for information, contact: jessica bridges, cae iom...

105 North Virginia Avenue, Suite 204 Falls Church, VA 22046

www.uschpa.org

Document prepared by:

For information, contact:

Jessica Bridges, CAE IOM Executive Director

[email protected] 703-348-2249

Installation information extracted from U.S. Department of Energy CHP Installation Database.

Case studies supplied by the U.S. Department of Energy Clean Energy Application Centers.

Combined Heat and Power Units located in Washington

State City Organization Name Facility Name Application SIC4 NAICS Op Year

Prime Mover

Capacity (kw)

Fuel Type

WA Aberdeen Sierra Pacific Industries Inc

Sierra Pacific Aberdeen Wood Products 2421 321113 2003 B/ST 18,000 WOOD

WA Anacortes March Point Cogeneration

Company-Phase I

Texaco Puget Sound Refinery Refining 2911 32411 1991 CC 166,800 NG

WA Bellingham PTE North America / Encogen Northwest

L.P.

Georgia Pacific Pulp & Paper Mill Pulp and Paper 2621 322121 1993 CC 170,000 NG

WA Bingen SDS Lumber Co Gorge Energy Div SDS Lumber Co Wood Products 2421 321113 1978 B/ST 8,500 WOOD

WA Bremerton Bremerton Wastewater

Bremerton Wastewater

Wastewater Treatment 4952 22132 . ERENG 152 BIOMASS

WA Burlington Sierra Pacific - Skagit County Sierra Pacific Wood Products 2421 321113 2007 B/ST 28,000 WOOD

WA Camas Georgia-Pacific

Corporation /James River Corporation

Camas Paper Mill Steam Plant Project Pulp and Paper 2621 322121 1996 B/ST 52,000 WOOD

WA Colville Vaagen Bros. Lumber, Inc.

Vaagen Bros. Lumber, Inc. Wood Products 2421 321113 1979 B/ST 4,000 WOOD

WA Cosmopolis Weyerhaeuser Company

Weyerhaeuser Company Pulp and Paper 2611 32211 1957 B/ST 15,000 WAST

WA Darrington Hampton Timber Mill

Hampton Timber Mill Wood Products 2421 321113 2006 B/ST 7,200 WOOD

WA Everett Kimberly Clark / Snohomish PUD

Scott Paper Mill / Everett

Cogeneration Project

Pulp and Paper 2621 322121 1996 B/ST 52,200 WOOD


Prime Mover

Capacity (kw)

Fuel Type

WA Ferndale Whatcom Co. MSW Whatcom Co. MSW Solid Waste Facilities 4953 562212 1986 B/ST 2,000 WAST

WA Ferndale Tenaska Washington Partners, L.P.

BP America/Tosco Nw Refinery Refining 2911 32411 1994 CC 270,000 OIL

WA Hoquiam Grays Harbor Paper Grays Harbor Paper Pulp and Paper 2600 322 2000 B/ST 18,500 WOOD

WA Kettle Falls Kettle Falls GT Kettle Falls Generating Station District Energy 4961 22133 2002 CT 7,000 NG

WA Longview Weyerhaeuser Company

Weyerhaeuser Longview Mill Wood Products 2421 321113 1978 B/ST 70,000 WAST

WA Longview Longview Fibre Company Longview Fibre Pulp and Paper 2621 322121 1936 B/ST 135,000 NG

WA Lynden Vander Haak Dairy Vander Haak Dairy Agriculture 241 11212 2004 ERENG 450 BIOMASS

WA Maple Valley

Bio Energy Washington (INGENCO)

Cedar Hills Regional Landfill

Solid Waste Facilities 4953 562212 2009 ERENG 4,680 BIOMASS

WA Monroe Qualco Energy Corporation

Snohomish County dairy digester Agriculture 241 11212 2009 ERENG 450 BIOMASS

WA Olympia LOTT Alliance Budd Inlet Treatment Plant

Wastewater Treatment 4952 22132 2009 ERENG 330 BIOMASS

WA Omak Colville Indian Precision Pine

Colville Indian Precision Pine Wood Products 2421 321113 2002 B/ST 7,500 WOOD

WA Outlook George DeRuyter & Sons Dairy

George DeRuyter &Sons Dairy Agriculture 241 11212 2006 ERENG 1,200 BIOMASS

WA Port Angeles Daishowa Daishowa America

Co. LTD Wood Products 2400 321 . B/ST 0 OIL

WA Port Townsend

Port Townsend Paper Company

Port Townsend Paper Company Pulp and Paper 2621 322121 1990 B/ST 14,500 WAST

WA Pullman Washington State University

Washington State University Colleges/Univ. 8221 61131 1963 B/ST 3,900 COAL


Prime Mover

Capacity (kw)

Fuel Type

WA Renton King County Wastewater

Treatment Div.

South Treatment Plant

Wastewater Treatment 4952 562111 2004 CT 9,500 BIOMASS

WA Rexville Farm Power Northwest Rexville Digester Agriculture 241 11212 2009 ERENG 750 BIOMASS

WA Seattle University Of Washington

University Of Washington Power

Plant Colleges/Univ. 8221 61131 1969 B/ST 5,000 NG

WA Seattle King County Dept-Natural Resources

West Point Treatment Plant

Wastewater Treatment 4952 22132 1983 ERENG 3,900 BIOMASS

WA Spokane Avista Utilities Avista Utilities Utilities 4939 221112 2001 CT 7,520 NG

WA Spokane Spokane Wastewater Spokane Wastewater

Wastewater Treatment 4952 22132 . ERENG 300 BIOMASS

WA Sumas Calpine - Sumas

Cogneration Company LP

Sumas Dry Kilns/Socco, Inc. Wood Products 2421 321113 1993 CC 125,500 NG

WA Tacoma Simpson Tacoma Kraft Company

Simpson Tacoma Kraft Pulp and Paper 2621 322121 2009 B/ST 55,000 WAST

Prime Mover Code Description Fuel

Code Description

B/ST Boiler/Steam Turbine BIOMASS Biomass, LFG, Digester Gas, Bagasse

CC Combined Cycle COAL Coal CT Combustion Turbine NG Natural Gas, Propane FCEL Fuel Cell OIL Oil, Distillate Fuel Oil, Jet Fuel, Kerosene, RFO

Prime Mover Code Description Fuel

Code Description

MT Microturbine WAST Waste, MSW, Black Liquor, Blast Furnace Gas, Petroleum Coke, Process Gas

ERENG Reciprocating Engine WOOD Wood, Wood Waste

OTR Other OTR Other

State Summary for Washington

Prime Mover Code Sites Capacity (kW) Total 34 1,264,832 B/ST 18 496,300 CC 4 732,300 CT 3 24,020 FCEL 0 0 MT 0 0 OTR 0 0 ERENG 9 12,212

Kimberly Clark Paper Mill 1 CHP Case Study

CHP Case Studies in the Pacific Northwest

52 MW Wood-Chip Fired Steam-Turbine Generator

Site Description Kimberly-Clark is a global health andhygiene company, with annual sales in excess of $14 billion. Well-recognized brand names include Kleenex®, Huggies®, Cottonelle®, Scott®, and Viva®. Its mill in Everett, Washington manufactures pulp and a variety of consumer and business-to-business tissue products. The Utilitiesoperation includes a cogeneration boilerwith a 52 MW generator, a recovery boiler,and three auxiliary boilers. The mill employs850 people.

The Snohomish County PUD and the mill (then owned by Scott Paper) jointly began construction of the $115MM cogeneration

facility in 1993. The PUD provided the capital and owns the project in addition to receiving the electricaloutput. KC provided constructionmanagement and operates/maintains the facility, receiving steam for its tissue mill processes.

The mill initiallyapproached PUD inDecember of 1990. A memorandum of understanding was executed in April of

1992, and construction & operating contracts executed in October 1993.

Kimberly Clark Mill in Everett, Washington

Ground breaking began that same month.The project was commissioned and beganlimited operation at the end of 1995 with full commercial operations in August 1996.

By working cooperatively with the local utility, Kimberly Clark was able to upgradethe mill with the latest technology boiler and thereby enhance the economics andstability of mill operations. Snohomish PUD acquired a generating resource near a large urban load center powered by renewable energy.

Plant Configuration The new wood boiler (#14) is a screw-fed,sloping grate design by Gotaverken (nowKvaerner) that is based on a mass burn design used in Europe and at a few other locations in North America. This configuration was selected over the more common stoker grate or fluidized beddesigns in order to handle the wide range of fuel sizes expected at the plant and toachieve very low NOx emissions.

At design conditions, 435,000 lb/hr of 825 psig, 850°F superheated steam from thewood-fired boiler is combined with 276,000lb/hr of high-pressure steam from the mill's recovery boiler burning waste liquor. The condensing steam turbine drives the generator and produces low-pressure steam for process use in the mill.

The 16-stage, General Electric extraction steam turbine has a rated capacity of 46.9 MW. Steam enters the turbine at about 800 psig and is extracted at 300 and 40 psig.The generator has a rated capacity of 52.2 MW. The condenser normally condenses 150,000-220,000 pounds/hour of exhaust

steam from the turbine (the difference between the amount of steam generated in the two boilers and the amount of steam used in the mill). However, the condenser is capable of condensing 350,000 pounds/hour of steam; this allows the wood-fired boiler to operate as a stand-alonepower plant when the mill is down. Thecapacity of the wood-fired power plant when operating in a stand-alone electric generating mode is about 39 MW.

The plant has a fuel receiving and storagesystem that can handle wood wastes in a range of sizes. Five groups of three screwseach feed the wood wastes into the boiler.

The fuel consists of both mill residues and urban wood wastes. Mill residues – barkand hogged wood – are supplied by millslocated in Puget Sound, Olympic Peninsula, and British Columbia. Urban wood wastes consist of wood wastes such as pallets and land clearing debris. The share of urbanwood waste, and especially the landclearing debris, increases during the summer. The fuel mix has been runningabout 40% mill residue and 60% urban wood waste during the summer and agreater proportion of mill residue during the


winter. As logging operations in the region decline, the proportion of urban wood waste in the mix will increase.

At times, in order to maintain steam production or to adjust to fuel or ash handling upsets, it is necessary to supplement the wood fuel with natural gas.

Energy/Financial Analysis KC and PUD signed a 21 year contract, renewable every 5 years thereafter. PUDprovided the capital and KC built and operates the plant. During the first fifteen years of operation, the paper mill buys the fuel, operates and maintains the facility, and uses the steam. Starting in year 10 the utility will pay an increasing portion of the fuel cost. Starting in year 16, the utility will also pay part of the O&M cost.

The mill has rights to 6,000,000 MMBtu of steam from the plant. PUD has rights to 325,000 MWh/year of the power output.Penalties for under-delivery of power are based on the Mid Columbia Electricity Wholesale Price Index.

PUD has a long-term contract with Sacramento Municipal Utility District (SMUD) to sell an average of about 33 MW through the year 2007. This was done to eliminate any early-year rate impacts on

Snohomish County PUD customers. Under terms of the contract, SMUD will purchase energy and capacity at a levelized real rate of 4.1¢/kWh throughSeptember 2007. This contractprice is higher than the prevailingwholesale rates in the Northwest.The power purchase agreementallows SMUD to purchase up to 36 MW during summer months and 26 MW at other times of the year. SMUD has the option of shifting a portion of the available wintercapacity and energy, and using it for summer delivery. Summerscheduling is capped at 42 MW. After the SMUD purchase period

concludes, PUD intends to bring the power back to serve local customers.

Everett Mill Utilities Complex

The Kimberly-Clark Everett mill is a retailcustomer of Snohomish County PUD, and consumes nearly as much electricity as the cogeneration plant produces. There is an average of about 5 MW of export power available from the mill.

Operating Experience and ResultsActual power output during the plant’s operating history has been consistentlysomewhat lower than the contractedamount due to reduced mill operations and underperformance of the boiler.

Approximately 25 different vendors supply wood waste for the boiler. These multiple supply sources cause a variation in fuelcomposition that needed to be addressedby fuel blending. The average heat content of the wood waste fuel input is 19,000Btu/kWh.

The boiler generates 425,000 pounds/hourof steam with 55% moisture fuel, comparedto the design values of 435,000 pounds/hour with 60% moisture fuel. When 60% moisture fuel is received (in the rainy season, which typically peaks in January


and February), the auxiliary natural gas, burner must be used.

There were a variety of startup problems including fuel slides, slagging, failure of superheater tubes, fuel and ash handlingproblems, pressure parts, and other performance issues. Several changes have been made to the boiler design and in operating procedures. Changes were made in air nozzle locations, grate design,and other areas. The unit now operates more reliably and with higher output.

Environmental Profile On start-up and initial operation, the boiler was unable to meet the original guaranteeson NOx emissions and carbon carryover.The wide variation in fuel types, sizes, and moisture content, created control problemswhich were addressed by improved fuel blending in the yard, and by adjusting the grate and the feed systems. Attempting to control NOx with additional ammonia injection caused a visible plume. These problems were reduced by increasing the secondary (overfire) air injection rate to

increase turbulence, and by decreasing the ammonia injection rate.

The higher NOx emissions were addressed by installing an ammonia injection system on the older recovery boiler. Ammoniainjection into the flue gas at the wood-fired boiler was discontinued. The recovery boiler has a better profile than the wood-fired boiler, so the reduction of NOx emissions by ammonia injection is much more efficient in that boiler. All permit requirements are being met.

An existing bag-house serving the old wood waste boilers was upgraded to provide particulate control for the new boiler.

Lessons LearnedThere were both positive and negative lessons learned from this project.

On the positive side, cost reductions wereachieved by the project by cooperative cost sharing between Kimberly Clark and Snohomish PUD. Each of the partnersfocused on their strength. KC had

General Electric Steam Turbine Generator


experience constructing and operating boilers, while PUD had access toinexpensive capital and the ability to marketthe electrical output. The use of an existingsite meant that the infrastructure wasalready in place – water, gas, electricalinterconnection, and water treatment.PUD’s existing power supply portfolio simplified integrating the plant electricaloutput into the resource mix.

There were some harder lessons learned.Technically, the boiler never performed up to its specifications, resulting in loweredoutput and the need to burn natural gas to maintain steam output during certainperiods.

In addition, the mill and the utility had very dissimilar general business activities andinstitutional environments. There was little common understanding of each party’saccepted business practices such as risktolerance, environmental decision-making process, duration of contractualrequirements, and public disclosure requirements.

Future Plans PUD is currently engaged in an integratedresource plan to determine the most cost effective options for meeting future powerneeds. There are no immediate plans to expand production at the site or to seekadditional CHP projects.

Organizational Profile Snohomish PUD – Owner, Financing,Marketing of Electrical OutputKimberly-Clark – General Contractor and Site Host Major Subcontractors: HA Simons – Engineering and Procurement Gotaverken – Wood-Waste Boiler & itsFacilities & T/G Building Fletcher General – Construction of Substation, Underground Piping, andElectrical Distribution System within the KC mill.

General Electric – Manufacturing andinstallation of Turbine Generator and auxiliaries:

ContactsSteve ZwallerKimberly [email protected]

Robin Cross Cogeneration Project Manager Snohomish Public Utility District [email protected]

Case study based on presentation made by Cross and Zwaller at The Northwest CHP Roundtable, June 23, 2003 and by an evaluation by G. Wiltsee, Lessons Learnedfrom Existing Biomass Powerplants,NREL/SR-570-26946, 2000.

For information on other case studiescontact:Ken Darrow Energy and Environmental Analysis, Inc. West Coast OfficeBellevue, Washington 425-688-0141


Case Study: King County South Treatment Plant Renton, Washington Combined heat and power using a molten carbonate fuel cell – 1.0 Megawatt of electrical output (MWe)

July 2006 WSU EEP06-03 Dr. R. Gordon Bloomquist, Washington State University Extension Energy Program 925 Plum St SE, Bldg 4 • P.O. Box 43165 • Olympia, WA 98504-3165 (360) 956-2004 • Fax (360) 236-2004 • TDD: (360) 956-2218

Cooperating agencies: Washington State University Extension Energy Program, U.S. Department of Energy, Alaska Energy Authority, Idaho Department of Water Resources Energy Division, Montana Department of Environmental Quality Energy Program and Oregon Department of Energy

Combined Heat and Power (CHP) Case Study CHP Using a Molten Carbonate Fuel Cell

King County South Treatment Plant Renton, Washington

July 2006

This King County photo shows the electrical balance of plant.

Introduction In the early to mid 1990s King County, Washington, began to evaluate the potential for employing molten carbonate fuel cells as a means of providing on site generation based upon anaerobic digester gas at their South Treatment Plant in Renton (a wastewater treatment facility). In the photo, the skid mounted inverter converts direct current (DC) current to alternating current (AC) power. The fuel cell stacks are located in the pressure vessel to the right of the photo. King County has long been an innovator in energy efficiency and as early as approximately 1982 had installed water-to-water heat pumps that transferred heat from the plant effluent to the anaerobic digesters. By so doing, methane was no longer needed for heating purposes and instead was scrubbed and sold to the local natural gas

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distribution company. King County felt that the development of a fuel cell based system would be an even better strategy to produce both power as well as heat. In 1997, they entered into an agreement with MC Power to pursue the development of a research and development (R&D) facility with a commitment for partial funding from the U.S. Environmental Protection Agency (EPA) and the U.S. Department of Energy (DOE). Unfortunately for all concerned, MC Power went into bankruptcy when the DOE decided in 1999 to downsize its molten carbonate fuel cell program and funding of future R&D work by MC Power was eliminated.

• Despite this initial set back, King County with continued support from EPA went out for bid to complete the project and eventually entered into an agreement with Fuel Cell Energy of Danbury, Connecticut, in 2000. The resulting King County Fuel Cell Demonstration Project is the world’s largest demonstration project of a molten carbonate fuel cell using anaerobic digester gas. The demonstration project was commissioned in April 2004. The demonstration period ends in September 2006 at which time King County has the right take over and to continue to operate the project.

The objectives of the project are:

• Demonstrate that molten carbonate fuel cell technology can be adapted to use anaerobic digester gas as the fuel source; and

• Achieve a nominal plant power output target of 1 MWe (net AC) using either digester gas, scrubbed digester gas or pipeline natural gas. After the demonstration, King County has the potential to operate the power plant at 1.5 MWe by installing a larger fuel cell stack.

The participants in the project are:

• King County • Fuel Cell Energy Inc. • U.S. Environmental Protection Agency • CH2M Hill • Brown and Caldwell • Hawk Mechanical The project is being reviewed by a team of experts comprised of representatives of state and federal government, national laboratories, academia, and industry.

Site Description The King County Department of Natural Resources South Treatment Plant is located in Renton, Washington, and is one of two major wastewater facilities serving the greater Seattle/Bellevue Area. The plant has undergone a number of expansions over the past two decades and now has a capacity of approximately 90 million gallons per day with ample room for further expansion should the need arise. The facility’s electrical demand is approximately 5.5 to 7.5 MWe on an average basis. The plant has four anaerobic digesters with a total capacity of approximately 240 thousand gallons and a thermal

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demand for the digesters of approximately 7,142 kilowatt-ton (kWt) or 174 million British Thermal Units (Btu) per hour. Total gas production from the digesters is approximately 1,200 cubic feet/day with an average Btu content of 548 Btu/cubic foot. Market Segment Evaluation A critical component of the initial evaluation of the use of a molten carbonate fuel cell(s) at the Renton facility was a national assessment of the potential for employing such technology at similar facilities throughout the United States. In order to ascertain the market potential, MC Power contracted with engineering firm CH2M Hill in 1997 to conduct a national survey. CH2M Hill identified a total of 134 wastewater treatment facilities having a potential for the generation of 347 to 425 MWe. Technical Description The 1 MWe molten carbonate fuel cell demonstration project has as its primary objectives:

1. Demonstrate that molten carbonate fuel cell technology can be adapted to use anaerobic digester gas as a fuel source; and

2. Achieve a nominal power plant output target of 1 MWe (net AC) using either digester gas, scrubbed digester gas or pipeline natural gas.

As a pilot project the facility was intended to provide only a small percentage of the electrical and thermal requirements of the wastewater facility. Total electrical demand for the facility is 5.5 to7.5 MWe and the total demand is 174 million Btu per hour. The project is designed to provide on site power and thermal energy without any export to the local utility. Also because of the nature of any demonstration project the system requires total backup by Puget Sound Energy the serving utility. The molten carbonate fuel cell is being operated on utility-provided natural gas, scrubbed anaerobic digester gas and un-scrubbed digester gas (sulfur is removed from the digester gas). Thermal energy from the molten carbonate fuel cell is available in the form of hot water up to 1.4 million Btu (MMBtu) per hour is available for use in heating the digesters. A molten carbonate fuel cell needs the incoming fuel to be about 1200 degrees Fahrenheit (the fuel cell’s operating temperature). The heat recovery unit is designed to run when the fuel cell is generating power, not under hot standby or startup conditions. The hot water loop pumps, control valves and the blower are all fully automated.

• Incoming air temperature to the boiler is 580° F. • Outgoing air temperature for the boilers is 240° F (change in temperature equals

340° F). • Incoming water temperature for the main system in tunnel is 136° F. • Outgoing boiler water temperature is 154° F (change in temperature equals 18° F.

The fuel supply to the fuel cell is as follows:

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1. Gas #1 = Natural gas from King County: Anaerobic digester gas that has been scrubbed on-site to pipeline quality gas.

2. Gas #2 = Natural gas from Puget Sound Energy: Natural gas supplied by the local gas utility.

3. Gas #3 = Raw digester gas: Unscrubbed anaerobic digester gas from the digester gas scrubber header (only sulfur is removed).

Each supply source is part of the demonstration. An input flow of approximately 149 cubic feet per minute (cfm) is required from gases 1 and 2 to achieve the fuel cell rated output of 1 MWe, while approximately 227 cfm is required for gas 3 to achieve the same rated output. The natural gas has a measured lower heating value (LHV) of 900 Btu/cubic foot and the LHV for the digester gas is 548 Btu/cubic foot un-scrubbed. System Efficiency System efficiencies with heat recovery range from 60 to 65 percent. Electrical efficiency is from 43 to 47 percent (lower heating value). The 1 MWe of net power output is de-rated by 2 percent every six months as fuel cell stacks age. Parasitic Loads Gas Type Balance of plant loads/kWe Transformer/inverter loss/kWe Total kWe Natural Gas 48-53 37 85- 90 Digester Gas 55-75 (including compressor)* 37 92-112 * The digester gas has an additional load for the gas compressor of about 40 kWe. Performance Summary

Fuel Cell Performance Summary on Natural Gas Year 2004 2005 Parameter Q2&Q3 Q4 Q1 Q2 Q3

Run Time Hrs 1,897 970 730 1,115 0 Power Gen KWh 1.4 M 0.5934 0.6974 1.1M 0 Availability 93% 100% 100% 84% 76% Shut Down 7% 0% 0% 16% 24% Efficiency* 43% 43% 42% 43% NA *Based on electricity out/natural gas in.

Fuel Cell Performance on Digester Gas Year 2004 2005 Parameter Q2&Q3 Q4 Q1 Q2 Q3

Run Time Hrs 313 490 1,270 691 0 Power Gen Kwh 76,664 357,000 1.158M 489k 0 Availability 65% 95% 90% 94% 76% Shut Down 35% 5% 10% 6% 24% Efficiency* 44% 44% 43% 44% NA *Efficiency based on electricity out/natural gas in.

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Project Cost Total cost for the project exceeds 22.5 million dollars. However, much of that cost is due to the research and demonstration nature of this project and requirements for instrumentation and monitoring. According to Greg Bush, the King Country Project Manager, a similar facility could be delivered at approximately 5 million dollars. Operation and Maintenance Issues

This King County photo shows the sulfa-treat vessels (for digester gas scrubbing). A number of operation and maintenance issues have been identified to date during the startup and initial operation of the fuel cell plant. Of particular note have been issues related to the various gas supplies. Since the fuel cell is being tested using three different gas supplies it has been necessary to make certain modifications to the facility to deal with the varying chemical compositions of the gases. In the case of the gas delivered by the local distribution company, it was learned that the gas contained unusually high amounts of carbonyl sulfide (COS). This required the addition of a third cold gas desulfurizer vessel. When the scrubbed digester gas was used and it did not meet the utilities specifications it was returned to the header causing a rapid spike in the methane concentration of raw

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digester gas. The rapid spike caused a system shutdown as a safety precaution. This could be remedied by the addition of a new pipeline directly from the digesters. Several changes to the facility have also been made to facilitate maintenance. These include addition of platforms and ladders to provide better and safer access; addition of water booster pumps for potable water for gas humidification; revisions to control and logic to incorporate capability of managing plant response to gas diverts; and repairs related to a gasket leak at the fuel gas deoxidizer flange. Facility staff training in operation and maintenance procedures took approximately one year after initial operation. Another major operational issue has been achieving full remote operation of the facility from the offices of Fuel Cell Energy in Danbury, Connecticut. This will allow Fuel Cell Energy to provide continued oversight and assistance throughout the transition period to local operational staff and beyond. Interconnection Issues King County experienced a number of interconnection problems prior to reaching agreement with the serving utility resulting in the need for extra relay protection for the facility. Such problems caused delays in completion of the project and extra costs were incurred. Environmental Issues More than 90 percent of the wastewater treatment plants in the United States generate anaerobic digester gas (ADG) as a byproduct of the sewerage treatment process. ADG is a mixture of gases, mainly methane (ca 60 percent), carbon dioxide (CO2) and water vapor. When ADG is released uncombusted, it contributes significantly to the greenhouse effect–methane having an impact some 23 times that of carbon dioxide. When ADG is flared, the combustion generates photoreactive ozone precursors such as nitric oxides and volatile organic compounds. Fuel cells emit much smaller amounts of such nitric oxides (NOx) and volatile organic compounds. The Renton Molten Carbonate Fuel Cell project is designed to achieve the following emission goals:

• Carbon monoxide (CO) less than 10 parts per million (ppm) Volume • NOx less than 2 ppm Volume • Non-Methane Hydrocarbons (NMHC) less than 1 ppm Volume

To date the facilities emissions are as follows: • CO less than or equal to 13 ppm • NOx less than or equal to 0.2 ppm • NMHC none detected

Next Steps King County hopes to complete the demonstration in September 2006 with report writing to follow. Upon completion of the demonstration, King County intends to continue to

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operate the fuel cell. For further information see King County’s library of information at http://dnr.metrokc.gov/wtd/fuelcell/library.htm. Acknowledgements The Northwest CHP Application Center wishes to especially thank the staff of King County and in particular Greg Bush for their persistence and hard work throughout the demonstration period. Northwest CHP Application Center For further information about the Northwest CHP Application Center please visit our website www.chpcenternw.org/ or contact Dave Sjoding at 360.956-2004 or [email protected].

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Case Study: Valley Medical Center, Renton, WA Combined Heat and Power - 3.6 MWc

Date: May 2005 WSU EEP05-023 Bob O’Brien, P.E. WSU Extension Energy Program 925 Plum St SE, Bldg 4 • P.O. Box 43165 • Olympia, WA 98504-3165 (360) 956-2004 • Fax (360) 236-2004 • TDD: (360) 956-2218


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Valley Medical Center 3.6 MW Gas Fired, Reciprocating Engines, Cogeneration Plant

Site Description

The Valley Medical Center (VMC) is the largest nonprofit health provider between Seattle and Tacoma, Washington. The Center provides a wide variety of medical services to the community including surgical, and 24-hour emergency care. Valley serves as a regional center, providing specialized treatment in cardiology, oncology, high-risk obstetrics, orthopedics, neurology, and pediatrics. The hospital is licensed for 302 beds. The hospital campus was dedicated on October 4, 1969 at its current site. Over the years the Hospital expanded, added and changed. From 1977 to 1983, $23 million was spent adding on a new Emergency Treatment Center, Surgicenter and Children's wing. More beds were added and other departments expanded. VMC quadrupled in size from 254,000 to 1.3 million square feet between 1969 and 1997.

Faced with a history of growth and uncertain future energy prices, the VMC elected to build a 3.6 MW cogeneration plant in 1997. They invested $6 million in the project and selected four 900 kW gas-fired, spark-ignited reciprocating engines as prime movers, because their electric-to-thermal output ratio was the best fit for the campus energy profile. The plant was sized to displace electricity purchased by VMC. The project objectives did not include exportation of any power to the grid. Three cogeneration units were intended to satisfy electrical demand on the campus, with the additional unit as standby. A key factor in the project planning was to establish a firm 10-year natural gas contract, which expires in 2007. The current firm price is about 25 percent of the current market price for natural gas. Due to maximum consumption limitations in the gas contract, the VMC cogeneration plant is currently limited to using an average of 5,300 therms per day or about 159,000 therms (159 kTherms or 15,000 million BTU’s) per month; this limited the CHP plant in 2004 to producing about 58 percent of the total electricity consumed by VMC (see Table 2).

Figure 1. Valley Medical Center Campus Layout

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The plant became fully operational in 1998.

Figure 2. Cogeneration Plant at Valley Medical Center

Plant Configuration The cogeneration plant consists of four 20-cylinder Jenbacker Energiesysteme Ltd (Austria) spark-ignited V—block-rpm engines geared to1800-rpm generators to produce 898 kW each (see Figures 3 and 4). There are four waste-heat recovery boilers attached to each cogeneration unit. Three Cleaver Brooks steam boilers are piped in parallel with the heat recovery boilers to provide supplemental energy to the steam network. In addition, water cooling the engine jackets produces about 139 gal/min of 185F water under design conditions. Due to the limitations in available gas to the VMC and the cogeneration plant, most of the thermal energy is produced by the steam boilers (See Table 1 and Figure 5). The Jenbacker engines are designed with lean-burn low emission controls that maintain an air/fuel ratio of 1.6 to 1.7. The technology achieves low emissions (NOx=1.00 grams/hp-hr, CO = 2.00 grams/hp-hr, and VOC = 0.31 grams/hp-hr) and does not require down stream exhaust cleanup. In general, the operation of the plant has met project expectations during the past six years of service.

Figure 3. Engines and Waste Heat Boilers

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Figure 4. Engines and Generations

Table 1: Annual Total Fuel Usage

Date Natural Gas Used, 1000 Therms

Thermal Energy Produced, lbs of Steam

Boilers CHP Total FromBoilers

FromCHP

Total

Jan '04 66 101 167 3,644,818 1,489,500 5,134,318Feb '04 63 91 154 3,127,078 1,353,000 4,480,078Mar '04 62 102 164 2,951,328 1,447,500 4,398,828Apr '04 33 129 162 2,194,904 1,578,000 3,772,904May '04 21 145 166 1,620,041 1,746,000 3,366,041Jun '04 12 139 151 1,219,183 1,675,500 2,894,683Jul '04 4 136 140 1,142,214 1,633,500 2,775,714Aug '04 9 129 138 1,634,785 1,417,500 3,052,285Sep '04 13 128 141 2,852,467 915,000 3,767,467Oct '04 80 85 165 4,242,463 1,161,000 5,403,463Nov '04 103 59 162 5,315,400 1,473,000 6,788,400Dec '03 38 128 166 2,983,912 1,630,500 4,614,412TOTAL 505 1,372 1,877 32,928,593 17,520,000 50,448,593UNITS 1,000 Therms # of Steam # of Steam # of Steam

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Table 2. Annual Electric Generation and Use in MWhr

2004GeneratedOn-Site

SoldBackto the Utility

Purchasedfrom the Utility

TotalDeliveredto Campus

Peak Electric Power

Demand (kW)

Jan 993 none 646 1,639 n/a Feb 902 none 606 1,508 n/a Mar 965 none 663 1,628 n/a Apr 1,052 none 588 1,640 n/a May 1,164 none 626 1,790 n/a Jun 1,117 none 793 1,910 n/a Jul 1,089 none 1,120 2,209 n/a Aug 945 none 1,143 2,088 n/a Sep 610 none 911 1,521 n/a Oct 774 none 648 1,422 n/a Nov 982 none 532 1,514 n/a Dec '03 1,087 none 159 1,246 n/a Total 11,680 none 8,435 20,115 n/a

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Recovered Heat MMBTUFrom Boilers MMBTU

Figure 5. Annual Thermal Energy Provided

Financial Statistics The cost of gas under the existing contract, which expires in 2007, is about $0.24 per therm delivered to the plant. Therefore, the operating cost of electrical generation (excluding labor and maintenance), based upon the existing contract fuel cost, is about $0.028 per kWh.

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Energy/Financial Analysis Overview The Valley Medical Center determined in early 2005 that the plant would be permanently shut down May 1, 2005, and all the cogeneration assets in the plant would be liquidated. The decision was based upon the fact that the very favorably priced gas contract could not be renewed beyond expiration in August 2007, and it would be more economical for the Medical Center to re-sell the gas available to them under the existing gas contract than to continue operating the cogeneration plant.

Additional Considerations The primary lessons learned by the Valley Medical Center cogeneration project are:

1. It can be very difficult to project future energy costs for cogeneration projects. 2. Changing economic factors occurring during the life of the project may obviate all

assumptions made at the time a project is being planned and developed.

© 2005 Northwest CHP Application Center. This publication contains material written and produced for public distribution. Permission to copy or disseminate all or part of this material is granted, provided that the copies are not made or distributed for commercial advantage, and that each is referenced by title with credit to the Northwest CHP Application Center. Copying, reprinting or dissemination, electronic or otherwise, for any other use requires prior written permission from the Northwest CHP Application Center.

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Case Study: Vander Haak DairyLynden, WA Date: September 2005 updated December 2005 WSU EEP05-025 925 Plum St SE, Bldg 4 • P.O. Box 43165 • Olympia, WA 98504-3165 (360) 956-2004 • Fax (360) 236-2004 • TDD: (360) 956-2218


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Vander Haak Dairy Anaerobic Digester

Authored by Dave Sjoding, Kim Lyons and Chad Kruger*

Quick Facts

Dairy Herd Size 1500 cows (3 cooperating dairies) Type of Dairy Operation Confined year round – Scraped manure Manure Transportation 1.5 mile pipe Digester Type Two stage – modified mixed plug flow Digester Volume/Tank size 4,500 gallons/day – Covered insulated tank Digester Heat 100 degrees – Mesophilic bacteria to make

methane Time for Digestion 22 day cycle Methane production 58% methane Prime Mover for Power Production Modified G 398 Caterpillar engine -

ReciprocatingPower Production 300 kWc and 285 kW net energy – can be

expanded with turbocharger to 450 kWc Waste heat used to heat manure 30 – 60 % Interconnection Engineering study to triple phase Pathogen control 99%

Background – Anaerobic Digestion for Dairies – A solution that leads to more solutions

Washington State has approximately 600 operating dairy farms that manage nearly 250,000 dairy cows. These dairies are often identified as sources of odor, water pollution and air pollution, and are under increasing public and regulatory pressure to control these problems. As a result, effectively managing animal wastes is a critical component of dairy operations and can make a difference in the dairy’s overall success. Most modern dairies utilize a lagoon system for animal waste storage, a practice that often results in odor problems, due to ammonia and volatile organic compounds (VOCs), and can lead to potential water quality concerns, due to nutrient (nitrogen and phosphorous) runoff, when manure is land applied. A lagoon system can also be a large source for methane and nitrous oxide emissions, both of which are greenhouse gases that contribute to global climate change. The Intergovernmental Panel on Climate Change has estimated that the concentration of methane in the atmosphere has increased by more than 150 percent in the last 250 years.

* Sjoding and Lyons – WSU Extension Energy Program and Northwest CHP Application Center; Kruger – WSU Center for Sustaining Agriculture & Natural Resources

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A growing number of dairy farmers are considering anaerobic digesters as an alternative method for managing animal manure. Ideally, these systems mitigate odor problems; protect water quality; reduce greenhouse gas emissions; improve the handling of manure nutrients; control most pathogens; and generate biogas that can be used to produce electricity either for on-farm operations, or for sale into the power grid, or which can be compressed into a liquid fuel. In addition, anaerobic digesters can provide potentially valuable by-products, such as fiber and nutrient water, creating new revenue streams for dairy farms. While these benefits are attractive, producing and managing an anaerobic digestion system is not as simple as operating a manure lagoon and requires a substantial financial and management commitment to be successful.

There are basically three types of anaerobic digesters: 1) Covered lagoon digesters; 2) Complete mix digesters; and 3) Plug-flow digesters. There are also three levels of temperature operating with different bacteria: 1) Ambient (outside air), which is not well suited for our northern climates; 2) Mesophilic (95-105 degrees); and 3) Thermophilic (125-135 degrees). Scrape dairies and flush dairies generally require different specific technologies to do anaerobic digestion. While these systems differ in design, cost, and performance, they all follow the same basic principle where the manure is digested by anaerobic bacteria and converted into a stable effluent and biogas. The biogas generated by the digester contains about 50 to 70 percent methane (600 Btus per standard cubic foot) and can be combusted in an engine to produce electricity. As a rule of thumb for scrapped dairies, modified plug flow mixed mesophilic digesters produce .2 kW per cow per day. Other types of digester systems, operating temperatures and types of animals/feedstock will produce different results. In Washington State alone, using the digester systems such as the Vander Haak dairy, if half of the 250,000 dairy cows were on a farm with anaerobic digestion (AD), as much as 25 MWc of renewable “green” electricity could be generated annually. In addition, as much as 80 million pounds of methane could be captured each year (about 315 thousand tons C equivalent), providing a significant reduction in greenhouse gas emissions. (Note: calculating actual greenhouse gas reductions are more complicated than presented)

Bioproducts & Making Economic and Business Sense

Single purpose bioenergy projects (biopower or biofuels) in the Pacific Northwest rarely make business or economic sense on a stand alone basis. Multiple products with multiple revenue streams (including cost offsets) are the key to business and economic success in our region. In this setting, the development of bioproducts assumes major importance. The Vander Haak dairy is no exception. The following is a table of current products, buyers and prices.

Electricity produced – base price

Puget Sound Energy $.035 / kwh

Green power adder Puget Sound Energy $.015 / kwh Bedding (digested fiber) Used by the dairies (40-60 %

of total) Offsets sawdust @ ~$10/ton

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Compost (digested fiber) Various buyers ~$3 – 6/ton Liquid fertilizer Used by dairies Substitutes for manure

application Carbon credits Sold with Environmental

Credit Corporation 50/50 split at market price on Chicago Climate Exchange

The following is a table of future products, product development leadership and approximate timeline to completion.

Nursery quality digested fiber (in place of peat moss)

WSU Whatcom County Extension

Peat moss from Canada sells to the nursery industry @ $24+

Crystallized phosphorous fertilizer

WSU Center for Bioproducts & Bioenergy

Potential value TBD

Other products could be developed. For example, subject to water availability, co-located greenhouses can use the extra CO2 rich waste heat (40-70 percent of that produced). In addition, digesters help resolve manure management and odor issues, which in turn can enable larger herd sizes. Piping the manure reduces operating costs. The digester in Tillamook, OR is financially troubled, due to transportation trucking costs.

Vander Haak Dairy

The Vander Haak Dairy is a family run farm operating in Lynden, Washington since 1968. It became the first dairy in Washington State to install a commercial anaerobic digester. The system utilizes a patented plug flow digester, designed by GHD Incorporated of Wisconsin, that handles manure from three dairies and up to 1500 dairy cows (as currently configured). In general, plug-flow digesters have few moving parts and work well with dairies, like Vander Haak, that collect cow manure by scraping instead of flushing the manure with water. The unprocessed manure is collected in a receiving pit and pumped directly into the anaerobic digester vessel where it undergoes a two-stage digestion process. In the first stage, raw manure is mixed and heated to 1000F,using the reclaimed waste heat from the engine/generator set. This facilitates the growth of acid forming bacteria that breaks down the raw manure into simpler volatile fatty acids and acetic acid. The slurry then gravity feeds into the second stage of the digester where methanogenic bacteria convert the volatile fatty acids into biogas. The second stage of the digester process takes about 20 days, after which the remaining materials flow into an effluent collection pit where they are further processed. The dairy is currently assessing the impact of other available feedstocks on the system processes.

The biogas generated in the digester is collected and burned in a natural gas fueled reciprocating engine set modified to burn biogas. Waste heat from the engine set is

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recovered and used to heat the digesters (30 to 60 percent is used), and could potentially be used in the future to provide for other thermal needs at the dairy. The engine genset produces about 285 net kW of electricity (parasitic load is 15 kW) which is sold to the power grid. This is enough electricity to serve approximately 180 average homes. The remaining digester effluent is separated into a solid and liquid stream for further processing. The separated solids are currently processed into bedding materials for the dairy or sold to other dairies for bedding. Additional work is underway to develop this material into a compost or soil amendment suitable for sale to commercial nurseries as a replacement to peat moss. The liquid stream from the digester is used as a high-value fertilizer, rich in phosphorous and useable nitrogen.

Financial Structure at a Glance

A number of financial pieces came together to build and operate the Vander Haak digester. Below is a summary table.

Total cost $1.2 million USDA 9006 grant funds $272,000 Vander Haak Dairy, LLC. Private financing $768,000 WSU Center for Sustaining Agriculture & Natural Resources; Climate Friendly Farming Project

$160,000

Did the bank accept the digester system as collateral?

No

Expected payback period ~7 – 9 years

Key partners and contacts for the Vander Haak Digester Project:

Vander Haak Dairy, LLC; Andgar Corporation; Whatcom County Extension/Whatcom Dairy Biogas Team; Port of Bellingham; Whatcom Conservation District; Whatcom County PUD #1; Puget Sound Energy; USDA Rural Development; WSU’s CSANR & Climate Friendly Farming Project (Paul G. Allen Family Foundation)

© 2005 Northwest CHP Application Center. This publication contains material written and produced for public distribution. Permission to copy or disseminate all or part of this material is granted, provided that the copies are not made or distributed for commercial advantage, and that each is referenced by title with credit to the Northwest CHP Application Center. Copying, reprinting or dissemination, electronic or otherwise, for any other use requires prior written permission from the Northwest CHP Application Center.

for information, contact: jessica bridges, cae iom...

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