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Cost and Performance Baseline for Fossil Energy Plants – Volume 2 Coal to Synthetic Natural Gas and Ammonia U.S. Department of Energy National Energy Technology.

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Presentation on theme: "Cost and Performance Baseline for Fossil Energy Plants – Volume 2 Coal to Synthetic Natural Gas and Ammonia U.S. Department of Energy National Energy Technology."— Presentation transcript:

1 Cost and Performance Baseline for Fossil Energy Plants – Volume 2 Coal to Synthetic Natural Gas and Ammonia U.S. Department of Energy National Energy Technology Laboratory July 2011

2 2 Coal to SNG Study, July 2011 Disclaimer This presentation was prepared as an account of work sponsored by an agency of the United States Government. Neither the United States Government nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference therein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof. The views and opinions of authors expressed therein do not necessarily state or reflect those of the United States Government or any agency thereof.

3 3 Coal to SNG Study, July 2011 Objective Determine cost and performance estimates of near-term commercial offerings for the production of synthetic natural gas (SNG) and ammonia both with and without CO 2 sequestration. –Consistent design requirements –Up-to-date performance and capital cost estimates –Technologies built now and deployed in the near term Provides baseline costs and performance –Comparison of study natural gas and ammonia prices with current market prices

4 4 Coal to SNG Study, July 2011 Study Matrix Products ST Cond. (psig/°F/°F) Coal Type Coal Drying Gasifier Technology Oxidant Acid Gas Removal/ CO 2 Separation / Sulfur Recovery CO 2 Capture 1 SNG 1800/1050/ 1000 Illinois No.6 Conven- tional Siemens 99 mol% O 2 Selexol / Selexol / Claus 90% Montana Rosebud PRB WTASiemens 99 mol% O 2 Selexol / Selexol / Claus 90% North Dakota Lignite WTASiemens 99 mol% O 2 Selexol / Selexol / Claus 90% SNG/ NH /1050/ 1000 Illinois No.6 Conven- tional Siemens 99 mol% O 2 Selexol / Selexol / Claus 90% PRB– Powder River Basin WTA – Fluidized bed dryer with integrated waste heat recovery (German) 1 There is CO 2 capture in every case, but CO 2 is sequestered only in the even numbered cases

5 5 Coal to SNG Study, July 2011 Design Basis: Coal Type Coal Ultimate Analysis (weight %) Illinois #6Powder River BasinNorth Dakota Lignite As Rec’dDryAs Rec’dDryAs Rec’dDry Moisture Carbon Hydrogen Nitrogen Chlorine Sulfur Ash Oxygen (by difference) Total100 HHV (Btu/lb)11,66613,1268,56411,5166,61710,427

6 6 Coal to SNG Study, July 2011 Economic Assumptions for First Year Cost of Production First Year of Capital Expenditure 2007 Economic Analysis Period 35 years Dollars 2007 Coal ($/MM Btu) Illinois No PRB0.89 Lignite0.83 Capacity Factor (%)90 5 Year Construction Period High Risk First Year Capital Charge Factor 24.49%

7 7 Coal to SNG Study, July 2011    STUDY CATEGORY Order of Magnitude Estimate (+/- >50% Accuracy) Very little project-specific definition Rough scaling of previous related but dissimilar analyses “Back-of-the-envelope” analyses Order of Magnitude Estimate (+/- >50% Accuracy) Very little project-specific definition Rough scaling of previous related but dissimilar analyses “Back-of-the-envelope” analyses Concept Screening (+/- 50% Accuracy) Preliminary mass and energy balances Modeling and simulation of major unit operations Factored estimate based on previous similar analyses Concept Screening (+/- 50% Accuracy) Preliminary mass and energy balances Modeling and simulation of major unit operations Factored estimate based on previous similar analyses Budget Estimate (+30% / -15% Accuracy) Thorough mass and energy balances Detailed process and economic modeling Estimate based on vendor quotes, third-party EPC firms Budget Estimate (+30% / -15% Accuracy) Thorough mass and energy balances Detailed process and economic modeling Estimate based on vendor quotes, third-party EPC firms Technical Approach Systems Analyses Categorization

8 8 Coal to SNG Study, July 2011 Technical Approach 1. Extensive Process Simulation (ASPEN)  All major chemical processes and equipment are simulated  Detailed mass and energy balances  Performance calculations (auxiliary power, SNG/ammonia production, gross/net power output) 1. Extensive Process Simulation (ASPEN)  All major chemical processes and equipment are simulated  Detailed mass and energy balances  Performance calculations (auxiliary power, SNG/ammonia production, gross/net power output) 2. Cost Estimation  Inputs from process simulation (Flow Rates/Gas Composition/Pressure/Temp.)  Sources for cost estimation WorleyParsons Vendor sources where available  Follow DOE Analysis Guidelines 2. Cost Estimation  Inputs from process simulation (Flow Rates/Gas Composition/Pressure/Temp.)  Sources for cost estimation WorleyParsons Vendor sources where available  Follow DOE Analysis Guidelines

9 9 Coal to SNG Study, July 2011 Study Assumptions Capacity Factor assumed to equal Availability at 90% –The addition of CO 2 capture, compression, and sequestration and an ammonia co-production facility was assumed not to impact the availability factor Methanation system was modeled using Haldor Topsoe’s high temperature TREMP™ process Ammonia reaction was modeled at 2,030 psia based on the Haldor Topsoe S-300 Ammonia Synthesis Loop In CO 2 sequestration cases, CO 2 was compressed to 2,200 psig, transported 50 miles, sequestered in a saline formation at a depth of 4,065 feet and monitored for 80 years CO 2 transport, storage and monitoring (TS&M) costs were included in the first year cost of production (COP) for sequestration cases

10 10 Coal to SNG Study, July 2011 SNG and SNG/Ammonia Plants

11 11 Coal to SNG Study, July 2011 Siemens Gasifier SNG production is based on nominal thermal input of 500 megawatt-thermal (MW th ) to the gasifier. Actual gasifier thermal input varies according to the type of coal feed and ranges from 506 to 550 MW th. Heat Recovery includes a partial quench followed by a syngas cooler (This configuration is not currently a commercial offering by Siemens, but is planned for future coal-to-SNG projects) Source: Siemens

12 12 Coal to SNG Study, July 2011 SNG Plant with CO 2 Capture (Sequestration in Cases 2,6, and 8 *) Emission Controls: SOx: Selexol AGR removal of sulfur to < 6 ppmv H 2 S in syngas Claus plant with tail gas recycle for ~99.8% overall S recovery Hg: Activated carbon beds for ~95% removal Steam Turbine: MW (Steam is produced primarily from syngas cooler and methanation process, but is not shown in BFD) Steam Conditions: 1800 psig/1050°F/1000°F Emission Controls: SOx: Selexol AGR removal of sulfur to < 6 ppmv H 2 S in syngas Claus plant with tail gas recycle for ~99.8% overall S recovery Hg: Activated carbon beds for ~95% removal Steam Turbine: MW (Steam is produced primarily from syngas cooler and methanation process, but is not shown in BFD) Steam Conditions: 1800 psig/1050°F/1000°F * Note: Cases 5thru 8 do not have a COS hydrolysis reactor in the bypass stream

13 13 Coal to SNG Study, July 2011 SNG/Ammonia Plant with CO 2 Capture (Sequestration in Case 4)

14 14 Coal to SNG Study, July 2011 Performance Results Illinois No. 6 Illinois No. 6 NH 3 Co- production PRBND Lignite CO 2 SequestrationNOYESNOYESNOYESNOYES Gross Power (MW) Net Power (MW) SNG Production (Bscf/yr) NH 3 Production (TPD) N/A 2,204 N/A Conversion Eff. (%) SNG HHV (Btu/scf) Assumes capacity factor of 90% 2 Conversion efficiency is HHV SNG /HHV coal for SNG only cases and (HHV SNG + HHV NH3 )/HHV coal for co-production cases

15 15 Coal to SNG Study, July 2011 Economic Results Illinois No. 6 Illinois No. 6 NH 3 Co- production PRBND Lignite CO 2 Sequestration NOYESNOYESNOYESNOYES TOC, $MM 1 3,2353,3133,7423,8303,3543,4423,5043,595 Capital FY COP ($/MMBtu) Fixed FY COP ($/MMBtu) Variable FY COP ($/MMBtu) Fuel FY COP ($/MMBtu) Electricity FY COP ($/MMBtu) CO 2 TS&M FY COP ($/MMBtu) Total FY COP 2 ($/MMBtu) Ammonia FY COP ($/ton) N/A N/A FY CO 2 Avoided Cost, $/ton N/A16.65N/A13.47N/A16.79N/A Total Overnight Cost (Includes Total Plant Cost plus preproduction costs, inventory capital, financing costs, and other owner’s costs) 2 90% capacity factor and 24.49% first year capital charge factor

16 16 Coal to SNG Study, July 2011 Environmental Performance Comparison

17 17 Coal to SNG Study, July 2011 Criteria Pollutant Emissions for All Cases

18 18 Coal to SNG Study, July 2011 Mercury Emissions for All Cases

19 19 Coal to SNG Study, July 2011 CO 2 Emissions for All Cases

20 20 Coal to SNG Study, July 2011 Raw Water Withdrawal and Consumption Comparison

21 21 Coal to SNG Study, July 2011 Raw Water Withdrawal and Consumption

22 22 Coal to SNG Study, July 2011 Economic Results for All Cases

23 23 Coal to SNG Study, July 2011 CO 2 Avoided Costs

24 24 Coal to SNG Study, July 2011 Plant Cost Comparison

25 25 Coal to SNG Study, July 2011 Cost of Production Comparison

26 26 Coal to SNG Study, July 2011 Highlights

27 27 Coal to SNG Study, July 2011 NETL Viewpoint Most up-to-date performance and costs currently available in public literature Establishes baseline performance and cost estimates for current state of technology Reduced costs are required to improve competitiveness of coal-to-SNG processes –In today’s market and regulatory environment –Also in a carbon constrained scenario Ammonia co-production provides the most attractive SNG prices

28 28 Coal to SNG Study, July 2011 Result Highlights: Efficiency & Capital Cost HHV Conversion Efficiencies –Illinois No. 6:61.3% to 61.5% –Powder River Basin:63.1%* –North Dakota Lignite:61.5% Total Overnight Cost without Sequestration (MM$): –Illinois No. 6 SNG:$3,235 –Illinois No. 6 SNG/NH 3 :$3,742 –Powder River Basin SNG:$3,354 –North Dakota Lignite SNG:$3,504 Total Overnight Cost with Sequestration (MM$): –Illinois No. 6 SNG:$3,313 –Illinois No. 6 SNG/NH 3 :$3,830 –Powder River Basin SNG:$3,442 –North Dakota Lignite SNG:$3,595 * PRB has the highest conversion efficiency of 63.1% primarily due to the low nitrogen and high oxygen content in the design fuel, which enables the SNG product to have a relatively lower concentration of inerts.

29 29 Coal to SNG Study, July 2011 Results Highlights: FY COP FY COP ($/MMBtu) without Capture: –Illinois No. 6 SNG:19.27 –Illinois No. 6 SNG and NH 3 :15.82 (NH 3 = $799/ton) –Powder River Basin SNG:19.15 –North Dakota Lignite SNG:21.27 FY COP ($/MMBtu) with Capture: –Illinois No. 6 SNG:20.95 –Illinois No. 6 SNG and NH 3 :17.85 (NH 3 = $828/ton) –Powder River Basin SNG:21.01 –North Dakota Lignite SNG:23.24

30 30 Coal to SNG Study, July 2011 Summary Table for All Cases

31 31 Coal to SNG Study, July 2011 Summary Table

32 32 Coal to SNG Study, July 2011 Fuel Quality

33 33 Coal to SNG Study, July 2011 The SNG produced in this study is at the low end of the acceptable quality range. –HHVs Btu/scf –Wobbe Indices -1,265-1,275 –Inert concentrations % The primary reason for the lower quality product is the absence of higher hydrocarbons. The quality of the SNG produced in this study could be enhanced with minor impact on overall cost by the following… –Increase the oxygen purity from 99% to 99.5%. –Upgrade the PSA by increasing the bed depth or adding beds in series. –Blend other gases into the pipeline to achieve a desired Wobbe Index value. Purity requirements will be dictated by location and fuel end use. SNG Fuel Quality

34 34 Coal to SNG Study, July 2011 Sensitivity to Financing Scenario

35 35 Coal to SNG Study, July 2011 Sensitivity to ROE

36 36 Coal to SNG Study, July 2011 Favorable Financial Structure Economic Pathway 1.Modify financing structure a)Increase percentage of debt from 50% to 70% and decrease interest on debt from 9.5% to 4.5% b)Increase loan repayment term from 15 years to 30 years c)Decrease capital expenditure period from 5 years to 4 years 2.Reduce capital cost escalation during the capital expenditure period from 3.6% to 0% 3.Reduce owner’s cost from 23% to 18% 4.Reduce taxes and insurance in fixed O&M costs from 2% to 0.4% 5.Assume CO 2 revenue value for enhanced oil recovery of $10/tonne

37 37 Coal to SNG Study, July 2011 Technology Maturity Economic Pathway 1.Modify financing a)Decrease interest on debt from 9.5% to 4.5% b)Decrease required internal rate of return on equity from 20% to 12% 2.Reduce capital cost by 22% to reflect FOAK to NOAK improvements


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