible scenario analyzed for 50% capture at a 550 MW plant in Ohio was associated with a CO2 capture cost of $42/t and injection scenario A (39 t CO2/day and 3 HCPVs) in the ECOF, with a net present value of $1,434 million and break-even oil price of $27/STB. Injection scenario B (39 t CO2/day and 5 HCPVs) in the ECOF and a CO2 capture cost of $38/t was the most economically feasible scenario for implementing 90% capture at the coal-fired reference plant, having a net present value of $2,003 million and break-even oil price of $31/STB. The most economically feasible scenario for supporting a commercial CCUS project in Ohio was associated with 25% CO2 capture at a cost of $48/t and injection scenario C (52 t CO2/day and 5 HCPVs) in the GCOF. This scenario had the highest net present value ($2,228 million) and lowest break-even oil price ($20/STB) of the source-sink scenarios examined. The CO2 capture costs modeled for the 550 MW reference plant were approximately 1.2 to 3.2 times higher than the corresponding oil break-even prices calculated for the nineteen scenarios qualifying as feasible in this study (Figure 2a). 3 of 5

4 On average, the 45Q CO 2 storage tax credit affords a $3/STB to $7/STB decrease in the calculated breakeven price of oil for the scenarios examined (Figure 3). Pipeline costs ranged from $1.0 million to $1.7 million per pipeline mile for transport of 25%, 50%, and 90% CO2 capture quantities from the 550 MW plant to the three oil fields of interest. Figure 2. Net present value results of the most economically feasible scenarios for implementing 50%, 90%, and commercial CO 2 capture from a 550 MW power plant in Ohio. Figure 3. (A) Break-even oil prices versus CO 2 capture costs calculated for the nineteen source-sink scenarios classified as feasible. (B) Comparison of break-even oil prices calculated for the most economically feasible 50%, 90%, and commercial capture scenarios and one infeasible scenario in the ECOF (left, denoted by an asterisk). 4 of 5

5 Significance The significance of this work includes the following: Field-scale reservoir performance and cost models suggest there are potentially feasible source-sink scenarios in Ohio for accommodating up to 90% of CO2 emissions captured from a 550 MW coal-fired power plant over 30 years. The CO2 capture cost incurred by the 550 MW reference plant was offset by CO2-EOR revenue rather than passed on to rate payers in 19 feasible scenarios examined. Inefficient CO 2 storage and reservoir access during CO 2-EOR is the primary technical factor limiting the feasibility of source-sink scenarios examined in this analysis. An increase in the cumulative volume of CO 2 injected (e.g. higher HCPVs) during EOR operations can potentially shift project outcomes from infeasible to feasible for a particular field. Comparison of economic outcomes with and without CO 2 storage costs and credits suggests the economic feasibility of specific source-sink pairs could be improved by taking advantage of CCUS-related policies and tax incentives. For more information, refer to: "CO2 Utilization for Enhanced Oil Recovery and Geologic Storage in Ohio, Task 5: Economic Analysis Topical Report.," OCDO Grant/Agreement OER- CDO-D-15-08, Columbus, of 5