Technology Approach and Sizing

Transcription

1 Stantec Consulting Ltd. 845 Prospect Street, Fredericton NB E3B 2T7 January 15, 2016 File: _8_8 Attention: #2 Miles Canyon Road Box 5920, Whitehorse, Yukon, Y1A 6S7 Dear Ms. Mallory, Stantec Consulting Ltd. (Stantec) was contracted by Yukon Energy Corporation (YEC) to conduct an update on biomass technology costing in support of current planning activities. This letter represents a screening level assessment of available technologies in the size range requested by YEC (0.5 MWe to 2.0 MWe), based on quotes from equipment vendors and information scaled from the previous biomass FEED Study 1. Outlined in this report is the sizing assumed for each plant and technology, a performance matrix outlining expected unit performance, and an opinion of probable capital and operating cost. Technology Approach and Sizing YEC requested the range of biomass plant capacities to be considered match that of the previous investigations in the FEED Study. Using the range of 0.5 MWe to 2.0 MWe as a basis, Table 1.0 outlines the technologies pursued for this effort along with their assumed capacities. This study looks at three technologies types covering conventional approaches for biomass power generation / cogeneration, as well as the developing market of gasification systems. The conventional technologies utilize a biomass combustion system of varying designs to combust biomass (wood chips) to heat a fluid (water for steam or thermal oil to transfer to an organic fluid) which is used in a prime mover (turbine-generator). Gasification technologies use varying designs to gasify the biomass to generate a synthetic gas or syngas, which is then used in a reciprocating engine for power generation. The syngas can also be oxidized (combusted) to generate heat as in conventional technologies for power generation, though this approach is not considered in this report. Please refer to the FEED study for more detailed explanations of gasification technologies. A secondary plant characteristic, similar to the FEED study, is the potential to use beetle kill biomass as a fuel supply. As presented in Table 1.1, beetle kill biomass would have significantly lower moisture content at approximately 15%, compared to green (live) biomass which is likely to have a range of 40-50%, 50% assumed for study purposes. Refer to the FEED study for a more 1 Stantec Consulting Ltd., 2013, Front End Engineering Design (FEED) Study, Yukon Bioenergy Demonstration Project in Haines Junction, Yukon, Final FEED Report

2 Page 2 of 10 detailed assessment of biomass feedstock. Regardless of source, biomass is assumed to arrive at the plant in the form of wood chips on a self-unloading truck. Table 1.1 Technology Capacities and Description Technology Description Min Gross Capacity Considered Max Gross Capacity Considered Conventional Steam Turbine Conventional Organic Rankine Cycle (ORC) Wood chips fired in combustion system with heat recovery High pressure / temperature steam generated to supply steam turbine-generator for power Steam condensed at low pressure to support heat recovery to district heating network as hot water. Wood chips fired in combustion system with heat recovery Low pressure / high temperature thermal oil is generated to supply organic fluid heat exchanger. Hot organic fluid sent to organic turbine-generator for power. Heat recovery to district heating network as hot water recovered from organic cycle and combustion system 0.5 MWe 2.0 MWe 0.6 MWe 2.3 MWe Gasification Wood chips sent to gasifier to generate producer gas Producer gas sent to gas cleanup system to produce syngas Syngas fired in reciprocating engine with heat recovery Heat recovery to district heating network as hot water. 0.5 MWe 2.0 MWe

3 Page 3 of 10 Table 1.2 Feedstock Characteristics Attributes HHV (dry) HHV (as fired) Ash (%wt dry) Moisture Content Dead spruce 8,000 Btu/lb 6,800 Btu/lb % Live spruce 8,000 Btu/lb 4,000 Btu/lb % Expected Unit Performance Using in-house data and information received from equipment vendors, the following subsections outline the expected performance for each technology for the range considered. Each technologies performance is presented in a score card format for easy comparison. In general, the conventional technologies (steam and ORC) have lower electrical generation efficiencies but have higher overall cogeneration efficiencies (assuming all recoverable heat can be used). For comparison purposes in the score card, the district heating network plant for Haines Junction in the FEED study is used to show the magnitude of heat generated. For most cases, the difference in heat available and that usable in Haines Junction is at least eight (8) to 100 times, indicating that distributed generation with smaller units properly matched to heat requirement are most advantageous. Both conventional technologies would be housed in a building along with their material handling infrastructure. The gasification technology presented is a blend of units considered during the FEED study, mainly Community Power Corporation, Proton Power, and Borealis Wood Power Group (Spanner). Units are available in 45 kwe to 250 kwe sizes, and are sold in multiples to achieve the generation capacities considered for this report. All units come in a containerized form and can be daisy chained together to reduce material handling and balance of plant equipment requirements. The technologies vary in fuel moisture requirements, any can be supplied with dryers for higher moisture content fuels, and typically looking to achieve moisture levels around 15% (alternatively can operate on wood pellets at 8%). Given the level of maturity of the conventional systems, they are able to achieve an availability in the range of 90-95% depending on operating conditions. The limiting factor is typically the combustor/heat recovery unit s operations as opposed to the prime mover (steam turbine/orc). The general consensus for availability of the gasification systems is approximately 80%. Vendor s indication 90%+ should be achievable as the technology matures, but current installations are achieving the 80% mark. Quoted electrical efficiencies are higher with the gasification technologies though usable heat recovery is typically lower than conventional units. One aspect not covered in this report is the generation of biochar by the gasification technologies. The biochar byproduct of the process can be readily collected and sold on the open market for a variety of uses.

4 Page 4 of 10 Conventional Boiler / Steam Turbine Block Diagram Expected Performance 0.5 MWe Case 2.0 MWe Case Electricity Gross Power (kwe) 500 Gross Power (kwe) 2,000 Net Power (kwe) 400 Net Power (kwe) 1,825 Availability (%) 92 Availability (%) 92 Annual Gross Gen (kwh) 4,029,600 Annual Gross Gen (kwh) 16,118,400 Annual Net Gen (kwh) 3,223,680 Annual Net Gen (kwh) 14,708,040 Recoverable Heat (kwth) 4,478 Recoverable Heat (kwth) 16,881 Annual Recoverable (kwh) 36,089,098 Annual Recoverable (kwh) 136,047,355 Annual Haines Junction (kwh) 1,283,645 Annual Haines Junction (kwh) 1,283,645 Gross Electrical Efficiency (%) 8.2 Gross Electrical Efficiency (%) 8.7 Net Electrical Efficiency (%) 6.6 Net Electrical Efficiency (%) 7.9 Max Gross Cogen Efficiency (%) 81.9 Max Gross Cogen Efficiency (%) 81.9 Max Net Cogen Efficiency (%) 80.2 Max Net Cogen Efficiency (%) 81.1 HJ Gross Cogen Efficiency (%) 10.8 HJ Gross Cogen Efficiency (%) 9.4 HJ Net Cogen Efficiency (%) 9.2 HJ Net Cogen Efficiency (%) 8.6

5 Page 5 of 10 Typical Thermal Oil Organic Rankine Cycle (ORC) Block Diagram Expected Performance 0.5 MWe Case 2.0 MWe Case Electricity Gross Power (kwe) 643 Gross Power (kwe) 2,270 Net Power (kwe) 551 Net Power (kwe) 2,103 Availability (%) 92 Availability (%) 92 Annual Gross Gen (kwh) 5,182,066 Annual Gross Gen (kwh) 18,294,384 Annual Net Gen (kwh) 4,440,619 Annual Net Gen (kwh) 16,948,498 Recoverable Heat (kwth) 2,957 Recoverable Heat (kwth) 7,256 Annual Recoverable (kwh) 23,831,377 Annual Recoverable (kwh) 58,477,555 Annual Haines Junction (kwh) 1,283,645 Annual Haines Junction (kwh) 1,283,645 Gross Electrical Efficiency (%) 14.1 Gross Electrical Efficiency (%) 17.2 Net Electrical Efficiency (%) 12.0 Net Electrical Efficiency (%) 15.9 Max Gross Cogen Efficiency (%) 78.7 Max Gross Cogen Efficiency (%) 78.2 Max Net Cogen Efficiency (%) 76.7 Max Net Cogen Efficiency (%) 77.0 HJ Gross Cogen Efficiency (%) 17.5 HJ Gross Cogen Efficiency (%) 18.4 HJ Net Cogen Efficiency (%) 15.5 HJ Net Cogen Efficiency (%) 17.1

6 Page 6 of 10 Biomass Gasification Block Diagram Expected Performance 0.5 MWe Case 2.0 MWe Case Electricity Gross Power (kwe) 500 Gross Power (kwe) 2,000 Net Power (kwe) 369 Net Power (kwe) 1,551 Availability (%) 80 Availability (%) 80 Annual Gross Gen (kwh) 3,504,000 Annual Gross Gen (kwh) 14,016,000 Annual Net Gen (kwh) 2,585,527 Annual Net Gen (kwh) 10,867,709 Recoverable Heat (kwth) 1,150 Recoverable Heat (kwth) 4,600 Annual Recoverable (kwh) 8,059,200 Annual Recoverable (kwh) 32,236,800 Annual Haines Junction (kwh) 1,283,645 Annual Haines Junction (kwh) 1,283,645 Gross Electrical Efficiency (%) 22.5 Gross Electrical Efficiency (%) 22.5 Net Electrical Efficiency (%) 16.6 Net Electrical Efficiency (%) 17.4 Max Gross Cogen Efficiency (%) 74.3 Max Gross Cogen Efficiency (%) 74.3 Max Net Cogen Efficiency (%) 68.4 Max Net Cogen Efficiency (%) 69.2 HJ Gross Cogen Efficiency (%) 30.7 HJ Gross Cogen Efficiency (%) 24.6 HJ Net Cogen Efficiency (%) 24.8 HJ Net Cogen Efficiency (%) 19.5

7 Page 7 of 10 Opinion of Probable Capital and Operating Cost Based on in-house data and vendor budgetary quotations, an opinion of capital cost was generated for the proposed projects. Costing is based on previous work with plants at this capacity and work completed during the FEED study. The opinion of capital cost is expected to be at a AACE Class 4 level. Table 3.1 Class 4 Opinion of Capital Cost (Steam Turbine and ORC) Boiler / Steam Turbine Thermal Oil ORC 0.5 MWe Case 2.0 MWe Case 0.5 MWe Case 2.0 MWe Case Direct Costs Major Equipment Combustor / Heat Recovery $2,180,000 $3,720,000 $2,000,000 $3,170,000 Prime Mover $455,000 $655,000 $1,975,000 $3,425,000 Balance of Plant/Shipping $400,000 $660,000 $600,000 $990,000 Installation Site Prep / Building / Foundation $3,250,000 $3,750,000 $3,250,000 $3,750,000 Piping / Mechanical $860,000 $890,000 $910,000 $940,000 Electrical, I&C $910,000 $945,000 $930,000 $965,000 Subtotal Directs $8,055,000 $10,620,000 $9,665,000 $13,240,000 Indirect Costs General Contractor (Mob/Demob, Insurance, $1,208,000 $1,593,000 $1,450,000 $1,986,000 Consumables) (15%) Engineering, Procurement, Commissioning & Start-up $806,000 $1,062,000 $967,000 $1,324,000 (10%) Contingencies (15%) $1,208,000 $1,593,000 $1,450,000 $1,986,000 Subtotal Indirects $3,222,000 $4,248,000 $3,867,000 $5,296,000 Total Facility Capital Cost $11,277,000 $14,868,000 $13,532,000 $18,536,000

8 Page 8 of 10 Table 3.2 Class 4 Opinion of Capital Cost (Gasification) Direct Costs Major Equipment Gasification 0.5 MWe Case 2.0 MWe Case Gasification Units $4,920,000 $17,710,000 Balance of Plant/Shipping $740,000 $2,660,000 Installation Site Prep / Building / Foundation $2,000,000 $3,250,000 Piping / Mechanical $400,000 $780,000 Electrical, I&C $550,000 $985,000 Subtotal Directs $8,610,000 $25,385,000 Indirect Costs General Contractor (Mob/Demob, Insurance, Consumables) (15%) $1,076,000 $3,173,000 Engineering, Procurement, Commissioning & Start-up (10%) $861,000 $2,539,000 Contingencies (15%) $1,292,000 $3,808,000 Subtotal Indirects $3,229,000 $9,520,000 Total Facility Capital Cost $11,839,000 $34,905,000 Operating and Maintenance Cost Predicted O&M costs are based on the technology considered, the likelihood that the conventional systems will require stationary engineers to operate the plant (where steam or thermal oil based), and those developed during the FEED study for the gasification units. The O&M opinion of probable cost is based on the use of an outside O&M contractor. Operations and maintenance costs for the biomass plant consists of several components: Labor. Maintenance and Materials. Annual Environmental Testing. Consumables and chemicals. Miscellaneous supplies.

9 Page 9 of 10 The items included in each category are explained below: Labor - The labor component, excluding fuel cost and renewal fund, is the largest cost in an O&M budget. It consists of the salaries and benefits for the operators and admin staff. The size of the staff can vary significantly depending on the size and complexity of the plant. For a typical biomass plant, the operation will consist of at least five (5) full-time operators. The staffing compliment is assumed to be lower for the gasification units assuming they can be operated remotely/during day shifts only according to vendors. Staffing compliment needs to be confirmed with local regulators Maintenance and Materials - The cost for maintenance and materials reflects normal daily, weekly, monthly costs for regular plant maintenance. Environmental Testing - Most environmental operating permits require annual testing for any air, water or waste water discharges from a plant to verify compliance with the permit conditions. Consumables and Chemicals - The cost of lubricants, oils, chemicals and misc. consumables used during normal plant operation is included in this line item. Misc. Supplies - This item covers the general administrative cost of running the power plant. It includes phones, office supplies, computers, etc. Table 3.3 and 3.4 outline the opinion of probable operating and maintenance costs for the options considered in the report. Table 3.3 Class 4 Opinion of Capital Cost (Steam Turbine and ORC) Boiler / Steam Turbine Thermal Oil ORC 0.5 MWe Case 2.0 MWe Case 0.5 MWe Case 2.0 MWe Case Labor $520,000 $520,000 $520,000 $520,000 Maintenance & Materials $50,000 $125,000 $50,000 $125,000 Environmental Testing $20,000 $35,000 $20,000 $35,000 Consumables & Chemicals $15,000 $45,000 $15,000 $45,000 Misc. Supplies $10,000 $25,000 $10,000 $25,000 Total O&M Annual Cost ($) $615,000 $750,000 $615,000 $750,000

10 Page 10 of 10 Table 3.4 Class 4 Opinion of Capital Cost (Gasification) Gasification 0.5 MWe Case 2.0 MWe Case Labor $200,000 $350,000 Maintenance & Materials $50,000 $200,000 Environmental Testing $15,000 $50,000 Consumables & Chemicals $15,000 $60,000 Misc. Supplies $5,000 $15,000 Total O&M Annual Cost ($) $285,000 $675,000 Regards, STANTEC CONSULTING LTD. Chris van Driel, CEM, CMVP, P.Eng. Director of Business Development, Thermal Energy (Canada) Phone: (506) Fax: (506) Chris.vanDriel@stantec.com c. Rod Savoie clm v:\1335\active\ \8_mechanical\8_report\let_cgv_ _biomass_update.docx