Impact of the Introduction of a Carbon Capture and Storage System in the Oil Sands Sector on Air Contaminant Emissions

Transcription

1 Canadian Energy Research Institute Impact of the Introduction of a Carbon Capture and Storage System in the Oil Sands Sector on Air Contaminant Emissions Part 2 Costs of Carbon Capture and Storage for the Oil Sands Sector Brian Bowers, P.Eng Prepared for Environment Canada Relevant Independent Objective

2 IMPACT OF THE INTRODUCTION OF A CARBON CAPTURE AND STORAGE SYSTEM IN THE OIL SANDS SECTOR ON AIR CONTAMINANT EMISSIONS PART 2 COSTS OF CARBON CAPTURE AND STORAGE FOR THE OIL SANDS SECTOR

3 Canadian Energy Research Institute i TABLE OF CONTENTS LIST OF TABLES... III EXECUTIVE SUMMARY... V CHAPTER 1 INTRODUCTION... 1 CHAPTER 2 COST OF CO 2 CAPTURE Capital Costs Fixed Operating Costs Variable Operating Costs Taxes Total Capture Costs... 4 CHAPTER 3 COSTS OF CO 2 TRANSPORTATION Capital Costs Fixed Operating Costs Variable Operating Costs Taxes Total Transportation Costs... 9 CHAPTER 4 COSTS OF CO 2 STORAGE...13 CHAPTER 5 TOTAL GROSS AND NET CCS COSTS WITH GASIFICATION TECHNOLOGY...14 REFERENCES...16

4 ii Impact of the Introduction of a Carbon Capture and Storage System in the Oil Sands Sector on Air Contaminant Emissions, Part 2 (THIS PAGE INTENTIONALLY LEFT BLANK)

5 Canadian Energy Research Institute iii LIST OF TABLES Table 2.1: Estimation of Fixed Operating Costs... 3 Table 2.2: Variable Operating Costs ($/t)... 4 Table 2.3: Tax Regime... 4 Table 2.4: Tax Calculation Spreadsheet... 5 Table 2.5: Cash Flow Spreadsheet... 6 Table 2.6: Components of Costs per Gross Tonne Captured ($/t)... 7 Table 2.7: Components of Costs per Net Tonne Captured ($/t)... 7 Table 3.1: Tax Calculation Spreadsheet...10 Table 3.2: Cash Flow Spreadsheet...11 Table 3.3: Components of Costs of Transportation...12 Table 5.1: Total Gross and Net Costs of CCS...15

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7 Canadian Energy Research Institute v EXECUTIVE SUMMARY This study provides updated estimates of the costs of capture, transportation and storage components of CCS facilities installed to serve the oil sands sector. Basic information for the study was obtained from a three volume 2002 CERI study entitled Costs of Capture and Sequestration of Carbon Dioxide in Western Canadian Geologic Media. Part 1 of this study envisages that facilities for the gasification of asphaltene or petcoke with carbon capture will be installed at the sites of bitumen extraction and upgrading operations and that power and process heat for CCS operations will be generated locally using syngas produced by these gasification units. It is also envisaged that a CO 2 gathering network will be developed and a trunk line provided to transport CO 2 from the oil sands areas to west-central Alberta where suitable geological reservoirs exist for the sequestration of CO 2. However, it is important to note that gasification of asphaltene and petcoke in oil sands operations are emerging technologies. The first application, the Opti/Nexen facility at Long Lake, is currently in the startup phase and does not include facilities for the capture of CO 2. Consequently the operating and cost data to make precise cost estimates are not yet available. For the purpose of this cost study, it is assumed that the capture process of the integrated gasification combined cycle (IGCC) process for the generation of electricity can be adapted to application in the oil sands operations. A prototype for this process was included in the 2002 CERI study on a theoretical basis. This study updates the cost estimate for this prototype. However, scaling of this updated prototype cost to bitumen extraction and upgrading operations in the oil sands areas is beyond the scope of this current study. The estimated total costs for CCS facilities in terms of total cost per gross tonne of CO 2 captured and cost per net tonne CO 2 captured are shown in the table below. Total Gross and Net Costs of CCS Gross Net Capture Transportation Storage Total The total cost per gross tonne captured is approximately $80/t and the total cost per net tonne captured is approximately $82/t.

8 Canadian Energy Research Institute 1 CHAPTER 1 INTRODUCTION This study considers the costs of carbon storage and capture (CCS) for the oil sands sector envisaged in Part 1 of this study. The study relies on information generated in previous studies; principally a 2002 CERI study 1 Costs of Capture and Sequestration of Carbon Dioxide in Western Canadian Geologic Media and its associated studies conducted by SNC Lavalin Inc. (SLI), Adams Pearson and Associates (APA) and the Alberta Geological Survey (AGS). This is a comprehensive study that includes both engineering studies of the capture and transportation facilities as well as geological studies of the storage aspects. A CERI study 2 being carried out in parallel with this study provided cost escalation information for the period since the completion the 2002 CERI study. Part 1 of this study envisages that facilities for the gasification of asphaltene or petcoke with carbon capture will be installed at the sites of bitumen extraction and upgrading operations, and that power and process heat for CCS operations will be generated locally using syngas produced by these gasification units. It is also envisaged that a CO 2 gathering network will be developed and a trunk line provided to transport CO 2 from the oil sands areas to west-central Alberta where suitable geological reservoirs exist for the sequestration of CO 2. However, it is important to note that gasification of asphaltene and petcoke in oil sands operations are emerging technologies. The first application, the Opti/Nexen facility at Long Lake, is currently in the startup phase and does not include facilities for the capture of CO 2. Consequently the operating and cost data to make precise cost estimates are not yet available. The cost estimate provided in this report for carbon capture in bitumen operations is limited to an update of the estimate contained in the 2002 CERI study for the integrated gasification combined cycle (IGCC) prototype. This is referred to in that study as a theoretical case. For the purpose of this cost study, it is assumed that a modification of this process can be adapted to use in oil sands operations. However, scaling of the updated cost for the IGCC prototype to bitumen extraction and upgrading operations in the oil sands areas is beyond the scope of this current study. In addition to providing an update of the IGCC prototype, this study also provides updates of the cost estimates contained in the 2002 CERI study for the transportation and storage components of a CCS system for the oil sands operations. The cost estimates assume that the components of the CCS system will be provided as services to the oil sands sector and operated as businesses. Estimates of taxes paid and returns earned by the business operator are included. The estimates assume a real rate of return to the operator of 10 percent. The assumed inflation rate is 2 percent. Hence, the nominal rate of return to the operator is assumed to be 12 percent. Supply cost methodology is used to make the estimations. By definition, the supply cost for a project is equal to the invariable price in constant dollars that must be received over the life of the project per unit of production to exactly balance revenues in constant dollars with capital and

9 2 Impact of the Introduction of a Carbon Capture and Storage System in the Oil Sands Sector on Air Contaminant Emissions, Part 2 operating costs, taxes and royalties (if applicable) and a specified rate of return. The economic assessments are made in the form of supply costs because the supply cost reflects only the costs, taxes and royalties of a project and does not require a projection of future market prices for the service or commodity provided. This simplifies the economic analysis for commodities or services for which future prices are unknown. The calculation of supply cost is relatively simple because, mathematically, the supply cost is simply the ratio of the total net present value of annual costs (with payments to governments included as costs) divided by the net present value of the annual productions. However, there are some complications. The calculation is iterative in nature because payments to governments are usually a function of price, which is equal to the output of the calculation. However, the calculation is easily carried out in an iterative worksheet. The worksheet is similar to a cash flow worksheet used by industry to determine investment profitability, except it solves for the price needed to achieve profitable operation at a specified rate of return. For the calculation of payments to governments, the revenue and cost inputs are converted to nominal dollars, the calculations made and the results expressed in real terms. The supply cost is determined when the price is sufficient to exactly balance revenues with capital and operating costs, payments to governments and a specified rate of return to the operator of the business. Supply costs are reported in constant 2007 dollars. The calculation procedure provides a breakdown of the total supply cost into its component parts on a discounted or undiscounted basis. The total supply cost is the same whether on an undiscounted or discounted basis. However, in the discounted case the time value of money is taken into account and front-end costs such as capital costs are larger. Estimates of both undiscounted and discounted costs are included in this report. Presented in the following chapters are the updated estimates in terms of total cost, cost per gross tonne and cost per net tonne of CO 2 captured and stored. Chapter 2 provides updates of costs for the IGCC prototype; Chapter 3 provides an update of the transportation cost and Chapter 4 an update of the CO 2 storage cost. Chapter 5 aggregates the component costs to derive the estimated total cost of CCS for the oil sands sector.

10 Canadian Energy Research Institute 3 CHAPTER 2 COST OF CO 2 CAPTURE The IGCC prototype cost estimate made by SLI for the 2002 CERI study was based on 90 percent capture of the CO 2 contained in the flue gas feed to the capture facilities. The CO 2 emissions due to the energy requirements of the CCS facilities, based on off-site generation of power and natural gas for process heat, were estimated at 16 percent of the CO 2 content of the flue gases, resulting in a net capture of 74 percent of the CO 2 contained in the flue gas to the facilities. Part 1 of this study also assumes that 90 percent of the CO 2 in the flue gases will be captured but for the estimation of CO 2 emissions due to the energy requirements of CCS facilities assumes onsite generation of power and process heat. The estimated emissions are 2.1 and 2.5 percent of the captured CO 2 for asphaltene and petcoke gasification cases respectively. The net capture is therefore estimated at 88.1 percent (97.9% * 90%) of the CO 2 contained in the flue gas for the asphaltene case and 87.8 percent (97.5% * 90%) for the petcoke case. 2.1 Capital Costs The capital cost for a facility capable of capturing 2,674 Kt/y was estimated at $260.1 million in 2002 by SLI. The updated estimate amounts $536.3 million. It is assumed that this capital cost is incurred the year prior to the startup of the capture facilities. 2.2 Fixed Operating Costs Fixed operating costs are estimated as a percentage of capital costs. Table 2.1 compares the current estimates with those in 2002 by SLI. Table 2.1: Estimation of Fixed Operating Costs Asphaltene Petcoke 2002 CO 2 captured (gross Kt/y) CCS CO 2 emissions (%) CO 2 captured (net Kt/y) Capital cost Year 1 ($M) Capital cost Year 2 ($M) Capital cost Year 3 ($M) Salaries and overhead (%) 1.5% 1.5% 1.5% Maintenance (%) 2.5% 2.5% 2.5% Insurance (%) 0.5% 0.5% 0.5% Total fixed cost (%) 4.5% 4.5% 4.5% Total annual cost ($M/y) Cost per gross tonne ($/t)

11 4 Impact of the Introduction of a Carbon Capture and Storage System in the Oil Sands Sector on Air Contaminant Emissions, Part 2 In its 2002 study, CERI added to the above estimates by SLI a fixed cost for administration and general (A&G) expenses charged at a rate of 10 percent of capital expenditures and operating costs. Abandonment and reclamation costs were also added at an assumed rate of 3 percent of the cumulative capital invested. 2.3 Variable Operating Costs SLI estimated variable operating costs per gross tonne of CO 2 captured. Table 2.2 compares the current estimate with that in 2002 by SLI. The escalation factors used to update the estimates are also listed in the table. Table 2.2: Variable Operating Costs ($/t) Factor Power Cooling water LP Steam from gas Process water Waste handling Limestone Solvent Total Taxes The assumptions for the calculation of taxes are listed in Table 2.3. Total federal and provincial tax rates were about 41 percent in This is revised to 30 percent as shown in the table. Table 2.3: Tax Regime Inflation rate 2% CCA rate 25% Federal tax rate 20% Provincial tax rate 10% Discount rate 10% 2.5 Total Capture Costs The tax and cash flow spreadsheets used to calculate the supply cost, or in this case the levelized unit cost of capture, are shown in Tables 2.4 and 2.5 respectively. The life of the project is assumed to be 33 years with an operating life of 30 years.

12 Canadian Energy Research Institute 5 Table 2.4: Tax Calculation Spreadsheet Project Real Real Nominal Nominal Nominal 1/2 Year CCA Rem. Net Nominal Real Year Expense Investment Revenue Expense Investment Investment Rule Claim CCA Income Fed. Tax Prov. Tax Total Tax Total Tax Totals Notes: Inflation rate (%) 2% CCA rate (%) 25% Federal tax rate (%) 20% Provincial tax rate (%) 10%

13 6 Impact of the Introduction of a Carbon Capture and Storage System in the Oil Sands Sector on Air Contaminant Emissions, Part 2 Table 2.5: Cash Flow Spreadsheet Gross Fixed Non-fuel A&G Abandon Non-fuel C/Flow Total C/Flow Facilities Net Project Production SC Revenue Opex Opex Opex Reclaim Opex B.T. Taxes A.T. Capex C/Flow Year Mtonne/yr $/tonne M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ Total Undiscounted supply cost Total NPV Discounted supply costs Variable opex $/gross tonne Notes: First year investment ($M) 0.0 Power Second year investment ($M) 0.0 Cooling 0.76 Third year investment ($M) Steam 4.85 Fixed non-fuel opex (% of plant capex) 4.5% Process water 0.01 A&G (% of cap $ opex) 10% Waste handling 0.01 A&R (% of cum capex) 3% Limestone 0.00 Discount rate (%) 10% Amine slovent 0.27 Total 20.94

14 Canadian Energy Research Institute 7 As shown in Table 2.5 the total levelized unit cost of capture is $58.40 per gross tonne of CO 2 captured. The components of this cost on a discounted and undiscounted basis are shown in Table 2.6. Table 2.6: Components of Costs per Gross Tonne Captured ($/t) Undiscounted Discounted Capital cost Fixed operating cost Administration and general Variable operating cost Abandonment and reclamation Total operating cost Taxes Return (10% real) NA Total cost Comparable updated estimates of gross capture costs for the pressure swing adsorption (PSA) and Benfield processes, which apply to oil sands operations that use natural gas/steam reforming, are $93 and $43 per gross tonne of CO 2 captured respectively. 2 The undiscounted component costs per net tonne of CO 2 captured for the asphaltene and petcoke gasification cases are listed in Table 2.7. These costs are calculated by dividing the undiscounted costs per gross tonne in Table 2.6 by the net to gross emissions ratio. The updated SLI estimate, which assumes off-site power generation and natural gas combustion for process heat generation for the CCS facilities, is included for comparative purposes. Table 2.7: Components of Costs per Net Tonne Captured ($/t) Asphaltene Petcoke SLI Updated Net to gross ratio 97.9% 97.5% 82.2% Capital cost Fixed operating cost Administration and general Variable operating cost Abandonment/reclamation Total operating cost Taxes Return (10% real) Total cost There is essentially no difference between costs for the asphaltene and petcoke cases. Comparable updated estimates of net capture costs for the pressure swing adsorption and Benfield processes are $126 and $45 per net tonne of CO 2 captured respectively.

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16 Canadian Energy Research Institute 9 CHAPTER 3 COSTS OF CO 2 TRANSPORTATION The 2002 CERI study considered a case where transportation is provided from the large oil sands plants in the Fort McMurray area to central Alberta storage sites. A 500 km, 24-inch diameter pipeline with a capacity of 11.3 Mt/y was assumed. This scenario has been adopted for the current study. 3.1 Capital Costs The capital cost for the assumed pipeline was estimated at $373 million in The updated estimate based on an escalation factor of 2.0, amounts $746 million. It is assumed that this capital cost is incurred the year prior to the startup of the pipeline. 3.2 Fixed Operating Costs Fixed operating costs are assumed to be 8.75 percent of capital costs. Administration and general costs are assumed to be 10 percent of capital and operating costs. 3.3 Variable Operating Costs Electrical energy requirements for the pipeline are 5 KWh per tonne of CO 2 transported. An electricity cost of $60/MWh was used in the 2002 CERI study. This has been updated in the current study to $157/MWh based on an escalation factor of Taxes Rates for inflation, CCA, federal and provincial taxes and returns are the same as for capture costs in Section Total Transportation Costs The tax and cash flow spreadsheets used to calculate a levelized unit transportation cost are shown in Tables 3.1 and 3.2 respectively. The life of the project is again assumed to be 33 years with an operating life of 30 years.

17 10 Impact of the Introduction of a Carbon Capture and Storage System in the Oil Sands Sector on Air Contaminant Emissions, Part 2 Table 3.1: Tax Calculation Spreadsheet Project Real Real Nominal Nominal Nominal 1/2 Year CCA Rem. Net Nominal Real Year Expense Investment Revenue Expense Investment Investment Rule Claim CCA Income Fed. Tax Prov. Tax Total TaxTotal Tax Totals Notes: Inflation rate (%) 2% CCA rate (%) 25% Federal tax rate (%) 20% Provincial tax rate (%) 10%

18 Canadian Energy Research Institute 11 Table 3.2: Cash Flow Spreadsheet Gross Fixed Non-fuel A&G Abandon Non-fuel Fuel C/Flow Total C/Flow Facilities Net Project Production SC Revenue Opex Opex Opex Reclaim Opex Opex B.T. Taxes A.T. Capex C/Flow Year Mtonne/yr $/tonne M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ Total Undiscounted supply cost Total NPV Discounted supply costs Notes: First year investment ($M) 0.0 Second year investment ($M) 0.0 Third year investment ($M) Fixed non-fuel opex (% of plant capex) 8.8% A&G (% of cap $ opex) 10% Power - $ per tonne transported 0.79 A&R (% of cum capex) 0% Discount rate (%) 10%

19 12 Impact of the Introduction of a Carbon Capture and Storage System in the Oil Sands Sector on Air Contaminant Emissions, Part 2 As shown in Table 3.2 the total levelized cost of transportation is $15.33 per tonne of CO 2 transported. The components of this cost on an undiscounted basis are compared with those estimated in 2002 in Table 3.3. Table 3.3: Components of Costs of Transportation Capital cost Fixed operating cost Administration and general Variable operating cost Abandonment and reclamation Total operating cost Taxes Return (10% real) Total cost The table shows that transportation costs have approximately doubled since 2002.

20 Canadian Energy Research Institute 13 CHAPTER 4 COSTS OF CO 2 STORAGE In the 2002 CERI study storage costs in the largest best quality gas reservoirs in western Alberta were estimated to be about $3/t. Costs in smaller, poorer quality and shallower reservoirs were estimated to be in the range $7/t to $9/t. A recent study 3 of the potential for CO 2 storage of the Redwater Leduc reef located north east of Edmonton by the Alberta Research Council (ARC) and Alberta Energy Resources Conservation Board (AERCB) has concluded that there is adequate volume for the storage of CO 2 in large saline aquifer reservoirs. The study concludes that based on the high injectivity in the reef, the potential exists to inject sustainably in excess of one Ktonne of CO 2 per day per well into the aquifer portion of the reef. Preliminary storage capacity estimates for the aquifer are in the order of one Gtonne of CO 2, which exceeds the projected oil sands emissions for the next 20 years. In addition to this storage potential, the Cooking Lake aquifer that underlies the Redwater reef offers even larger potential for CO 2 storage once the Leduc reef has been filled. Given that the ARC/AERCB studies indicate that there are sufficient high quality reservoirs available for the storage of CO 2 it is reasonable to assume that the cost for storage will be at the low end of the range estimated in the 2002 CERI study ($3/t in 2002). Assuming an escalation in line with the other cost increases since 2002 a cost of $6/t is a reasonable current estimate.

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22 Canadian Energy Research Institute 15 CHAPTER 5 TOTAL GROSS AND NET CCS COSTS WITH GASIFICATION TECHNOLOGY The estimated total costs in terms of total cost per gross tonne of CO 2 captured and cost per net tonne captured are shown in Table 5.1. Table 5.1: Total Gross and Net Costs of CCS Gross Net Capture Transportation Storage Total The total cost per gross tonne captured is approximately $80/t and the total cost per net tonne captured is approximately $82/t.

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24 Canadian Energy Research Institute 17 REFERENCES 1. Costs of Capture and Sequestration of Carbon Dioxide in Western Canadian Geologic Media; L. Fisher, T. Sloan and P. Mortensen, CERI Study No. 106, June Costs for Capture of Carbon Dioxide Partial Update; T. Walden, CERI Study, March The Redwater Reef in the Heartland Area, Alberta; A Unique Opportunity for Understanding and Demonstrating Safe Geological Storage of CO 2 ; W. Gunter, Alberta Research Council and Stefan Bachu, Alberta Energy Resources Conservation Board, June 2007.

25 About CERI The Canadian Energy Research Institute (CERI) is a co-operative research organization established through an initiative of government, academia, and industry in The Institute's mission is to provide relevant, independent, objective economic research and education in energy and related environmental issues. Related objectives include reviewing emerging energy issues and policies as well as developing expertise in the analysis of questions related to energy and the environment. For further information, see our web site: