Loading...
HomeMy WebLinkAboutKotzebue Electric Assoc Wind Power Project Third-Year Operating Exp 2001-2002Crriel Kotzebue Electric Association Wind Power Project Third-Year Operating Experience: 2001-2002 U.S. Department of Energy-EPRI Wind Turbine Verification Program Technical Report mn | wae ee sata DISCLAIMER OF WARRANTIES AND LIMITATION OF LIABILITIES THIS DOCUMENT WAS PREPARED BY THE ORGANIZATION(S) NAMED BELOW AS AN ACCOUNT OF WORK SPONSORED OR COSPONSORED BY THE ELECTRIC POWER RESEARCH INSTITUTE, INC. (EPRI). NEITHER EPRI, ANY MEMBER OF EPRI, ANY COSPONSOR, THE ORGANIZATION(S) BELOW, NOR ANY PERSON ACTING ON BEHALF OF ANY OF THEM: (A) MAKES ANY WARRANTY OR REPRESENTATION WHATSOEVER, EXPRESS OR IMPLIED, (I) WITH RESPECT TO THE USE OF ANY INFORMATION, APPARATUS, METHOD, PROCESS, OR SIMILAR ITEM DISCLOSED IN THIS DOCUMENT, INCLUDING MERCHANTABILITY AND FITNESS FOR A PARTICULAR PURPOSE, OR (Il) THAT SUCH USE DOES NOT INFRINGE ON OR INTERFERE WITH PRIVATELY OWNED RIGHTS, INCLUDING ANY PARTY'S INTELLECTUAL PROPERTY, OR (Ill) THAT THIS DOCUMENT IS SUITABLE TO ANY PARTICULAR USER'S CIRCUMSTANCE; OR (B) ASSUMES RESPONSIBILITY FOR ANY DAMAGES OR OTHER LIABILITY WHATSOEVER (INCLUDING ANY CONSEQUENTIAL DAMAGES, EVEN IF EPRI OR ANY EPRI REPRESENTATIVE HAS BEEN ADVISED OF THE POSSIBILITY OF SUCH DAMAGES) RESULTING FROM YOUR SELECTION OR USE OF THIS DOCUMENT OR ANY INFORMATION, APPARATUS, METHOD, PROCESS, OR SIMILAR ITEM DISCLOSED IN THIS DOCUMENT. ORGANIZATION(S) THAT PREPARED THIS DOCUMENT Global Energy Concepts, LLC ORDERING INFORMATION Requests for copies of this report should be directed to EPRI Orders and Conferences, 1355 Willow Way, Suite 278, Concord, CA 94520, (800) 313-3774, press 2 or internally x5379, (925) 609-9169, (925) 609-1310 (fax). Electric Power Research Institute and EPRI are registered service marks of the Electric Power Research Institute, Inc. EPRI. ELECTRIFY THE WORLD is a service mark of the Electric Power Research Institute, Inc. Copyright © 2002 Electric Power Research Institute, Inc. All rights reserved. CieteI Kotzebue Electric Association Wind Power Project Third-Year Operating Experience: 2001-2002 U.S. Department of Energy-EPRI Wind Turbine Verification Program Technical Report Kotzebue Electric Association Wind Power Project Third-Year Operating Experience: 2001-2002 U.S. Department of Energy-EPRI Wind Turbine Verification Program 1004206 Final Report, December 2002 Cosponsors U.S. Department of Energy 1000 Independence Ave., SW MS Washington, D.C. 20585 Principal Investigator T. Hall National Renewable Energy Laboratory 1617 Cole Blvd., M/S 3811 Golden, Colorado 80401 Principal Investigator B. Smith Kotzebue Electric Association 245 Logoon Street Kotzebue, Alaska 99752 EPRI Project Manager C. McGowin EPRI * 3412 Hillview Avenue, Palo Alto, California 94304 * PO Box 10412, Palo Alto, California 94303 * USA 800.313.3774 * 650.855.2121 * askepri@epri.com * www.epri.com DISCLAIMER OF WARRANTIES AND LIMITATION OF LIABILITIES THIS DOCUMENT WAS PREPARED BY THE ORGANIZATION(S) NAMED BELOW AS AN ACCOUNT OF WORK SPONSORED OR COSPONSORED BY THE ELECTRIC POWER RESEARCH INSTITUTE, INC. (EPRI). NEITHER EPRI, ANY MEMBER OF EPRI, ANY COSPONSOR, THE ORGANIZATION(S) BELOW, NOR ANY PERSON ACTING ON BEHALF OF ANY OF THEM: (A) MAKES ANY WARRANTY OR REPRESENTATION WHATSOEVER, EXPRESS OR IMPLIED, (I) WITH RESPECT TO THE USE OF ANY INFORMATION, APPARATUS, METHOD, PROCESS, OR SIMILAR ITEM DISCLOSED IN THIS DOCUMENT, INCLUDING MERCHANTABILITY AND FITNESS FOR A PARTICULAR PURPOSE, OR (Il) THAT SUCH USE DOES NOT INFRINGE ON OR INTERFERE WITH PRIVATELY OWNED RIGHTS, INCLUDING ANY PARTY'S INTELLECTUAL PROPERTY, OR (lll) THAT THIS DOCUMENT IS SUITABLE TO ANY PARTICULAR USER'S CIRCUMSTANCE; OR (B) ASSUMES RESPONSIBILITY FOR ANY DAMAGES OR OTHER LIABILITY WHATSOEVER (INCLUDING ANY CONSEQUENTIAL DAMAGES, EVEN IF EPRI OR ANY EPRI REPRESENTATIVE HAS BEEN ADVISED OF THE POSSIBILITY OF SUCH DAMAGES) RESULTING FROM YOUR SELECTION OR USE OF THIS DOCUMENT OR ANY INFORMATION, APPARATUS, METHOD, PROCESS, OR SIMILAR ITEM DISCLOSED IN THIS DOCUMENT. ORGANIZATION(S) THAT PREPARED THIS DOCUMENT Global Energy Concepts, LLC ORDERING INFORMATION Requests for copies of this report should be directed to EPRI Orders and Conferences, 1355 Willow Way, Suite 278, Concord, CA 94520, (800) 313-3774, press 2 or internally x5379, (925) 609-9169, (925) 609-1310 (fax). Electric Power Research Institute and EPRI are registered service marks of the Electric Power Research Institute, Inc. EPRI. ELECTRIFY THE WORLD is a service mark of the Electric Power Research Institute, Inc. Copyright © 2002 Electric Power Research Institute, Inc. All rights reserved. CITATIONS This report was prepared by Global Energy Concepts, LLC 5729 Lakeview Drive, Ste. 100 Kirkland, WA 98033 Principal Investigators R. Vilhauer K. Conover This report describes research sponsored by EPRI, the U.S. Department of Energy, National Renewable Energy Laboratory, and Kotzebue Electric Association. The report is a corporate document that should be cited in the literature in the following manner: Kotzebue Electric Association Wind Power Project Third-Year Operating Experience: 2001- 2002: U.S. Department of Energy-EPRI Wind Turbine Verification Program, EPRI, Palo Alto, CA; the U.S. Department of Energy, Washington, DC; National Renewable Energy Laboratory, Golden, CO, and Kotzebue Electric Association, Kotzebue, Alaska: 2002. 1004206. iti REPORT SUMMARY This report describes the third-year operating experience and expansion of the 0.76-MW Kotzebue Electric Association (KEA) wind power project near Kotzebue, Alaska. The lessons learned in the project will be valuable to other utilities planning similar wind power projects. Background In 1992, EPRI and the U.S. Department of Energy (DOE) initiated the Wind Turbine Verification Program (TVP). Program goals are to help electric utility companies gain field experience with wind power, evaluate early commercial wind turbines at several U.S. sites, and transfer the experience to the wind power and utility communities. TVP projects are selected through competitive solicitations. Under the program, there have been eight projects, including four associate projects. The KEA project is an associate project and has received only limited funding and technical assistance to support data collection; the project did not receive TVP funding for the purchase and installation of wind turbines. KEA joined TVP in 1997 as the first associate project. The 0.76-MW wind turbine project is owned and operated by KEA at a site near Kotzebue in northwest Alaska. It consists of ten Atlantic Orient Corporation (AOC) 15/50 wind turbines and one Northern Power Systems North Wind 100 (NW 100) wind turbine. The ten AOC turbines have a 15-m diameter, three-blade rotor, and a constant-speed turbine generator mounted on top of a 24.4-m (80-ft) lattice tower. The first three AOC turbines were installed in 1997, the remaining seven AOC turbines were installed in 1999, and the project was commissioned in June 1999. The NW 100, featured on the report cover, was installed in May 2002, bringing the project capacity to 0.76 MW. The NW 100 is a three-blade, fixed-pitch, stall-regulated design with a rotor diameter of 19.1 m (63 ft). The turbine is mounted on a 23.4-m (77-ft) tubular steel tower. The development and first- and second-year operating experiences of the project are described in these EPRI companion reports: TR-113918 (December 1999), 1000957 (December 2000), and 1004040 (December 2001). Future reports will describe additional years of operating experience and further project expansion. Objectives To document KEA’s project expansion activities and third year of operating experience, to describe the experience gained and problems encountered in the third year of project operation, and to transfer the lessons learned to other utilities planning similar projects. Approach Project investigators documented the third-year operating experience at the KEA project from July 2001 through June 2002. The report describes the project’s annual performance, its operation and maintenance activities, expansion activities and plans, and KEA’s continuing wind research and outreach activities. Results During the 12-month period, July 2001 through June 2002, the Kotzebue wind facility delivered 858,419 kWh of electricity to the Kotzebue distribution system. It operated at a 14.8% average capacity factor based on 660-kW rated capacity. Overall TVP system availability was 94.5%, allowing for all scheduled and forced outages of the wind turbines. Some turbine downtime was due to project expansion and other activities conducted by KEA. Individual turbine availabilities ranged from 82.0% to 98.4%. The third year of operation is characterized by somewhat lower wind speeds and lower turbine availability than the second year. However, the wind speeds and resulting energy were still higher than what the project experienced during the first year of operation. During the third year, the project experienced a 33% increase in downtime from the second year of operation. The majority of the downtime increase can be attributed to the project expansion activities. EPRI Perspective Through 2002, EPRI has issued 23 reports on project development and operation for eight DOE- EPRI TVP wind projects located in Alaska, lowa, Nebraska, Texas, Vermont, Wisconsin, and Tennessee. An important goal of the program is to transfer the experience gained in the TVP projects to utilities, wind power developers and turbine vendors, government agencies, and other interested parties so that the lessons learned can be incorporated into future projects. This report will be useful in this regard because it describes actual operation experiences, which will help others avoid or reduce the impact of many problems encountered. Future EPRI reports will describe the fourth year of operation at Kotzebue and the initial experience of the new NW 100 turbine and additional AOC turbines included in KEA’s project expansion plans, and other TVP- funded projects. Keywords Wind power Wind resource Performance Availability Operations and maintenance vi ABSTRACT The Wind Turbine Verification Program (TVP) is a collaborative effort of the U.S. Department of Energy, the Electric Power Research Institute, and host utilities to develop, construct, and operate wind power plants. Through their involvement as an associate TVP project, Kotzebue Electric Associate (KEA) has developed, constructed, and is now operating a 0.76 MW wind power plant. The project consists of ten commercial 66 kW wind turbines manufactured by Atlantic Orient Corporation (AOC) of Norwich, Vermont, and one 100 kW wind turbine manufactured by Northern Power Systems. The AOC 15/50 wind turbines are installed on 24.4-m (80-ft) lattice towers at a site near the town of Kotzebue in northwest Alaska. The first phase of the project, commissioned in September 1997, consists of three turbines. The remaining seven turbines were commissioned in June 1999 and a dedication ceremony was held on August 14, 1999. The North Wind 100 (NW 100) is installed on a 23.4-m (77-ft) tubular steel tower. The NW 100 was installed and commissioned in May 2002. This report discusses the activities and experience during the third year of operation of the full ten-turbine project as well as the installation of the NW 100 and other project expansion activities at KEA. It includes summaries of the wind resource data, actual and projected energy production, and availability at the site during the third year of operation. The report discusses the operation and maintenance activities and categorizes the downtime experienced by the turbines during the period from July 2001 through June 2002. KEA is currently in the process of installing two additional AOC 15/50 wind turbines and assessing plans for further project expansion. KEA may eventually increase the installed capacity of the project to as much as 2 to 4 MW. Because KEA has installed the NW 100 turbine and is installing additional AOC turbines, continued performance evaluation under the TVP is planned for the future. vii ACKNOWLEDGMENTS A number of individuals provided information and contributed to the production of this report. Valuable input and comments were received from representatives of Kotzebue Electric Association, Atlantic Orient Corporation, the Electric Power Research Institute, the U.S. Department of Energy, and the National Renewable Energy Laboratory. Matt Bergan and Brad Reeve of KEA, Craig Thompson of Thompson Engineering, and Jesse Stowell of Northern Power Systems were particularly helpful in providing details and clarification. Gordon Randall, Mark Young, and Betsie McLain of Global Energy Concepts made significant contributions to the final analysis and format of the document. Other GEC staff members also assisted with various sections of the report. ix LIST OF ABBREVIATIONS AOC DOE EPRI GEC IEC Met NPS NREL O&M PLC SCADA TVP UWIG WECTEC Atlantic Orient Corporation U.S. Department of Energy Electric Power Research Institute Global Energy Concepts International Electrotechnical Commission Kotzebue Electric Association Meteorological Northern Power Systems National Renewable Energy Laboratory Operation and Maintenance Programmable Logic Controller Supervisory Control and Data Acquisition Turbine Verification Program Utility Wind Interest Group Wind Economics and Technology, Inc. xi CONTENTS 1 INTRODUCTION 1.1 Project Background. 1.2 Background on the Wind Turbine Verification Program ..............::ccsceseeseeseeeeeeeeeeeeaeeees 1-3 TES IREPOMU ODJOCtIVES AN! SCOPE eeteccasccrcste taster ter sae tce eerie ect ce cee er 1-4 124 Report: Organization teiscccctactactcccen cases sas tent ce seta acetataatacesctacttoesoetesnbct act ccthst at eetebactaentehaets 1-4 2. WIND RESOURCE CHARACTERISTICS lcctcsecscceccscesccncscassassceseos eessconscecseestensancanccsosccsonssets 2-1 251i Data ‘Collection saiisicscavasdatcutcncuhcancetuatovtcnscnscta chost tutcetdatcevtctacuachtacbeenscnt suacudeidet tescnbertecterts 2:2iWind Speed isteach tsa aabactastdchdat atdesdebcautottesttcnsomseneshsobartactcehattebasits 2S IV ITNT CTION seater etctece neta te tnt acters Set ee st tase aetteat toast fotgoe tense tees ece tense ea 2.4 Turbulence and Shear 3 PROJECT PERFORMANCE 3.1 Availability . SEZIEMOP Gy: TOCUCTION ret sscetatcatcttct cc aetat cnt cassette tobcat atest cae tat dat tcbest tact tonto tot totceecntaeecetcnee aches 3.2.1 Seasonal and Inter-Annual Performance Variations ...............:.::ssesesceeeeeseeeeeeeeeeeee 3-4 3.2.2 Utility Meter Readings and On-Site Energy Losses.............eecceeeeeceeseeesseeeesseeesseees 3-6 32253] PT OJOCTOC SMO GY fara at eset otc ats cic tet saet cuca tat ect deecet Sense tet sec acetone dates verse cata ts 3-7 3.2.4 Lost Energy Due to Downtime.....................--ccsssccssccroscccescresscceserenecencssonceseasonsers 3-10 3.2.5 Percent Time Generating S-aiUtility, Demand iam: Project ENGL Gy soscceeqceveccseetscecccntaccctecne cece eccntes sactatsenectcetsatetectcctees 3-13 3:4/Powen Quality: Considerations scatter tects eset eect ce ein teen entero eeetaes 3-14 4 PROJECT OPERATIONS AND MAINTENANCE ......00.....ccccssssecseeseseseeseeeceseseeesesseeseaeeaseeseas 4-1 AN IIKE AIS OR MS trate yy esecestcc tater seer acta tata ee tae sat cease eee eter Saree 41 4.2 Maintenance Activities and Other Downtime Events............2...::cesesceeeeseeseeseeseeeeeeeeeees 4-1 42:1 ADowntime: Categories sister ta cbt t acetate cca atta shee irtctedetttttait osetia 4-3 4.2.2 Downtime Due To O&M Activities ............. ee eeeeeeeeeeesceeseeeeceseeesseecesseaeeeceeeeeeseneees 4-7 4.2.3 Downtime Due To Faullts.........cccccccccceeeeeeseeeeeeeeeeeeeeeeeeeeeeeeeesseeeeseeseeeeeseeseeeeeegnes 4-12 4.3 SCADA System Experience 4.4 Operating Guidelines... ceesseseessseeeteeeteeeeseeeeeseees 4.5 Potential Performance Improvements and Turbine Testing ...........:::ccccesceceseseeeseeseeees 4-17 4.5.1 Slow-Starting Turbines.............cccccccesecsecseeeeceeeeenseseseeseeeeseeeseseeesseeeneeeeseeeeseeeeneees 4-17 4.5:2 Turbine Pitch Settings... xt ic. extoc. dst tcsestosessesseres recone revsearscasusteveuseeoueses sussssonuseusaneatens 4-18 5 PROJECT EXPANSION ACTIVITIES AND PLANG..........:ssscesscsssssssssssssssenseessesneestensesseneees 5-1 5:1 The: North Wind 100 Turbine: tcstcccecteccestccessestsvecscoresacsecsssnnsvtsseesotseenteonsvascessssesinnesteceavues 5-1 Ws SPURTE Tm aa ected ethene ol ate lata ela 5.3 Two Additional AOC 15/50s 5:4. FUTUTe PFOJ6Ct/EXPANSION eee cree se dscdeniecrsorsssussesnaueresasretessesmesrssed 6 OUTREACH ACTIVITIES AND FUTURE PLANS 6.1 Community Education and Outreach Activities ........... ccc ceceeseeeeeeeeeeeeeeeesseeeseeseeneeeneees 6-1 6.2 Technology Transfer and Information Dissemination ...............:cc:cccceeseeeesseeseeeneeeeseteeeees 6-1 6.3 Wind Project Planning and Development...............:ccceeseeeeesseeeeceseeeeeseeeeeesueeseeeeeeeeneees 6-2 7 CONCLUSIONS ........sccssceesssssssssessseneeseesssesseesseuseseesesseneenseenseeseeseesseseeseeseeseeenaeeuenseeneeenaeenss 7-1 A TVP-RELATED DOCUMENTG.........cccccsscsssessssssssssssssassessseesesseuseuseeseseeateneesseesasenseeseenseesees A-1 I OTT Lonel atta leeteesonebeeletche areal lalate seller orlalaleeraslelelowrlvantisesb-ahel ella eda A-1 NREL/AWEA WindPower Published Papers .............:::cscccesseesseesseeeeeeserseeeeeseeseneeseseeeesesoes A-2 Other TVP RESOUICES) tei ctse rca stacrdcne crastscpuctasnesssrospeseisucvsced suucpesersinsstesiersousassasesstevesenneansaes A-5 B MONTHLY AVAILABILITY AND PRODUCTION BY TURBINE ............:.::sscssscsseseseessessees B-1 CTVP AVAILABILITY DESCRIPTION.........cccscsssssssssssessssessessesssesesseeassaesaeennsenseneensenseesaeeees C-1 DSPECIFIC DOWNTIME CAUSES BY TURBINE............ccscsssssssssssssseseesseseessesseeseeeenenaeeneees D-1 E NW 100 TURBINE DESCRIPTION. .........csccssssssssssssseesssssssessesssessussssneeseessesseeseesecenseenseasenee E-1 xiv LIST OF FIGURES Figure -17Alaskal State) Mapeccncerctesceeceecrestccatectensesnccnsconcesrsureaterstsnsrsaetuascucezassunsarestecesserers 1-2 Figure 1-2 Photograph of the KEA Wind Power Plant ..............::cc:ccsescsesseessceeseeeseeeseseeeesesentenes 1-3 Figure 2-1 Location of the Current KEA Met Tower... Figure 2-2 Monthly Wind Pattern at Kotzebue (26.5 M)..........:ccscsccssesssseessseseeessesseeeseeenseneeenes 2-5 Figure 2-3 Diurnal Wind Pattern at the Kotzebue Wind Project (26.5 M) ..........::::ccscesseeseeeeees 2-6 Figure 2-4 KEA Wind Speed Frequency Distribution — July 2001 to June 2002..............::00 2-7 Figure 2-5 Annual Wind and Energy Rose — July 2000 to June 2001 ............c:ccceecesseeseeeeeereenes 2-9 Figure 3-1 Average Wind Speed, Availability, and Energy Production by Month................:+ 3-5 Figure 3-2 Actual, Calculated, and Long-Term Projected Energy — July 2001 to June DOOD a dreccatesnac ences sens sites sseeereces tease tesa hiesses nnesocestassastssavarenisavsssescosescocssersussessssasasceestscses 3-9 Figure 3-3 Actual and Lost Energy by Month — July 2001 to June 2002..............:ceseeeseeeeeereeee 3-11 Figure 3-4 Actual and Lost Energy by Turbine — July 2001 to June 2002.............:.ccceseeeeeeeeee 3-12 Figure 3-5 Percent Time Generating Power — July 1999 to June 2002 Figure 3-6 Projected and Actual Third-Year Wind Energy Contribution to KEA Energy Demand astiesccssccetecetseccsssevecesecetraccuctssrrseccosessccevursescevsqoesoceesosse soneveas ens soystsnsaessaeaTet seated 3-14 Figure 3-7 Power Factor vs; Output POWOM ie c:-cesecrooscsvenssveccsnererecesscecevecestecessacsecestacesceeseeeses 3-17 Figure 3-8 Total Demand Distortion vs. Output PoWEe? ..............:ccccsceesscesseeceeeeeneeeseeenseseeeeneeees 3-17 Figure 4-1 Monthly Availability and Wind Speed — July 2001 to June 2002............ceceeseeseeeeees 4-2 Figure 4-2 Total Project Downtime by Cause — July 2001 to June 2002............ceccceeeseeeeeeees 4-4 Figure 4-3 Total Lost Energy by Cause — July 2001 to JUNE 2002...........cesceseeseeseeeeeeseseeneenenes 4-5 Figure 4-4 Total Project Downtime by Turbine — July 2001 to June 2002............cecceseeeeseeeeees 4-6 Figure 4-5 Total Project Downtime by Month — July 2001 to June 2002.............ccceeceseeeeeeseeees 4-6 Figure 4-6 Comparison of Project Downtime by Turbine — July 1999 to June 2002................. 4-8 Figure 4-7 O&M Downtime by Cause — July 2001 to JUNE 2002 ..........eeceeseeeseeeeeeseeeseeneeneeeees 4-8 Figure 4-8 Lost Energy Due to O&M by Cause — July 2001 to JUNE 2002.......... ec ceeeeseeeeeeeeee 4-9 Figure 4-9 O&M Downtime by Month — July 2001 to JUNE 2002...........ccceesceeeeeeeeeeseeeeeseeeeeenes 4-9 Figure 4-10 O&M Downtime by Turbine — July 2001 to June 2002............cceeseeeseeseeeseeeeneeenes 4-10 Figure 4-11 Fault Downtime by Cause — July 2000 to JUNE 2001...........eeceeceeeseeseeeeeseeseeeeeee 4-13 Figure 4-12 Fault Frequency and Duration by Month — July 2001 to June 2002..............0:000+ 4-13 Figure 4-13 Breakdown of Fault Downtime by Cause and Turbine — July 2001 to June 2002 wee 414 Figure 5-1 Freezeback Piling Used for Turbine Foundation ..............cccccccceeseeseeeeeteeteeteeneeeenee 5-4 XV Figure 5-2 NW 100 Tower on Ground.. --- 5-6 Figure:5=3 NW -100: Hub OM: Groun G iszecsccecsecaveveescascescscctecurazsascactatennvansevszewsccvoncssenvtresocreuteveres 5-6 Figure 5-4 NW 100 Tower Being Lowered onto Foundation ..............::cccccsseesecssesseeesesseeseeseeee 5-7 Figure 5-5 NW 100 Tower Being Positioned on Foundation Base.. w» 5-7 Figure 5-6 NW 100 Tower in Position on Foundation Base .............c.cccsccscescesseeseesseseeeeeseeeeees 5-8 Figure 5-7 NW 100 Hub Being Raised into PoSition ..............cccceeseeseesseeseeseeeeeeseseeeeessneseneeenes 5-9 Figure 5-8 NW 100 Hub Being Attached to Nacelle............cccceeccceseeeseeseeeseeeseeeeneeeeeeneeeeneeaees 5-10 xvi LIST OF TABLES Table 2-1 Data Recovery Rates for Meteorological Data — July 2001 to June 2002................ 2-3 Table 2-2 Mean Monthly Wind Speeds at Kotzebue (26.5 M)........:ccceeceeesseeeeeeteeeeeeeeeeeeeeeenees 2-5 Table 2-3 KEA Monthly Turbulence Intensity and Wind Shear — July 2001 to June 2002....... 2-10 Table 3-1 Energy and Availability by Turbine — July 2001 to June 2002..............cceeeeeeeeeeeeeeeeee Table 3-2 Energy and Availability by Month — July 2001 to June 2002.............cceeeeeeeeeeeeeee Table 3-3 Meter Readings and Sum of Turbine Readings — July 2001 to June 2002 . ce Table 3-4 Estimated Energy Losses..............cscesssccccssseeesseeecsseeecssseeeeeseeeesessneaeeeeeseessaeesseeenges Table 3-5 Project Characteristics and Long-Term Net Energy Estimates .............0:::::seeeeeeeee Table 3-6 Actual and Projected Long-Term Energy — July 2001 to June 2002 .. wes Table 3-7 Downtime and Lost Energy by Month — July 2001 to June 2002 .............::cccceeeeees Table 3-8 Actual and Projected Average Wind Energy Penetration on KEA System............... Table 4-1 Downtime Hours by Category — July 1999 to June 2002 ..0..... ee ceeeeceeeseeeeeereeeeeee Table 4-2 O&M Downtime Hours by Category — July 1999 to June 2002 ...........eeceeeeeeeeeee Table 4-3 Fault Downtime by Category — July 1999 to June 2002.2... eeceeeseeeeeseeeneeeeeeeeeee Table 4-4 Recovery Rates for SCADA System Data — July 2000 to June 2001............. Table'5-1- NW-100) Maintenance: Check dist miccccccscacecececccsececnsesstearestsccsssccvsssevoreresccsetoancssseezstesso XVii 7 INTRODUCTION This report is the fourth in a series of reports documenting the experiences of Kotzebue Electric Association (KEA) in developing, constructing and operating a wind power plant near Kotzebue, Alaska. The project was recently expanded from 0.66 MW to 0.76 MW and additional expansion is planned for the near term. The project is part of the Wind Turbine Verification Program (TVP), a collaborative effort of the U.S. Department of Energy (DOE), the Electric Power Research Institute (EPRI), and host utilities to gain experience with utility operation of new wind turbine technology. Additional information on the KEA TVP project is contained in three previous EPRI reports, TR-113918, 1000957, and 1004040. The first report was published in 1999 and documents the development of the entire ten-turbine project as well as the initial operation of the Phase 1 turbines. The second and third reports, published in 2000 and 2001, document the first and second years of project operating experience. Extensive background information, redundant to the previous reports, is not repeated in this report unless appropriate or necessary for comparison purposes. 1.1 Project Background The KEA TVP wind power plant is a facility of small, commercial-scale wind turbines, recently expanded from 0.66 MW to 0.76 MW. The project consists of ten AOC 15/50 66 kW wind turbines manufactured by Atlantic Orient Corporation (AOC) of Norwich, Vermont, and one NW 100 wind turbine rated at 100 kW and manufactured by Northern Power Systems of Waitsfield, Vermont. The AOC turbines are installed on 24.4-m (80-ft) lattice towers on piling foundations, resulting in a hub height of approximately 26.5 m (87 ft). The AOC 15/50 is a three- blade, downwind turbine with a 15-m (49-ft) rotor diameter. The NW 100 is installed on a 23.4- m (77 ft) tower and is also mounted on a pile foundation. The resulting hub height is approximately 26.5 m (87-ft). Two additional AOC 15/50s are currently being installed and are expected to be operational by the end of 2002 or in early 2003. KEA’s project site is located on the tip of the Baldwin Peninsula approximately 42 km (26 mi) north of the Arctic Circle on the northwest coast of Alaska near the town of Kotzebue. With a population of approximately 3,000 residents, Kotzebue is the largest community in Northwest Alaska and serves as the economic, governmental, medical, communication, and transportation hub for the 11 communities in the Northwest Arctic Borough, an area roughly the size of Indiana. Kotzebue can be accessed only by air or water. Daily jet service is available from Anchorage, and small aircraft carry passengers and supplies from Kotzebue to the surrounding villages. Figure 1-1 shows the location of Kotzebue on the Alaska state map. 1-1 Introduction Bering Sea oO. ik ¥ Cc Ce ae Pacific Ocean Woe ee 7 Figure 1-1 Alaska State Map The climate in Kotzebue is characterized by long cold winters and short cool summers. The Kotzebue Sound and area rivers begin to freeze in early October, and spring breakup generally occurs in late May or early June. The 148-acre KEA wind project site is located approximately 7.2 km (4.5 mi) south of the town of Kotzebue. The land is owned by the Kikiktagruk Inupiat Corporation and leased to KEA for an initial period of ten years with an extension option of four additional ten-year periods. The wind project is situated on a relatively flat plain of treeless tundra that is well exposed to both the prevailing easterly winter winds and the prevailing westerly summer winds. Figure 1-2 is a photograph of the wind power project site. The ten-turbine project was installed in multiple phases at a single site over a period of approximately two years. The phases are defined by their funding sources. Phase 1 consists of the first three turbines, installed in July 1997 and commissioned in September 1997. All seven of the Phase 2 and 3 turbines were installed in the spring of 1999 and commissioned in June 1999. Two additional AOC turbines were ordered in late 2000 and specified as Turbines 11 and 12. Although the turbine nacelles were delivered to Kotzebue in November 2001, turbine towers, blades, and controllers were not available until the fall of 2002. Initially, the NW 100 was expected to be installed after the two AOCs and was designated as Turbine 14. The NW 100 installation was completed in May 2002. The installation of two additional AOC 15/5S0s is close to completion and will give KEA an installed wind capacity of 0.892 MW. This report covers the experience during the ten-turbine project’s third year of operation, July 2001 through June 2002, as well as the installation and commissioning of the NW 100 turbine. Introduction (photo courtesy of Brad Reeve, KEA) Figure 1-2 Photograph of the KEA Wind Power Plant 1.2 Background on the Wind Turbine Verification Program The objective of the TVP is to provide a bridge between the wind turbine development programs currently underway in the United States and utility purchases and evaluation of commercial, utility-grade wind turbines. The TVP is intended to assist utilities in learning about wind power through first-hand experience and to build, test, and operate enough new wind turbines to gain statistically significant performance data. A further objective of the TVP is to provide other utilities with information about wind technology and the operation of a wind power plant from the perspective of a utility owner and operator. EPRI manages the TVP program on behalf of the funding organizations and publishes periodic reports to document the experience of each TVP project. Appendix A lists the TVP reports published through the end of 2002. EPRI and DOE, through its National Renewable Energy Laboratory (NREL), also provide valuable technical and management assistance to the host utilities. The TVP was implemented in several phases. In 1994, Central and South West Services (CSW) and Green Mountain Power Corporation (GMP) were chosen by competitive solicitation to host the first two TVP projects. EPRI and DOE awarded contracts to cover a portion of the costs associated with the selected projects based on a number of criteria that demonstrated their ability to help commercialize state-of-the-art wind technology. The projects also were required to be a minimum of 6 MW and use turbines with a substantial U.S. manufacturing content. Introduction In 1996, TVP released a solicitation that focused on distributed wind generation projects. The selection criteria required that each project be connected directly to a distribution line, consist of at least two wind turbines, and be less than 5 MW in nameplate rating. The selected projects are each owned by a consortium of utilities. One project is located in Iowa and the other in Nebraska. In addition to the projects described above, four utility wind projects were incorporated into the TVP as “associate projects.” These projects receive limited funding from the program but benefit from the information exchange and technical assistance. In return, the program sponsors receive performance data and other valuable information. In addition to the KEA project, other associate TVP projects include the Low Wind Speed Turbine Project in Wisconsin and the Big Spring Wind Power Plant in Texas. In 2001, the eighth TVP project and fourth associate project, was selected through a TVP solicitation. It is the 2.0 MW wind project installed by the Tennessee Valley Authority on Buffalo Mountain in northeastern Tennessee. 1.3 Report Objectives and Scope This report focuses on the third year of operation of KEA’s ten AOC 15/50 wind turbines and project expansion activities. The report discusses the project’s performance, operation and maintenance activities, and the installation and commissioning of the NW 100 wind turbine, as well as KEA’s outreach activities and future plans. Additional KEA project reports are planned to describe the continuing performance and expansion of the project. The principal objective of this report is to summarize the KEA TVP project experience, including performance characteristics, wind resource data, operating strategy, maintenance activities, project expansion, research projects, and other significant events that occurred during the reporting period. 1.4 Report Organization The report consists of seven sections. Following the introduction, Section 2 describes the wind resource characteristics at the site. Section 3 discusses the project performance in terms of energy output and availability. Section 4 provides additional details on the operation and maintenance activities. Section 5 discusses the installation and commissioning of the NW 100. wind turbine and other project expansion activities. Section 6 is an overview of KEA’s outreach activities and future plans. Section 7 summarizes the conclusions and experience gained during the project’s third year of operation. 1-4 2 WIND RESOURCE CHARACTERISTICS KEA has collected wind resource data for ten years from numerous locations in the Kotzebue area. The purpose of the initial installation of monitoring equipment was to establish the general wind characteristics of the area. More sophisticated monitoring equipment was installed as KEA progressed towards the development of its wind project. The wind resource data are currently being collected from a hub-height meteorological (met) tower through the Supervisory Control and Data Acquisition (SCADA) system installed in 1999. The following summarizes KEA’s wind monitoring program and the on-site wind resource during the reporting period from July 2001 through June 2002. 2.1 Data Collection In 1992, KEA purchased monitoring equipment from NRG Systems of Vermont and installed it on a roof-mounted tower on a transmitter building for an existing communication tower near the project site. Data collection continued at this site through 1996. In the summer of 1995, KEA installed a 33-m (110-ft) met tower on site and began data collection in August 1995 at heights of 19.5 m (65 ft) and 33 m (110 ft). This data collection effort suffered from marginal data recovery during its first few years. When the first three turbines were installed in 1997, construction activities further impacted the data. In addition, the completed turbine configuration created a wake impact which had an effect on the met data for winds from certain direction sectors. In August 1998, the met tower was relocated to a site approximately one rotor diameter east of the first row of turbines. East is the prevailing wind direction at the site, and enabled the met tower to be used for performance evaluation. Additional sensors were added to the tower and data were collected at 10 m, 20 m, and 30 m (33, 66, and 98 ft). However, when the next seven AOC turbines were installed east of the first three turbines, they created wake impacts and the met tower data were no longer representative of the wind conditions at the site. In the summer of 1999, a second met tower was installed east of the ten-turbine project layout. This met tower is approximately two rotor diameters east of Turbine 8 and serves as the primary source of wind resource data for this report. Figure 2-1 shows the location of the met tower relative to the turbines and the surrounding terrain. Sensors are installed at 10 m, 19 m, and 26.5 m (33, 62, and 87 ft). The met data are recorded by the Second Wind SCADA system which was commissioned in late August 1999. Data from this met tower were also used to conduct power performance tests on Turbine 8 during the ten-turbine project’s first year of operation. The KOTZ tower shown in Figure 2-1 is an existing communications tower used by the local radio station. Wind Resource Characteristics Nu 4 Met Tower 2000 3000 4000 5000 FEET i GSI ARERR 800 1000 METERS Figure 2-1 Location of the Current KEA Met Tower Wind Resource Characteristics Wind data are also available from the Kotzebue Airport, which is located approximately 6.4 km (4 mi) northwest of the project site and serves as a long-term reference for the wind resource in the area. In 1999, KEA hired a consultant, Wind Economics & Technology, Inc. (WECTEC), to summarize the wind resource data collected in Kotzebue and to make long-term energy estimates for the site. WECTEC evaluated concurrent data from the original site met tower and the airport to compare the sites. WECTEC then developed a long-term estimated wind speed for the project site based on hourly data from the airport. The airport data, the long-term wind resource estimate, and related energy estimates are discussed in more detail in previous EPRI reports for the KEA wind project. A complete met data set, based on the Second Wind SCADA data, was compiled for the project site for the reporting period, July 2001 through June 2002. Table 2-1 presents the data recovery rates for the on-site wind speed anemometers at all sensor heights. The SCADA system collects and records wind speed, wind direction, temperature and pressure data every 10 minutes. During the third year of operation, the annual wind speed data recovery rate for the 26.5-m sensor was approximately 96% compared to 94% during the previous year. Table 2-1 Data Recovery Rates for Meteorological Data — July 2001 to June 2002 Month 10m 19m 26.5 m July 94.4% 94.3% 92.3% August 69.6% 69.6% 67.7% September 100.0% 100.0% 100.0% October 96.9% 96.8% 95.8% November 99.1% 99.1% 99.1% December 100.0% 100.0% 100.0% January 100.0% 100.0% 100.0% February 100.0% 100.0% 100.0% March 100.0% 100.0% 100.0% April 99.8% 99.8% 99.8% May 99.3% 99.3% 99.0% June 97.9% 97.9% 96.9% Annual Average 96.4% 96.4% 95.9% Data recovery was lower than usual during August due to project expansion activities that resulted in communication loss. High voltage lines were added for the new turbines and site roads were extended. During this activity, heavy equipment crushed a section of communications cable. A period of troubleshooting was required to find the location of the damaged cable and make necessary repairs. 2-3 Wind Resource Characteristics For the third year of operation, GEC replaced missing wind speed data for the 26.5-m sensor according to the following methods. When wind speed data at the 26.5-m height were missing and accurate data were available at a lower sensor height, data from the lower sensor were adjusted to represent the 26.5-m wind speed based on the relationships between the lower and upper sensors that were determined during periods of concurrent valid data. For short periods of missing data lasting up to three hours, an average of the 26.5-m wind speeds before and after the missing data was used. For limited time periods when accurate data were not available from any of the sensor heights, data were reconstructed for the 26.5-m wind speed based on a correlation between the on-site sensors and the daily average wind speed recorded at the Kotzebue Airport. For months when data were replaced using this method, GEC obtained correlation coefficient values ranging .88 to .93. A correlation factor of 1.0 indicates perfect correlation. Thus, these high correlation coefficients suggest a strong relationship between airport and site wind speeds and increase the confidence of adjusting Kotzebue Airport data to replace the site data. The following sections present an overview of the wind characteristics at the site during the third year of operation and include comparisons to the first and second year data and the estimated long-term wind resource. Additional information on performance trends and energy output is included in a later section of the report. 2.2 Wind Speed Table 2-2 compares the monthly and annual 26.5-m wind speeds for the first three years of operation, July 1999 through June 2002, to the estimated long-term site wind speed at 26.5 m. The average annual wind speed at the site during the third year of operation was 5.8 m/s (12.9 mph), approximately 6% lower than the estimated long-term average. The annual wind speed during the first year was approximately 16% lower than the long-term estimated average wind speed of 6.1 m/s (13.6 mph), and was approximately 7% higher during the second year. Figure 2-2 provides a graphical comparison of the wind resource at the site during the year prior to the full ten-turbine installation, the project’s first and second operating years, and the long- term estimated wind resource. This graph illustrates the inter-annual and seasonal variation in wind speed at the KEA wind site. Table 2-2 Mean Monthly Wind Speeds at Kotzebue (26.5 m) Wind Resource Characteristics 7/01-6/02 7/00-6/01 7/99-6/00 Long-term Month m/s | (mph) m/s (mph) | m/s | (mph) | mis (mph) July 5.1 (11.4) 5.1 (11.4) 55 | (124) | 58 (12.9) August 56 | (126) | 64 (14.2) 5.3 | (118) | 65 | (14.4) [September 5.5 (12.3) 6.4 (14.3) 5.1 | (11.4) 6.4 (14.2) October 5.2 (11.7) 5.2 (11.7) 48 | (10.7) 66 (14.7) November 43 (9.6) | 7.8 | (17.6) 45 | (10.1) | 7.1 (15.9) December | 46 | (10.3) 8.7 (19.5) 4.2 (9.3) 6.2 (13.9) January 6.5 (14.5) | 7.0 (15.6) | 53 | (118) | 63 | (14.1) | February 51 (11.5) 95 (21.2) 7.2 (16.1) 6.7 (14.9) March 9.0 20.2) 6.5 (14.5) 6.5 (14.5) 5.5 (12.3) ‘April | 62 | (13.8) | 66 | (14.8) 49 | (11.0) | 53 | (11.9) | May 65 | (14.6) 47 | (104) | 44 | (9.9) 5.3 (11.8) June 5.6 (12.6) 4.3 (9.7) 3.7 | (8.2) 6.0 (13.3) Annual Average | 5.8 (12.9) 6.5 (14.6) 5.1 (11.4) 6.1 (13.6) Wind Speed (m/s) = oO OAPF NWA AHADANOO Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun T r T 7/01-6/02 —e— 7/00-6/01 —e#—7/99-6/00 - - - - Long-term | Lu Figure 2-2 Monthly Wind Pattern at Kotzebue (26.5 m) As the figure indicates, the site experienced lower-than-average wind speeds during most months of the year. However, the wind speeds during March through May were higher than the long- term averages. As shown in Table 2-2 and Figure 2-2, with the exception of a few months, the seasonal pattern during the third year of operation was quite similar to the pattern during the first year. The long-term estimated monthly wind speed pattern predicts significantly less monthly variation than occurred between July 1999 and June 2002. Figure 2-3 compares the diurnal wind resource pattern during the project’s third year of operation to the long-term pattern at the project site. The wind speeds were lower during this 2-5 Wind Resource Characteristics reporting period than the estimated long-term wind speeds, but their diurnal patterns are fairly similar. However, during the third year, the annual diurnal pattern exhibited a slight peak in the evening, whereas the long-term estimated pattern exhibits a somewhat more pronounced peak earlier in the day. In general, the KEA site does not exhibit a significant variation in diurnal wind speed compared to other sites. | | | | | | | | | Wind Speed (m/s) o 5 {— oe 7 SSSSnenmrnnnaesstheresnsnanesnssmsseesesserseasr anaes ——— 4 | 123 45 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Hour of the Day ans — 7/01-6/02 - Sede Long-term Figure 2-3 Diurnal Wind Pattern at the Kotzebue Wind Project (26.5 m) Figure 2-4 presents the wind speed frequency distribution at Kotzebue for July 2001 through June 2002 in tabular and graphical form. The plot shows the measured wind speed frequency distribution together with the Rayleigh distribution, which is often used to provide a simple estimate of the wind speed distribution. Using the Rayleigh distribution and the average wind speed to predict the energy generation for the third year of operation usually provides a fairly accurate prediction of energy generation. (It over-predicts the actual distribution by only 3%.) While the actual and Rayleigh frequency distributions appear dissimilar for wind speeds below 6 m/s (13.4 mph), the Rayleigh distribution more successfully approximates the third-year wind speed frequency distribution for most of the operable wind speeds. The degree to which the Rayleigh distribution represents the actual wind speed frequency distribution varies by site and year. The Rayleigh distribution under-predicted the actual energy generation by approximately 9% for the first year of the KEA wind power project and over-predicted the energy by 2% during the second year. Wind Resource Characteristics 2 s 2 3 c < 0 2 4 6 8 10 12 14 #16 #18 #20 22 Wind Speed (m/s) Measured - - - - Rayleigh Bin m/s Measured Hours Bin m/s Measured Hours 0.0 394 11.5 88 0.5 257 12.0 85 1.0 98 12.5 79 1.5 103 13.0 61 2.0 126 13.5 54 2.5 235 14.0 47 3.0 490 14.5 34 3.5 593 15.0 32 4.0 654 15.5 27 4.5 661 16.0 22 5.0 658 16.5 16 5:5 732 17.0 17 6.0 523 17.5 1 6.5 495 18.0 1 7.0 395 18.5 6 75 349 19.0 6 8.0 305 19.5 4 8.5 260 20.0 5 9.0 242 20.5 3 9.5 188 21.0 1 10.0 158 21.5 1 10.5 124 22.0 0 11.0 110 Total 8760 Figure 2-4 KEA Wind Speed Frequency Distribution — July 2001 to June 2002 2-7 Wind Resource Characteristics 2.3 Wind Direction The KEA site achieved a directional data recovery rate of 96.4% for July 2001 through June 2002 from the Second Wind SCADA system. Figure 2-5 shows the annual wind rose at KEA for the third year of operation, based on the hours of occurrence and the energy available in each direction sector. Prevailing winds were from the east, a trend that is consistent with previous wind data at the project site. As shown in the wind rose, a direction sector width of approximately +23° from due east encompasses the majority of the energy-producing winds, also consistent with previous years at the site. Westerly winds during the third year were negligible, whereas in previous annual wind roses, a westerly component was more apparent. 2.4 Turbulence and Shear Table 2-3 summarizes the monthly turbulence intensity and wind shear during the reporting period. Turbulence intensity is a relative indicator of the turbulence characteristics of the wind. At the KEA site, the average turbulence intensity at hub height for the third year of operation was 0.10 at wind speeds above 4.0 m/s (8.9 mph). Throughout the three years of operation, the turbulence intensity has remained at 0.09 to 0.10. This turbulence intensity level is considered to be fairly low and unlikely to contribute to any operational problems. The wind shear factor () between 10 and 26.5 m was estimated to be 0.20 and 0.19 during the first and second year of operation, respectively. During the third year of operation, the calculated shear increased to 0.27. The shear was calculated based on the power law formula’ using wind speed data above 4.0 m/s (8.9 mph) from all directions. The highest monthly wind shear values were 0.38 for November and 0.37 for December. November and December were also the lowest wind-speed months during the year. Therefore, while these high monthly shear values affect the annual average of the shear calculation, they are not particularly reflective of the shear experienced during the higher energy-producing winds. Excluding the November and December data, the average wind shear was still relatively high at approximately 0.25. ' (H/H,)°=(v,/v,) where H, and H, are measurement heights and v, and v, are wind speeds. 2-8 Wind Resource Characteristics 40 30 Ss ©— Percent of Total Energy Percent of Total Time Figure 2-5 Annual Wind and Energy Rose — July 2000 to June 2001 2-9 Wind Resource Characteristics cat Turbulence Intensity and Wind Shear — July 2001 to June 2002 Month Turbulence 10-26.5 m [ Intensity Wind Shear July 0.12 0.20 ot August 0.11 0.21 September 0.11 0.27 October 0.11 0.32 November 0.11 0.38 December 0.10 ni 0.37 January 0.10 0.28 il February 0.09 0.30 March 0.08 | 0.28 April 0.08 0.25 May 0.09 0.19 June 0.11 0.19 ee 0x0 om Seu 0.10 0.19 pablo ll 0.09 0.20 2-10 3 PROJECT PERFORMANCE This section addresses the availability and energy production from the KEA TVP project during the third year of operation from July 2001 through June 2002.’ The NW 100 turbine was installed in May 2002 and is therefore not included in this performance analysis. The initial operating experience of the NW 100 is discussed in Section 5. The total energy produced by the 10 AOC turbines during this period was approximately 858.4 MWh. The average TVP system availability, which takes into account all downtime, was 94.5% during the third year. The energy output was lower than the long-term projected energy primarily due to lower-than-normal wind speeds. The monthly data presented in this section are based on the TVP reporting periods, which begin at midday on the 20" of the previous month and continue until midday on the 20" of the current month. For example, the month of August includes data from July 20 to August 20. The TVP reporting periods were adjusted to coincide with KEA’s internal reporting periods. These reporting periods were also used for analysis and reporting of the first- and second-year operating experience. 3.1 Availability Table 3-1 summarizes the energy production and availability for each turbine during the third year of operation. Table 3-2 shows the project totals by month and both tables compare the results to the first and second year of operation of the ten AOC turbines. The average capacity factor for the third year of operation based on 0.66 MW of installed capacity was 14.8%. This decrease in capacity factor from the previous year’s 20.8% is primarily due to lower wind speeds. The TVP availability for the reporting period was 94.5% based on the recovered data. Turbines 8 and 10 exhibited the highest turbine availability at 98.4%, and Turbine 3 exhibited the lowest single turbine availability at 82.0%. The lowest project availability (85.6%) occurred during July 2001 and the highest availability (99.5%) occurred during the September 2001 reporting period. Appendix B presents the monthly availability by turbine. Specific reasons for turbine downtime are discussed in Section 4. There are a number of different ways to define and track availability for individual wind turbines and wind power plants. To ensure consistency in data reporting for all projects involved in the ° The first three AOC turbines, Phase 1, were installed in 1997. The remaining seven turbines, Phases 2 and 3, were installed concurrently and commissioned in June 1999. This report focuses on the project performance for July 2001 through June 2002, the third year of operation for the ten-turbine project. For comparison purposes, some references are made to the project’s first and second years of operation, the periods from July 1999 to June 2000 and July 2000 to June 2001. The performance of the NW 100 and additional AOC turbines will be reported in future EPRI reports. 3-1 Project Performance program, the TVP has developed a definition of availability to be used for reporting performance statistics. The TVP definition of availability accounts for all downtime experienced by the individual wind turbines in a project and divides the available hours by the total hours in the reporting period. For example, if during a 100-hour period, a turbine is shut down for 5 hours for a site tour, 5 hours for repairs, and 5 hours due to a line outage, the TVP downtime would be 15 hours and the TVP availability would be (100% - (15/100) x 100%) or 85% for that turbine. Appendix C presents the TVP availability definition. The TVP availability values presented in Tables 3-1 and 3-2 take into account downtime hours associated with a number of different events at the Kotzebue project including construction activities conducted by KEA; delays in responding to faults (the site is largely unattended); turbine reliability problems; scheduled maintenance and routine inspections; troubleshooting; delays in obtaining parts; and project-wide shutdowns in response to utility line outages, equipment upgrades, and safety concerns. Table 3-1 Energy and Availability by Turbine — July 2001 to June 2002 Wind Energy Capacity TVP Turbine (kWh) Factor [1] | Availability 1 91,436 15.8% 97.0% 2 85,161 14.7% 96.2% 3 60,648 10.5% 82.0% 4 90,918 15.7% 96.9% 5 82,897 14.3% 93.4% 6 93,837 16.2% 96.6% v 78,541 13.6% 88.0% 8 84,594 14.6% 98.4% 9 90,678 15.7% 98.1% 10 99,708 17.2% 98.4% | sel orienta 958,419 | 14.8% 94.5% Peco pled 1,200,514 20.8% 95.9% elvan ee a 733,071 12.6% 96.8% 1] Based on the TVP-rated turbine capacity of 66 kW. Project Performance Table 3-2 Energy and Availability by Month - July 2001 to June 2002 Annual . Month Tan en ] pedis July 2000 34,387 7.2% 85.6% August 51,558 10.5% 86.8% September 57,203 11.6% 99.5% October 45,342 9.5% 97.8% November 16,406 3.3% 98.6% December 58,897 12.4% 99.4% January 2001 97,671 19.9% 98.9% February 69,092 14.1% 90.0% March 172,953 39.0% 89.0% April 88,377 18.0% 95.8% May 102,167 21.5% 97.0% June 64,366 13.1% 95.7% Total Project — 3" Year (7/01-6/02) 858,419 14.8% 94.5% Total Project — 2nd Year (7/00-6/01) 1,200,514 20.8% 95.9% Total Project — 1st Year (7/99-6/00) 733,071 12.6% 96.8% 1] Based on the TVP-rated turbine capacity of 66 kW. Commercial wind projects generally expect an annual turbine availability of 97% to 98%. However, due to the remote location and harsh environment of the KEA wind project, a 95% expected availability is considered more reasonable and is the basis of the long-term energy estimates discussed later in this section. As shown in Tables 3-1 and 3-2, the project achieved 96.8% TVP availability during the first year and 95.9% during the second year of operation. During the third year of operation, the project availability decreased slightly to 94.5%. KEA’s relatively high availability during its three years of operation can be attributed to the reliability of the AOC turbines and the responsiveness of the KEA site personnel in resetting faults and addressing maintenance issues. 3.2 Energy Production Tables 3-1 and 3-2 also summarize the energy production for the third year of operation. As the tables indicate, the KEA project produced 858.4 MWh of energy during the third year of 3-3 Project Performance operation, significantly less than the previous year’s production of 1,200.5 MWh but more than the first year production of 733.1 MWh. The significant differences in project output are largely due to the annual variation in wind speeds. Turbine 10 produced more energy than any of the other turbines during the third year of operation, achieving a capacity factor of 17.2%. Turbines 9 and 10 achieved the highest annual average production over the three years of operation with capacity factors of 17.5% and 18.1%, respectively. These turbines experience the best exposure to the prevailing winds. As Table 3-1 illustrates, Turbine 3 generated the least power during the third year of operation, at 60.6 MWh, caused in part to its low turbine availability for the reporting period. Turbine 3 also continued to experience tip brake deployment problems that frequently resulted in lower-than- normal energy production when the turbine did operate. During the third year, Turbine 3 experienced an unusually long downtime event during February and March when the turbine was shut down more than half the time. Site personnel were not available to perform troubleshooting for several weeks and ultimately the turbine began operating without any specific repairs. Turbines 7 and 5 were the next lowest producers. This result is partially due to their location, which is impacted by the wake effects of neighboring turbines. The turbines also experienced higher-than-average downtime with availability of 88.0% and 93.5%, respectively. Appendix B presents the monthly energy production by turbine. Following is a discussion of issues related to the energy production at KEA, including seasonal and inter-annual performance variations, energy losses, projected energy, lost energy, and energy penetration. 3.2.1 Seasonal and Inter-Annual Performance Variations Figure 3-1 shows the monthly variation in wind speed, availability, and energy production at the KEA project during the three years of operation. The seasonal energy pattern is impacted by both the wind resource and the availability of the turbines. During the third operating year, the highest energy production occurred during March, when the project produced over 173.0 MWh, or 6.2 MWh per day, yielding a 39.0% capacity factor. Although May was the second highest energy-producing month during the third year, the production was significantly lower at approximately 3.4 MWh per day and 21.5% capacity factor. While the high energy-producing months correspond to the months with the highest wind speeds, the average wind speed during March was 9.0 m/s compared to 6.5 m/s during May. The lowest energy-producing month during the third year was November, with an average of 0.5 MWh per day and a 3.3% capacity factor. During November, the average monthly wind speed was 4.3 m/s (9.6 mph), the lowest month during the third year. During the first and second years of operation, June was the lowest wind speed month. Figure 3-1 accentuates the differences in wind speed and energy production between the project’s three years of operation. The project experienced abnormally low wind speeds during its first year of operation, and considerably fewer winter storms than usual. The second year had higher-than-normal wind speeds resulting in higher-than-expected energy production. While the third year experienced wind speeds higher than the first year, the winds were still somewhat 3-4 Project Performance lower than the expected long-term average. Winter blizzards typically supply a significant portion of annual high winds and greatly impact the overall energy production for the year. Figure 3-1 Wind Speed (m/s) Jul 7/99-6/00 —= == 7/00-6/01 Feb Mar Apr May 7/01-6/02 Jun > 2 3S s 3 $ | =< 40% | ———— —_ el a i F 20% | — - — — 0% ! Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun - + - + 799-600 — — 7/00-6/01 — 7101-6102 250 1 § 200 }- : — | = | > 150 | — — [] — | = 7] | o : 1] & 100 -——_______ |} }{ | — ——| 7 | s | dhl Malad ai | Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun 10 7/99-6/00 m 7/00/6/01 1 7/01-6/02 | Average Wind Speed, Availability, and Energy Production by Month Project Performance 3.2.2 Utility Meter Readings and On-Site Energy Losses Table 3-3 compares the sum of the energy generation reported for each turbine and the energy delivered to the grid as indicated by the KEA primary meter at the project interconnection point. The difference between the meter and the sum of the turbines represents the energy losses in the on-site electrical collection equipment, the energy consumption by the facility, and the differences in measurement. As the KEA meter is located at the project site, it does not account for the distribution line losses between the project and the utility load. In general the highest losses are expected to occur during the coldest months due to increased power consumption by the on-site facility and the energy used to operate the turbine transmission heaters. The coldest months typically are December, January and February. During the third year of operation, the highest losses occurred during March and April and are likely due to the project expansion activities during this time. Table 3-3 Meter Readings and Sum of Turbine Readings — July 2001 to June 2002 Mont roe Sit | Taming, | een) Per Meters (kWh) July 32,609 34,387 1,778 5.5% August 49,861 51,558 1,697 3.4% September 56,064 57,203 1,139 2.0% October 44,709 45,342 633 1.4% November 15,404 16,406 1,002 6.5% December 57,288 58,897 1,610 2.8% January 93,654 97,671 4,017 4.3% February 66,390 69,092 2,702 4.1% March 166,370 172,953 6,583 4.0% April 83,486 88,377 4,891 5.9% May 98,350 102,167 3,817 3.9% June 61,900 64,366 2,466 4.0% 3rd Year — 7/01-6/02 826,085 858,419 32,333 3.9% 2nd Year - 7/00-6/01 1,162,631 1,200,514 37,883 3.2% 1st Year - 7/99-6/00 718,344 733,071 14,727 2.1% The average energy loss during the reporting period was 3.9%, somewhat higher than the first- and second-year losses. However, the actual energy loss during the third year was lower than the second-year loss. The monthly variation between the meters may be due to the use of multipliers, the use of different time stamps, the variation in on-site energy use, and data processing or analysis errors. 3-6 Project Performance 3.2.3 Projected Energy Energy projections for the site were calculated in the report, Wind Resource and Theoretical Energy Estimates for Kotzebue, Alaska and the Northwest Coast, prepared by WECTEC, March 1999. WECTEC developed an estimated long-term data set that represents the wind resource at the Kotzebue project site. This data set reflects a thorough review of all available data for the site as well as the long-term records from the Kotzebue Airport. As discussed in Section 2.1, the WECTEC analysis indicates a strong correlation between the airport and the project site consistent with the flat terrain and proximity of the airport to the project site. A strong correlation between the long-term reference station and the project site increases the confidence in the estimated long-term wind resource at the project site. Based on the annual distribution of winds at the KEA site and the AOC 15/50 published power curve, WECTEC estimated a gross annual energy of 131,400 kWh per turbine. Expected energy losses summarized in Table 3-4 are based on site conditions and industry experience. Table 3-4 Estimated Energy Losses Estimated Cumulative Loss Factors Loss Losses Availability 5.0% 5.0% Transformer/Line Losses 1.0% 6.0% Control System 1.0% 6.9% Blade Soiling 1.0% 7.8% Wake/Off-axis 2.0% 9.7% Total Cumulative Losses 9.7% Despite the cold temperatures, Kotzebue has a very dry climate and rarely experiences the rime icing problems that occur in Vermont and other milder winter climates. The nearby radio tower has been in operation for over ten years and has not experienced any icing problems. As a result, no energy losses were considered for icing. Based on the expected losses in Table 3-4, the net annual energy is estimated to be approximately 118,700 kWh per turbine. This represents a capacity factor of 20.5% based on a rated turbine capacity of 66 kW. Table 3-5 summarizes the energy estimates. Project Performance Table 3-5 Project Characteristics and Long-Term Net Energy Estimates Annual Energy Estimate Gross Energy per Turbine 131.4 MWh Number of Turbines 10 Gross Project Energy 1,314 MWh Estimated Energy Losses 9.7% Net Project Energy 1,187 MWh Capacity Factor * 20.5% * Capacity factor is based on 66 kW rating of the turbines. Table 3-6 compares the actual and calculated energy for the third year to the projected long-term monthly energy. Figure 3-2 further illustrates the relationship between the various energy measures. During its third operating year, the project produced approximately 28% less energy than the long-term energy estimate. The actual energy generated was 87% of the calculated energy for the third year.’ This 13% shortfall is attributed in part to turbine anomalies, such as instances when turbines were technically available but not actually producing power or producing power at lower-than-warranted levels. For example, if a brake tip is erroneously deployed, the turbine may continue to be available but will require higher winds to operate and will have significantly lower energy output. The calculated energy estimate assumes that if the turbine is available, it is producing power at the warranted rate for the measured wind speed. * Calculated energy is based on the actual wind speeds at the site met tower and the manufacturer’ s power curve. While this energy estimate is based on actual wind speed and provides a valuable comparison, not all turbines experience the same winds. Although the calculated energy is adjusted for actual monthly availability and estimated parasitic losses, it is not based on the actual operating hours of the turbines. 3-8 Project Performance Table 3-6 Actual and Projected Long-Term Energy — July 2001 to June 2002 Actual Calculated | Long-term Energy Energy Energy Actual vs. | Actual vs. Month (MWh) (MWh) (MWh) Calculated | Long-term T - duly 34 Sete 65% 49% August 52 60 109 85% 47% September 57 65 99 87% 58% October 45 56 117 80% 39% November 16 31 136 53% 12% December 59 63 110 94% 54% January 98 114 125 86% 78% February 69 Td 120 90% 58% March 173 181 87 95% 199% April 88 103 68 86% 130% May 102 107 63 95% 162% June 64 75 83 85% 78% Annual 858 987 1,187 87% 72% | 200 180 | 160 E 140 = 120 > 100 & 80 G 60 40 20 + 0 | Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Actual - - - - Calculated Long-term | Figure 3-2 Actual, Calculated, and Long-Term Projected Energy — July 2001 to June 2002 3-9 Project Performance 3.2.4 Lost Energy Due to Downtime Table 3-7 shows the estimated energy lost during the downtime periods in each month. This calculated energy value is based on the manufacturer’s power curve at site air density and the met tower wind speed at hub height during the downtime periods and it is termed “lost energy” in this report.’ The project lost approximately 85.6 MWh to downtime during its third year of operation, 45% more than the 59.1 MWh lost energy reported for the project’s second year and three times the 28.4 MWh lost during the first year. This marked increase in lost energy is due to several factors. Some of the lost energy during the first year was not accounted for because specific downtime documentation was not available for Turbines 4 to 10 for the first several months of the year. During the second and third years of operation, the wind speeds were higher, resulting in greater energy losses when the turbines were down. The turbine availability also decreased somewhat from 96.8% during the first year, to 95.9% during the second year, to 94.5% during the third year. Section 4 addresses specific causes of turbine downtime during the third year. Table 3-7 also shows that lost energy per hour of downtime has increased each year. This increase was generally the result of higher wind speeds during turbine downtime events. Table 3-7 Downtime and Lost Energy by Month — July 2001 to June 2002 Lost Energy/ Downtime |Lost Energy| Downtime Month Hours (kWh) Hour (kW) July 1,040.0 7,173 6.9 August 981.6 5,133 5.2 September 39.8 403 10.1 October 159.0 2,257 14.2 November 107.5 1,117 10.4 December 39.8 355 8.9 January 78.8 4,330 54.9 February 745.3 17,921 24.0 March 736.8 28,685 38.9 April 313.3 8,259 26.4 May 213.7 6,107 28.6 June 316.5 6,354 20.1 3rd Year — 7/01-6/02 4,772.2 88,094 18.5 2nd Year - 7/00-6/01 3,578.5 59,102 16.5 1st Year - 7/99-6/00 1,975.5 28,447 14.4 “In reality, the energy is not “lost,” but rather the opportunity to capture the wind energy is lost during periods when the turbines are unavailable to operate. 3-10 Project Performance As discussed in previous KEA reports, the met tower wind speed used for estimating lost energy is undoubtedly more representative of some turbines than it is of others. The most accurate estimate of lost energy would be based on the actual wind experienced at the nacelle of each turbine. However, the turbine-mounted anemometers are mounted on the tower at approximately 18 m (59 ft), rather than the 26.5-m (87-ft) nacelle height, and the data are not representative of the turbine nacelle wind speeds. In addition to the difference between wind speeds at the two heights, the turbine-mounted anemometers are affected by wake turbulence from the turbine blades and tower. The periods with the most lost energy do not necessarily coincide with the periods of the most downtime. For example, during the third year, 42% of the downtime occurred during July and August; however, due to low wind speeds, energy lost during those months accounted for only 14% of the total annual lost energy. On the other hand, February and March account for 31% of the downtime but more than 53% of the total annual lost energy. Table 3-7 also shows the lost energy per downtime hour by month. January had the highest rate of energy loss per downtime hour, at 54.9 kW, while August had only 5.2 kW. In general, months with high energy loss per downtime hour correspond to months with high average wind speeds. Figure 3-3 shows the actual energy production, lost energy due to downtime, and average wind speed for each month. The figure illustrates the relationship between the potential output of the project (actual plus lost energy) and the wind speed. 250 10 200 a 8 = = E = 150. St 6s = 3 > Q > 100 4 0 Q sc a £ . ll ll i | I i i PRE d. : Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Wind Speed (m/s) Figure 3-3 Actual and Lost Energy by Month - July 2001 to June 2002 Figure 3-4 shows the actual and lost energy for each turbine during the third year of operation. Assuming the turbines produce power at or near the warranted power curve when they operate, the sum of the actual and lost energy should be nearly equivalent for all turbines, with only minor variations that account for individual turbine losses. As shown in the figure, however, Turbine 8 generated lower energy than the other turbines. Turbine 8 generates less energy because the pitch setting was modified to limit the high energy output during cold high-wind 3-11 Project Performance periods. Turbines 2 and 3 have a lower sum of actual and lost energy than the other turbines due to tip brake problems. Although a turbine is considered available and generally continues to operate when a tip brake deploys erroneously, the turbine output is significantly reduced. Consequently the actual energy generated during these events is very low and because the turbine is considered available, lost energy is not estimated. Section 4 addresses the tip brake events and other causes of turbine downtime. During the first and second years, Turbine 3’s performance was significantly lower than that of the other turbines. Turbine 3’s relative improvement during the third year is primarily due to a change in operating strategy. During the third year, KEA shut Turbine 3 down whenever they observed a deployed tip brake. Because the turbine was then unavailable, lost energy was calculated rather than operating the turbine with little or no output. The turbine was also shut down for an unusually long time during February and March when site personnel were not available to troubleshoot a tip brake problem. The lost energy was calculated for this long downtime event. 120 100 oo Oo Energy (MWh) h oO oO oO nN o Oo 1 2 3 4 5 6 7 8 9 10 \o Energy Produced ™ Estimated Lost Energy | | Figure 3-4 Actual and Lost Energy by Turbine — July 2001 to June 2002 3.2.5 Percent Time Generating Figure 3-5 shows the monthly percentage of time the KEA wind power plant produced electricity during its three years of operation. The turbines produced power 3,219 hours (37% of the time) during the third year of operation, 3,965 hours during the second year, and 2,988 hours during the first year. For March 2002, the project’s percent time generating was 64.3%, the highest month during the third year of operation. 3-12 Project Performance Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun 0 7/99-6/00 ™7/00-6/01 @ 7/01-6/02 Figure 3-5 Percent Time Generating Power — July 1999 to June 2002 3.3 Utility Demand and Project Energy The analyses presented in this section are intended to illustrate several key points to utilities contemplating wind energy. Clearly, a wind project produces varying amounts of energy at different times of the year because of variations in the wind resource. Energy has a different value to KEA during different time periods because of variations in the local demand. The energy is more valuable to the utility during the peak demand periods than during the periods of low demand. Figure 3-6 compares the typical seasonal energy demand at KEA with the actual demand from July 2001 to June 2002. The figure also shows the long-term estimated and actual third-year wind energy from the project. The long-term estimated wind energy production closely matches the historic utility demand. Similarly, the highest wind energy output matches the highest demand period; both generally occur between October and February. The actual wind energy produced during most months of the third operating year reflected trends in the actual KEA demand for the year, with the exception of March and May that more closely follow the typical demand. Although KEA’s primary focus is to ensure the reliable operation of the diesel plant, they have used information such as lost energy and revenue analyses to adjust the O&M strategy at the wind project to more effectively allocate resources and schedule O&M activities. The process and the lessons learned at this site should be beneficial to KEA in future commercial wind power projects. Table 3-8 shows the average monthly penetration, or total percentage of KEA energy demand met by actual energy produced at the wind power plant, during its third operating year. The highest average monthly penetration (9.8%) occurred during March, and the lowest penetration (0.8%) occurred during November. 3-13 Project Performance | | 450 — — — | | Wind Energy (MWh) ee eel etree elie Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun ag Long-term Projected Vind Energy sam Actual Vind Energy Typical Energy Demand KEA Actual Demand Figure 3-6 Projected and Actual Third-Year Wind Energy Contribution to KEA Energy Demand Table 3-8 Actual and Projected Average Wind Energy Penetration on KEA System Average Monthly Penetration oe 7/01-6/02 pea July 2.2% 4.4% August 3.2% 6.5% September 3.4% 5.8% October 2.6% 6.3% November 0.8% 7.3% December 2.9% 5.3% January 4.7% 5.8% February 3.2% 6.3% March 9.8% 4.3% April 4.7% 3.7% May 6.6% 3.6% June 4.0% 5.2% Overall 4.0% 5.4% 3-14 Total Energy Demand (MWh) Project Performance 3.4 Power Quality Considerations One of TVP’s objectives is to examine issues related to distributed generation. Relative to the large wind project concept, distributed wind generation using “clusters” of wind turbines is seen by some to offer lower risk and a more flexible way for utilities to participate in wind energy projects. Such projects are typically connected directly to a distribution line without a dedicated substation, which reduces costs. They may be operated independently or from a central, remote site. As an alternative to the traditional U.S. utility approach of expanding centralized generation, the distributed development model offers opportunities for utilities to address system expansion issues and allows smaller, modular capacity assets to be located nearer to load centers. TVP has completed an evaluation of power quality on the four distributed TVP projects.” Initial results of this evaluation were presented at the Windpower 2001 conference. The results specific to the KEA project are summarized in this section. Power quality is of particular interest for distributed wind applications for two primary reasons. First, the wind turbines are connected to distribution feeders rather than to transmission lines. Distribution feeders are not as electrically “stiff’ and are less able to deal with a fluctuating source like a wind turbine. (Stiffness refers to the ability of a feeder to maintain constant voltage during periods of high current.). Secondly, utility customers are typically located on the same distribution line, sometimes relatively close to the wind turbine(s). Without intervening substations or transmission lines, these customers will be more directly exposed to power quality problems should any exist. The variations in output power inherent with wind turbines caused by changes in wind speed, turbulence, wind turbine switching events (e.g., starting, stopping, and switching speeds), and other phenomena have the potential to degrade the power quality of a distribution feeder. A new international standard for wind turbine power quality has been released by the International Electrotechnical Commission (IEC), IEC 61400-21, Wind Turbine Generator Systems—Part 21: Measurement and Assessment of Power Quality Characteristics of Grid Connected Wind Turbines. This document provides a uniform methodology for measuring power quality characteristics of grid-connected wind turbines, including peak power output, reactive power, voltage fluctuations (flicker), and harmonics. These wind turbine electrical characteristics, through interaction with the electrical grid, exert the most influence on the power quality of a particular wind turbine installation. The KEA wind farm uses 66-kW AOC turbines with direct-line-connected, single-speed induction generators and stall-controlled blades. Power factor correction is provided by capacitor banks permanently connected to the turbine outputs. The three or four turbines in each row connect to a common 225 or 300 MVA, 480/12.5 kV transformer located at the end of the row. The transformer outputs connect to a 12.5 kV distribution line via underground cable. ° Power Quality of Distributed Wind Projects in the Turbine Verification Program was presented at the American Wind Energy Association's annual conference, Windpower 2001, in June 2001. 3-15 Project Performance The connection point of the ten wind turbines is near the end of a 5 mile, 12.5 kV distribution feeder. The average load on this feeder is 200 kW, so the wind turbines often supply 100% of this load. There are four feeders in the electrical system, all connected to a single substation bus that is supplied by the nearby diesel generating plant. The Kotzebue electric system is an isolated grid, powered by a diesel generating plant with six generators. Only one or two of the diesel generators typically supply power at any time; the rest are necessary for redundancy. The minimum substation load is 1.8 MW. The wind power penetration into this grid has been as high as 35% for a 10-minute period’. The TVP power quality study evaluated several parameters measured using power transducers at the turbines. These parameters, and the observations regarding each, include the following: Peak Power: Maximum 1|-second and maximum 10-minute average power levels were compared to the rated peak power of 66 kW for the AOC turbines. The measured peak power on a 10-minute basis was approximately 5% higher than the turbine’s rated peak power and measured peak power on a |-second basis was approximately 32% higher than rated power. These values are considered to be within the normal range for a stall-controlled turbine. Feeder Voltage Regulation: 10-minute average voltages were measured and compared to the service voltage range specified in ANSI C84.1. Voltages were maintained well within the ANSI limits. Reactive Power: Reactive power is shown in Figure 3-5 as power factor plotted against power output. Power factor is controlled by a fixed bank of capacitors. This results in more variation in the reactive power requirements and the resulting power factor compared to active power factor regulation, which is utilized on some variable-speed turbines. Nevertheless, the control scheme maintains a relatively constant power factor from about 20 kW output up to full load. Although the power factor measured at the KEA wind site stays at a relatively constant level, the power factor as seen at the Kotzebue diesel power plant has dropped significantly at times during this last year. On several occasions during the summer months of 2002, KEA power plant operators noted that the diesel plant was as low as 0.7. This occurred when wind production was high (between 600 and 700 kW) and the total system load was low (i.e., approximately 1800 kW). These low grid power factors have had no noticeable effect on power quality or stability because the diesel generators in operation are designed to operate effectively in such conditions. Harmonics: Total demand distortion (TDD) of the current measured was compared to the 5% TDD limit recommended in IEEE 519. TDD is the ratio of the root-mean-square value of the total harmonic current to the rated current. The TDD for the KEA turbines, as shown in Figure 3-6, is approximately constant near 3% over the range of operation. Overall, the conclusion of the power quality analysis is that the wind turbines have no measurable adverse effects. Previous analysis has shown that this is true even during periods of high wind penetration on the KEA grid. Additional analysis will be performed in the coming year to ° Characterizing the Effects of High Wind Penetration on a Small Isolated Grid in Arctic Alaska was presented at the American Wind Energy Association’s annual conference, Windpower 2001, in June 2001. 3-16 Project Performance determine if the addition of the North Wind 100 turbine has a noticeable effect on power quality, or if any problems occur at higher penetration loads as the capacity of the wind projects increases. 0.96 ~~" 2 0.92 ———_ oo ee | el —_—__— —____ | Power Factor Oo 8 | | - | | | | | sili 0.86 +— 7 [ae Tea Ts 0.82 (ny nn ST 0.80 4 + o 7 #13 #20 2 33 #40 4 #&«24953 59 466 Output Power (kW) ° g | Figure 3-7 Power Factor vs. Output Power ] 6.0% | | | | | — 5.0% | | & | Fs | | 2 40% s =". 2 - ae — = = - - a 3.0% }-—_______"®*msese esse oe 2 STB eee | c £ | B 2.0% ;— == es 3 | F 1.0% ~-——____ — — = — | || 0.0% | 0 7 13 20 26 33 40 46 53 59 66 Output Power (kW) (= ™ _KEA Snr EEE 519 Limit Figure 3-8 Total Demand Distortion vs. Output Power 3-17 4 PROJECT OPERATIONS AND MAINTENANCE 4.1 KEA’s O&M Strategy KEA personnel provide the ongoing operations and maintenance support for the wind project with some periodic support from their electrical contractor, Thompson Engineering of Anchorage, Alaska. In the past, AOC has periodically traveled to Kotzebue to provide additional maintenance support as necessary. However, it is not logistically practical for AOC technicians to travel to Kotzebue to perform turbine repairs on a regular basis and, with KEA’s increasing experience and knowledge, it is less necessary to have AOC on site. In March 1998, KEA hired Matt Bergan, a wind energy engineer, who was formerly employed at AOC. Mr. Bergan’s initial responsibilities included the ongoing O&M for Phase 1 and the construction oversight for the 7-turbine expansion of the project. Mr. Bergan continues to perform the majority of the O&M duties at the KEA wind project, and he also provides some O&M services to KEA’s Wales, Alaska, wind project that consists of two AOC 15/50 turbines. The O&M strategy at the KEA wind project is significantly influenced by KEA’s other activities. Although the wind energy engineer was hired specifically to operate the wind project, he continues to perform other duties unrelated to the wind project. The reliable operation of the diesel generators takes precedence over the operation of the wind project. KEA was able to hire an engineering intern for the summer of 2002. The intern worked with KEA personnel to perform several maintenance activities at the wind project that had been postponed due to a shortage of personnel. KEA also hired an outside engineer for a week to assist KEA with evaluating the AOC blade pitching tools and techniques. Although KEA is interested in hiring a full-time wind technician to work with the wind energy engineer, it is difficult to find a qualified technician who is willing to live in this remote location and harsh environment. Over time the wind energy engineer has provided some training to other KEA employees to perform basic operating and maintenance tasks. In spite of the limitations inherent in operating a wind project in this small remote community, the turbines have experienced a relatively high three-year average availability of 95.7%. 4.2 Maintenance Activities and Other Downtime Events The KEA project experienced 4,772 hours of total turbine downtime during the third year of operation. This level of downtime represents a 33% increase from the 3,578 hours of downtime experienced during the second year of operation. Specific reasons for the increased downtime are discussed later in this section. Project Operations and Maintenance Although availability is commonly used as a performance measurement in the wind energy industry, it is important to consider the time of occurrence and the cause of the downtime along with the actual number of downtime hours. Figure 4-1 compares the monthly availability to the average monthly wind speeds from July 2001 through June 2002. Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun | —+— Wind Speed (m/s) = = = is TvP Availability | Figure 4-1 Monthly Availability and Wind Speed — July 2001 to June 2002 Availability was highest from September through January. The lowest availability months, July and August, coincide with lower-than-average wind months. KEA understands the benefit of scheduling activities such as preventive maintenance and inspections during periods of low wind speed whenever possible. For example, during the third year of operation, all of the downtime related to project expansion was scheduled during the August reporting period because August is generally a low-wind month. Fortunately the low-wind months often occur during the months of greatest daylight hours, providing adequate opportunities to perform scheduled maintenance activities. In addition to the time of occurrence, the cause of downtime and the cost to return a turbine to service are also important considerations. For example, assuming the winds are comparable, 10 hours of downtime due to a fault that is reset without additional action has less impact on the project than 10 hours of downtime due to a repair that requires significant labor, equipment, and parts replacement. Following is a discussion of the cause and impact of the project downtime during the third year. The downtime is categorized and compared to the second-year downtime. The impact of events is discussed in terms of hours and lost energy, if appropriate. As discussed in the previous section, the lost energy for each downtime period is calculated for each turbine on an event-by- event basis that considers the actual wind conditions at the site during the time of the event. 4-2 Project Operations and Maintenance Actual O&M cost data for the project are not readily available. The majority of the spare parts used to maintain the turbines have been provided by AOC under the conditions of the turbine warranty. KEA estimates that, on an annual basis, approximately one-half of the wind energy engineer’s time is spent performing activities related to the operation and maintenance of the wind project. 4.2.1 Downtime Categories Figure 4-2 summarizes the total downtime by category at the KEA project during the second year of operation. The categories are: O&M-This category includes all troubleshooting, adjustments, retrofits, and repairs performed on the turbines. It includes downtime that accumulates while waiting for parts, instructions, or outside services not available on site but required to place a turbine back on line. Downtime associated with the SCADA system is not included in this category if the turbines continued to operate. O&M downtime accounts for approximately 3,283 hours or 69% of the total downtime during the third year of operation. This represents a 20% increase in O&M downtime from the second year. This increase is attributed largely to the downtime hours related to tip brake problems. Faults—This category includes only those faults that require a reset and no other action. If a maintenance activity immediately follows a fault, the downtime hours associated with the fault are combined with the repair hours and the event is included in the O&M category. In some cases, faults are not cleared until after a repair is made. In these instances, the fault time is re-classified as an O&M event if sufficient information is available to make that determination. When faults occur in the evening or on weekends, they are often reset in the morning of the next business day. Occasionally harsh weather limits access to the site, in which case a turbine reset may be delayed. The response time before the fault is reset is included in the fault category as long as the fault is not followed by maintenance. Faults account for approximately 207 hours or 4% of the total downtime during the third year of operation. Fault downtime decreased by more than half from the second to third year and is a relatively low number of downtime hours. The call-out feature was incorporated into the SCADA system late in the summer of 2002 and may further reduce fault downtime. The SCADA call-out feature is discussed in Section 4.3. Line Outages—Specific, identifiable line outages are included in this category. While KEA tracks total feeder outages, they do not track some partial outages. Therefore, several brief undetected line outages at the wind site are likely to have occurred during the year. The line outages included in this category were documented and reported by the site personnel. During the third year of operation, line outages account for about 228 hours, or 5% of the total downtime. This is approximately a 4% reduction in line outage downtime from the second year. Project Expansion-This category includes downtime for activities associated with the expansion of the KEA wind project and represents 17% of the total project downtime during the third year of operation. The turbine downtime hours related to project expansion include electrical line work and road extension activities. A detailed discussion of the KEA project expansion is provided in Section 5. Project Operations and Maintenance e¢ Other-This category includes downtime for the removal of the old Campbell SCADA system. This system was installed in Phase | for Turbines 1, 2, and 3. In July 2001 the turbines were shut down and the SCADA system was decommissioned. The Campbell system was sent to the Wales, Alaska, wind project for installation. This category includes 230 hours that were incurred by Turbines | and 2. Turbine 3 did not incur downtime hours for this activity because it was already shut down due to tip brake problems. Total Downtime: 4,772 hours Other Fault Line Outage 4.8% 4.3% 4.8% Project | Expansion | 17.3% osm 68.8% Figure 4-2 Total Project Downtime by Cause — July 2001 to June 2002 The remainder of the section describes additional analysis of the downtime associated with faults and O&M activities. Figure 4-3 shows the percentage of total lost energy by category at the KEA project during the third year of operation. O&M downtime accounts for about 72,831 kWh of lost energy, faults account for 5,020 kWh, line outages account for 6,063 kWh, project expansion downtime accounts for 2,885 kWh, and “Other” downtime accounts for 1,295 kWh. Although the downtime hours increased 33%, the third-year estimated lost energy increased 49% from the second year, indicating that a greater amount of downtime hours occurred during energy- producing winds. The downtime category that KEA had some control over is the project expansion downtime. The maintenance activities related to expanding the project were scheduled during periods of low winds. This is evident in the relationship between the downtime hours and the lost energy for this category. While over 17% of the project downtime is attributed to project expansion activities, only 3% of total lost energy is attributed to this category. Project Operations and Maintenance Total Lost Energy: 88,094 kWh Project Other De Line Outage 15% 57% 6.9% Expansion 3.3% O&M | 82.7% Figure 4-3 Total Lost Energy by Cause — July 2001 to June 2002 Figure 4-4 shows the downtime for each wind turbine by category. Turbine 3 contributed significantly more O&M downtime than any other turbine with 47% of the total O&M downtime during the third year for reasons discussed below. Figure 4-4 also illustrates the variability of the total downtime experienced by individual turbines. Turbine 3 experienced 1,539 hours of downtime, approximately 32% of total project downtime in the third year. In contrast, Turbines 1, 4, 8, 9 and 10 combined (half the project) contributed only 21% of the total project downtime. Appendix D presents additional information on the specific causes of downtime for each turbine. Figure 4-5 shows the downtime for each month by category and the monthly mean wind speeds during the third year of operation. The months of greatest downtime, July and August, correspond to months of relatively low winds, resulting in relatively low lost energy. Approximately 42% of the total downtime hours occurred during July and August with only 14% of the lost energy attributed to these downtime hours. Unfortunately, the project experienced 737 hours of downtime, 15% of the total project downtime, during March, which was the highest wind month. Consequently, 33% of the lost energy for the third year occurred during March. Table 4-1 summarizes the total downtime hours by category for each of the three years of the KEA wind project. As the table indicates, total downtime hours have increased each year of the project. The project downtime hours increased 44% from the first to the second year and 33% from the second to the third year. However, the majority of the increased downtime hours in the third year are attributed to the project expansion activities and increased O&M. 4-5 Project Operations and Maintenance 1600 1400 | 1200 - 1000 | oa 5 800 + F 600 400 | 200 | | 0 | Turbine @ O&M oO Project Expansion O Faults m Line Outages 0 Other Figure 4-4 Total Project Downtime by Turbine — July 2001 to June 2002 1200 10 9 1000 4 8 800 | 7 6 600 4 § 4 400 4 3 | 200 4 | | | | 0. ; = a |__| : | Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun | fay O&M C7 Expansion = Fault | Mg Line Outage mam Other — Wind Speed Figure 4-5 Total Project Downtime by Month — July 2001 to June 2002 4-6 Project Operations and Maintenance Table 4-1 Downtime Hours by Category — July 1999 to June 2002 Downtime Hours Downtime Category 07/99 — 06/00 07/00 — 06/01 07/01 — 06/02 Fault 149.7 | 462.0 207.2 Line Outage 123.3 3725 | 2276 O&M | 1,702.7 | 2,729.5 3,283.5 Other | 83.2 [145 | 2295 | WT 2 Storm Damage 432.8 N/A N/A Project Expansion N/A N/A 823.8 Total 2,491.7 3,578.5 4,771.5 During the first year of operation, an unusually gusty wind storm in September 1999 caused the maintenance rope on Turbine 2 to unravel and break free from the leg of the tower. During the storm, the rope got caught in the rotating blades of the turbine, became entangled in the tip brake and caused considerable damage. This resulted in 433 hours of downtime for repairs, and the creation of a unique downtime category for the first year of the project. During the third year of the project, KEA expanded the wind project with the installation of the North Wind 100 turbine. The site work was also completed for upcoming installation of two additional AOC 15/50 turbines. These project expansion activities included electrical line work and an extension of the road. The resulting 824 hours of turbine downtime created this second unique downtime category. Figure 4-6 illustrates the distribution of downtime for the three years of operation on a turbine- by-turbine basis. During the third year of operation, 32% of the project downtime, 1,539 hours, is attributed to Turbine 3. Turbine 7 accounts for another 22% of the project downtime during the third year. Overall, during the three years of operations, 36% of the total project downtime is attributed to Turbine 3. While the average per turbine downtime for the three years was 1,084 hours, Turbine 3 experienced 3,862 hours. Turbines 2, 5, and 7 also experienced higher-than-average downtime with an average of 1,316 hours per turbine during the three years of operation. Turbines 1, 4, 6, 8, 9, and 10 experienced a much lower average downtime of 506 hours per turbine during the three years of operation. 4.2.2 Downtime Due To O&M Activities As discussed in Section 3, the TVP availability was approximately 95% during the third year of operation, and total turbine downtime was 4,772 hours. The majority of the downtime, 3,283 hours, was attributed to O&M activities. During the third year, electrical repairs and tip brakes accounted for the majority of the O&M downtime. Figures 4-7 and 4-8 categorize the O&M downtime and related energy losses by major turbine component. Project Operations and Maintenance 2,000 1,800 1,600 1,400 1,200 - 1,000 800 Hours 600 400 200 0 1 2 3 4 5 6 7 8 0 7/99-6/00 @ 7/00-6/01 © 7/01-6/02 Figure 4-6 Comparison of Project Downtime by Turbine - July 1999 to June 2002 O&M Downtime: 3,283 hours | Controller | Anemometer 3.7% | 3.2% Tip Brakes 40.5% Figure 4-7 O&M Downtime by Cause — July 2001 to June 2002 4-8 Bectrical 52.6% Project Operations and Maintenance Lost Energy during O&M: 72,831 kWh Controller Anemometer 0.5% 25% Tip Brakes 34.9% Bectrical 62.0% Figure 4-8 Lost Energy Due to O&M by Cause — July 2001 to June 2002 Figures 4-9 and 4-10 show the O&M downtime distribution by month and by turbine. Some general observations on the turbine failures and repairs are provided below. O&M Downtime: 3,283 hours 900 1 | 800 ——— a — —| | 1s ——— 600 -—— —— — }— —| ® | 3 500 —— b Ss xz 400 ee = 4 }-— — 300 aan an c= : —| | ve fit aa il 7 a Biba 0 _ = i i Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun B Electrical OTip Brakes O Controller m Anemometer Figure 4-9 O&M Downtime by Month — July 2001 to June 2002 4-9 Project Operations and Maintenance O&M Downtime: 3,120 hours | | | | | {| | EL | | | | | | a 8 o = o ‘Electrical O Tip Brakes & Anemometer o Controller | Figure 4-10 O&M Downtime by Turbine — July 2001 to June 2002 Electrical. During the third year of operation, electrical events accounted for 1,718 hours of O&M downtime. Electrical O&M accounts for 53% of O&M downtime and approximately 36% of the project’s total downtime during the third year. Turbines 3, 5, and 7 experienced the majority of the electrical O&M downtime with 389, 378, and 713 hours, respectively. During the second year, O&M downtime due to electrical issues accounted for 2,178 hours. The high electrical downtime hours during the second year were largely due to a single event at Turbine 3, which occurred toward the end of the second year reporting period. As reported in the previous annual report, this event continued into the third year of operation. The portion of this event that occurred during the third year accounts for an additional 388 hours of downtime and was the longest electrical O&M downtime event during the third year of operation. Turbine 3 experienced approximately 2,039 hours of downtime between April 2001 and July 2002 due to an overspeed problem. In spring 2001, KEA replaced the parking brake undercurrent sensor and speed sensor, and installed new contacts in the main contactor. When the turbine continued to experience overspeed problems, KEA personnel removed, tested, and reinstalled the frequency/voltage unit. However, the turbine continued to experience problems and was offline for most of May and all of June 2001. In July, after more troubleshooting, KEA regrounded the shield around the cables of the speed-sensing unit. They also calibrated and installed a new shaft- speed sensor and frequency-to-voltage converter. This resolved Turbine 3’s overspeed problem and its speed-sensing unit has been functioning properly since that time. During the third year, the frequency-to-voltage converter was also replaced on Turbine 7, attributing to 146 hours of downtime. Turbines 5, 6, and 7 experienced 728 hours of electrical downtime due to blown fuses and failed surge suppressors. The remaining electrical O&M downtime during the third year was related to twist cable maintenance and repair, miscellaneous sensors, and a loose terminal on a main contactor. 4-10 Project Operations and Maintenance Tip brakes. Tip brake problems resulted in a total of 1,322 hours of O&M downtime during the third year of operation. These downtime hours include troubleshooting and repair time, and represent 9 events. The majority of the tip brake downtime, 1,127 hours, is attributed to Turbine 3. Turbine 2 experienced 163 hours of tip brake downtime, and Turbine 4, the remaining 32 hours. During the July and August reporting periods, KEA troubleshot and repaired a damaged secondary rotary transformer on Turbine 3. This event accounts for 175 hours of the tip brake downtime. The remaining 952 hours of tip brake downtime on Turbine 3 occurred between January and March and was caused by a tip brake that would not stay closed. The wind energy engineer was out of town for a good portion of March and unable to address problems at the wind project. As discussed in previous reports, an important aspect of tip brake problems is reduced energy output when a tip brake is erroneously deployed. When a tip brake deploys erroneously, the turbine is considered available and continues to operate but produces significantly less power than if it were operating properly. These energy losses are in addition to the energy lost during recorded downtime events and are more difficult to accurately quantify. For example, in addition to the downtime experienced by Turbine 3, the turbine produced significantly less energy while it was available to operate than the other turbines. When individual turbine energy production for the third year of operation was adjusted to account for availability and the adjusted energy was compared, Turbine 3 only produces about 80% as much energy as the average of the other nine turbines. Tip brake issues have been a continuous problem on Turbine 3. O&M downtime for tip brake troubleshooting and repairs increased significantly from the second to the third year. During the second year of the project, tip brake problems only contributed 202 hours, 7% of total O&M downtime. During third year, tip brake downtime accounted for 1322 hours of the O&M downtime. However, it’s important to note that only two of the ten turbines experienced downtime due to tip brake problems. During the first two years of operation, several turbines experienced downtime due to problems with the tip brakes. As discussed in the previous EPRI reports, AOC has worked to improve the reliability of the tip brakes by upgrading several small components. Upgrades have included stronger magnets, improved alignment, a more rugged damper bracket-to-hinge block joint, and improved catch plates and catch plate grommets. AOC also established upgrades for hinge eyes, catch plate washers and cap screws, and a new strain relief for the blade cables. Several of these improvements have been incorporated on some of the turbines. These upgrades are being incorporated on the remaining turbines when tip brake inspection or repair is required. Consequently, several of the turbines have not yet been retrofitted with the tip brake upgrade components. Anemometers. During the third year of operation, anemometers accounted for 120 hours of O&M downtime. Anemometer O&M hours included anemometer replacements on five turbines throughout the year and accounted for 4% of O&M downtime during the third year. Controller. During the third year, the controller accounted for 106 hours of O&M downtime. The controller downtime is attributed to one event and represents 3% of the total O&M downtime during the third year. 4-11 Project Operations and Maintenance Other O&M. This category includes 18.5 hours of downtime. The majority of these hours, 16 hours, are attributed to unknown O&M. Unknown O&M consists of undefined maintenance events for which there is no documentation. The few remaining hours were for two brief scheduled maintenance activities. This amounted to such a small percentage (0.6%) of downtime that it does not appear in the figures for O&M downtime. Table 4-2 summarizes O&M downtime hours by category for the three years of the project’s ten- turbine operation. The tip brake system downtime increased significantly from 202 hours in the second year to 1,322 hours in the third year. This increase is largely due to extensive tip brake downtime at Turbine 3. Table 4-2 O&M Downtime Hours by Category — July 1999 to June 2002 O&M Downtime Category | 07/99 — 06/00 | 07/00 — 06/01 | 07/01 — 06/02 Electrical 676.5 2,177.8 1,717.7 Gearbox 0.0 342.0 0 Rotor 0.0 7.0 0 Tip brake system 664.3 201.5 1,321.8 Anemometer 65.8 0.0 119.7 Controller 131.3 0.0 105.80 Other/Unknown 164.7 1.2 18.5 Total 1,702.7 2,729.5 3,283.5 4.2.3 Downtime Due To Faults Figure 4-11 shows a breakdown of fault downtime by type for the KEA turbines during the third year of operation. Faults accounted for 207 hours of downtime and an estimated energy loss of 5,020 kWh. Electrical faults account for 87 hours, or 42% of the total fault downtime during the third year. After a power outage, four turbines failed to reset themselves and account for 59 hours, 28% of the fault downtime. The remaining fault downtime hours were for unknown reasons and a few brief, miscellaneous faults. Besides total fault downtime hours, another important factor is the frequency and duration of fault events. For example, a project may experience relatively few faults but the faults may not be reset for several hours or days due to the operating strategy of the utility. KEA has recently incorporated a SCADA call-out feature that notifies a remote operator when a turbine is off-line. This system could reduce fault downtime as well as O&M downtime. Because KEA often does not have personnel on site, they had Second Wind add the call-out feature to their SCADA system. The call-out function is programmed to call the KEA office in town during business hours when a turbine goes off line. On the weekends, the wind energy engineer or other KEA personnel would be notified in the event of a turbine outage. Second Wind completed the SCADA software programming update and incorporated the call-out feature in September 2002 when they upgraded the SCADA system to communicate with the NW 100 turbine. 4-12 Project Operations and Maintenance Fault Downtime: 207 hours Tip Brakes Other 0.4% 29.1% Electrical 42.1% Controller 28.4% Figure 4-11 Fault Downtime by Cause — July 2000 to June 2001 Figure 4-12 demonstrates the duration and number of faults by month for the third year. During the third year, June had the highest number of fault events and the greatest downtime hours. However, even this highest month only had 6 faults. The six faults resulted in 100 hours of downtime. As previously discussed, four turbines required manual resets after an overnight power outage and accounted for 59 hours of June fault downtime. The remaining fault downtime during June is attributed to one electrical fault that occurred over a weekend and was not reset until Monday. Total Hours 0 20 40 60 80 100 120 | Number of Faults m Number of Faults D Total Hours | Figure 4-12 Fault Frequency and Duration by Month — July 2001 to June 2002 4-13 Project Operations and Maintenance Figure 4-13 illustrates the distribution and cause of fault downtime among the turbines. Turbine 7 had six faults, the highest number of faults of any turbine, and also the highest fault downtime, 81 hours. Turbines 3 and 6 experienced no faults and Turbine 9 contributed less than an hour of fault downtime. The remaining turbines had less than 20 hours of fault downtime during the third year of operation. Fault Downtime: 207 hours 90 — 80 a | | 70 4— AN -_ —a | 60 £50 |——_______ = — ——————— | | 2 40 = / 30 4 —— | | 20 10 0 i = | o 1 2 3 4 5 6 7 8 9 10 Turbine Figure 4-13 Breakdown of Fault Downtime by Cause and Turbine — July 2001 to June 2002 Table 4-3 summarizes the fault downtime by cause for the three years of operation. While fault downtime more than doubled during the second year, the number of fault downtime hours significantly decreased during the third year. The level of fault downtime experienced even in the second year is still relatively low. KEA may reduce fault downtime further with the incorporation of the SCADA call-out feature. Table 4-3 Fault Downtime by Category — July 1999 to June 2002 Fault Category 07/99 —06/00 | 07/00 — 06/01 | 07/01 — 06/02 Communications 0.0 280.5 0.0 Controller 0.0 77.8 58.8 Electrical 6.7 22.2 87.2 Tip Brake System 0.0 6.3 0.8 Unknown/Other 109.5 75.2 60.3 Yaw 33.5 0.0 0.5 Total 149.7 462.0 207.2 4-14 Project Operations and Maintenance 4.3 SCADA System Experience The AOC turbine was initially designed as a stand-alone system and AOC did not offer any type of SCADA system at the time of KEA’s original purchase order. KEA contracted with Island Technologies Incorporated (ITI) to design and install a system that would enable remote monitoring and recording of wind turbine operation performance data and parameters and some simple remote control of wind turbine functions. The system was installed in early 1998 for control and monitoring of the Phase | turbines. The Campbell SCADA system was decommissioned during the July reporting period and sent to KEA’s two-turbine wind project in Wales, Alaska. NREL provided a Second Wind SCADA system to the KEA project as part of KEA’s involvement with the TVP. Second Wind and GEC personnel provided on-site support to KEA for the hardware installation. Second Wind personnel performed preliminary commissioning of the SCADA system in September 1999. The system was upgraded in September 2002 to incorporate the new NW 100 turbine and provide a call-out feature. The call-out feature is programmed to call a remote operator when a turbine faults off. KEA is in the process of deciding on the preferred strategy for using this new SCADA feature. Because KEA personnel are not generally on-site, KEA expects the call-out system to reduce downtime hours by providing earlier notification of turbine outages. The Second Wind SCADA system includes a Supervisor Computer which allows real-time monitoring and remote control of the turbines and interconnections with the turbine controllers. In addition to turbine data, the Second Wind SCADA collects concurrent data from the met tower sensors and redundant power quality transducers (Phaser™) also manufactured by Second Wind. The Phasers™ measure numerous power quality parameters including real and reactive power, voltage and current on each phase, voltage and current total harmonic distortion (THD), frequency deviation, and voltage imbalance. There is a Phaser™ attached to each turbine in addition to the project interconnection point. Table 4-4 presents the data recovery rates for SCADA data downloaded from the Second Wind system during the third year of operation. The table includes recovery rates for the turbine data, the Phaser™ data and the met data. The data recovery and overall reliability of the SCADA system improved during the third year with the exception of the August reporting period. During August 2001, KEA experienced several periods of SCADA communication loss. Site power was turned off while high-voltage lines for the new turbines were installed. The site roads were extended down the turbine rows. During this activity heavy equipment crushed a section of communications cable. A period of troubleshooting was required to find the location of the damaged cable. The SCADA data recovery for the turbines during August was 53%. While this represents approximately 350 hours of lost data during the period, the turbines were able to continue operating except for approximately 85 hours. The SCADA program constantly scans the output from the turbine’s programmable logic computer (PLC) and posts data in a database located on the computer hard drive. This constant accessing of the hard drive tends to fragment the hard drive space. During the second year, Second Wind recommended running a defragmentation program. KEA has continued running the defragmentation program regularly and also archives the database on a regular basis to keep the database at a manageable size. The current computer/database management strategy ensures 4-15 Project Operations and Maintenance reliable system operations and data recovery rates. Excluding the low data recovery in August, the turbine, Phaser™, and met tower data recovery rates during the third year were 98%, 96%, and 98%, respectively. Table 4-4 Recovery Rates for SCADA System Data — July 2000 to June 2001 Month Turbine Phaser™ [1] Met [2] July 92.8% 82.3% 91.3% August 52.9% 49.6% 67.7% September 100.0% 99.7% 100.0% October 96.7% 94.1% 96.9% November 97.2% 95.7% 99.1% December 100.0% 98.5% 100.0% January 100.0% 99.7% 100.0% February 99.1% 98.2% 100.0% March 97.0% 95.5% 95.5% April 99.4% 98.7% 99.8% May 99.3% 97.3% 99.3% June 95.7% 91.0% 96.9% 07/01 — 06/02 94.2% 91.7% 95.6% 07/00 — 06/01 95.2% 92.2% 95.1% 07/99 — 06/00 88.9% 94.9% 91.2% [1] Values are based on Real Turbine Power data collected from the Second Wind Phasers™. [2] Values are based on recovery of hub-height wind speed data. 4.4 Operating Guidelines As part of routine TVP monitoring of the KEA project, inconsistencies were noted in turbine availability data that suggested that the turbines were sometimes being operated in a manner that led to inaccurate SCADA measurements. For example, turbines that the SCADA indicated were stopped or in maintenance mode were generating power. Investigation led to the conclusion that consistent methodologies for operating and maintaining the AOC turbines and the wind project in general were not documented. Consequently, the TVP, in cooperation with KEA, began preparation of an Operation Guideline document to identify and document safe and consistent operations procedures for the wind project, turbines, and SCADA system. 4-16 Project Operations and Maintenance Completion of the Operation Guideline is scheduled for the upcoming year; however, several key operational issues have already been identified and addressed. These include: e Proper procedures for changing turbine status through the SCADA and manually at the turbine; Procedures for SCADA operation during and after line outages; More complete descriptions of turbine switches and operation modes; Procedures for safely climbing and maintaining turbines; Turbine troubleshooting procedures; and General maintenance schedules for the AOC turbines. These instructions and consistent procedures should help current and future operators of the KEA wind project with routine and emergency operations of the park, and should also help generate higher quality SCADA data from the turbines. This, in turn, is expected to simplify data analysis and reporting procedures for KEA and the TVP. 4.5 Potential Performance Improvements and Turbine Testing 4.5.1 Slow-Starting Turbines As discussed in the previous operating reports, in April 2001 AOC installed a free-wheeling program in the control software for two turbines in an attempt to reduce the slow-start problems occasionally exhibited by the KEA turbines. The slow-start condition occurs when the turbines were available to operate, and the winds speeds were above turbine cut-in, but the turbine does not connect to the utility line. The free-wheeling program was applied to Turbines 6 and 7, which had frequently exhibited the slow-start behavior. Initial data analysis indicated that the program change may improve the slow-start problem marginally, but also increases power consumption by the turbines at low wind speeds. Sufficient data now exist to evaluate the changes. Data were assembled for the two turbines that received program changes and two adjacent turbines (Turbines 5 and 8). Data were reviewed and were generally comparable across the four turbines under consideration in terms of data recovery and turbine availability. The ability of the program change to reduce slow-start events was evaluated by determining the percentage of time the free-wheeling turbines produced power relative to the two baseline turbines both before and after the program change. An increase in the relative percentage would indicate that the free-wheeling program is reducing slow-start events. Before the program change, Turbines 6 and 7 produced power at 95% of the frequency of the baseline turbines. Following the program change (i.e., when allowed to free-wheel), Turbines 6 and 7 produced power at 120% of the frequency of the baseline turbines. Consequently, it appears that the free- wheel program has indeed reduced slow-start events for these two turbines. As noted, the free-wheeling program also increases turbine power consumption at low wind speeds. The analysis described above was repeated to examine changes in power consumption rather than time generating. Before the program change, Turbines 6 and 7 consumed power at an average of 159% of the amount of the baseline turbines. Following the program change (i.e., when allowed to free-wheel), Turbines 6 and 7 consumed power at an average of 312% of the 4-17 Project Operations and Maintenance amount of the baseline turbines. This indicates a significant increase in the amount of power consumption, although the consumption is still low (i.e., less than 3%) compared with the amount produced when the turbines are generating in higher winds. Overall, the free-wheeling program appears to be of marginal benefit. Additional energy will be generated as slow-start events are reduced in frequency, but the amount of energy available at lower wind speeds is not large and will be partially offset by the increased consumption below cut-in wind speeds. Further evaluation of the slow-start problem will likely be necessary to produce a more effective long-term solution. 4.5.2 Turbine Pitch Settings During the first two years of evaluation, power curve issues were noted for some of the AOC turbines at KEA. First, most turbines would generate power at levels significantly in excess of the 66 kW rated capacity during periods of high air density. This produced immediate problems such as blown fuses and also generated concern that long-term problems such as reduced gearbox life and reduced overall efficiency would occur. Second, although the turbines were intended to be configured with identical pitch angles, it was clear that there were significant differences between the power curves of some turbines, indicating dissimilar pitch settings. Based on these observations and the results of the repitching of Turbine 8 in September 2000, the TVP performed an evaluation of the available performance data to identify an optimal pitch setting for the turbines that would result in the highest expected annual energy production while limiting the peak power production to levels that would not be expected to have an adverse effect on the turbine component life. Initial reviews of the data indicated that, to a large extent, these goals were mutually exclusive; i.e., pitching the turbines to reduce overproduction would likely have a negative impact on annual energy production. Consequently, the data were reanalyzed with the turbine component life as the main goal, and the extent to which meeting this goal would impact turbine production was evaluated. A target level of a 2-second peak production of 85-kW_at-a-worst-case air density of 1.41 kg/m (based on the highest observed air density during the winter of 2002) was established as the point at which no long-term effects. on component life o' would be likely to occur. Worst-case peak power levels for each of the turbines were compared with the peaks of sea level power curves, and it was determined that setting the pitch such that the turbines would not generate power in excess of the target level would reduce the peak of the sea- level power curve to approximately 60-64 kW; i.e., only a 2-6 kW reduction from the TVP rated capacity of 66 kW. Based on the apparently small impact on the desired power curve, KEA and GEC concluded that repitching the turbines to reduce peak power would be beneficial. Current turbine pitch settings were measured in August 2002 and an optimal setting that is expected to meet the target peak power level was determined. The impact on energy production will vary by turbine due to the wide variety of current pitch setting. Based on preliminary analyses, the overall annual energy production is not expected to decrease by more than 10% as a result of repitching the turbines to the recommended pitch setting. The results of the turbine repitch program, including peak power and overall energy production, will be more thoroughly evaluated over the coming year. 4-18 3 PROJECT EXPANSION ACTIVITIES AND PLANS 5.1 The North Wind 100 Turbine Installation of the Northern Power Systems (NPS) North Wind 100 (NW 100) turbine began April 23 and the turbine was commissioned on May 17, 2002. The NW 100 has a direct-drive, variable-speed generator that operates between 50-69 rpm. The turbine has a three-blade rigid rotor, fixed-pitch, and stall-regulated design with a rotor diameter of 19.1 m (63 ft). The NW 100 is an upwind turbine with an active yaw system. The turbine is mounted on a 23.4-m (77-ft) tubular steel tower that is installed on a pile foundation. The resulting hub height of the turbine is approximately 26.5 m (87 ft). Appendix E provides a complete description of the NW 100 turbine. The NW 100 turbine was designed for small isolated grids. It was specifically designed for reliable operation and easy maintenance in severe cold climates. The direct-drive generator eliminates the need for a gearbox which would require heating for effective lubrication in extremely cold temperatures. Gearboxes also require a fair amount of maintenance that can be difficult in harsh environments. The enclosed tower with an inside ladder allows access for turbine maintenance with less exposure to the elements. The NW 100 wind turbine was developed by NPS with support from several cooperating agencies within the U.S. government. These agencies included the National Aeronautics and Space Administration (NASA), the National Science Foundation (NSF), the DOE, and NREL. Initial funding for product development came from two Small Business Innovative Research (SBIR) grants. NREL funded development of a 100 kW direct drive generator under their Turbine Development Innovative Subsystems program. Westinghouse Electric acted as a subcontractor to NPS in this development effort and fabricated the prototype generator. This generator was incorporated into the Proof-of-Concept (POC) NW 100, which has become the testbed for field evaluation of the NREL-funded generator. The POC turbine was commissioned in February 1999 for long-term testing at a hilltop site near the NPS headquarters in central Vermont. In September 2000, NASA, NREL and Northern Power were awarded the prestigious R&D 100 award by R&D Magazine for development of the North Wind 100 wind turbine from its inception under the SBIR program. For 38 years, this award has been presented annually to the top 100 innovative products, chosen for their “technological significance” over competing products and technologies. 5-1 Project Expansion Activities and Plans NPS believes that the NW 100 has significant commercial potential in small wind project and wind/diesel village power applications. DOE and NREL have continued to show strong support for introduction of the product into these markets, particularly in Alaska. In 1999, NPS began work on a new project under the NREL Turbine Research Program. Under this project NPS has refined the NW 100 design, carried out component qualification tests, and in April 2001 installed a production prototype unit at the National Wind Technology Center where it is undergoing certification testing in conjunction with Underwriters Laboratories (UL). The NW 100 installed at Kotzebue is the second production prototype. The production prototypes differ significantly from the POC turbine in several ways. The turbines in Kotzebue and Boulder have advanced power electronics that were not available when the POC turbine was developed. The production prototype turbines also are equipped with an advanced blade design developed by Sandia. As TVP performance evaluation continues at KEA, comparisons will be made to the experience of other NW 100 turbines. 5.2 Installation Experience As previously illustrated in Figure 2-1, KEA’s NW 100 is designated as Turbine 14 and is located at the end of the middle row of turbines, just south of Turbine 4. The 30-ton crane used for erection of the AOC turbines was also used for the installation of the NW 100. The installation team included two NPS employees, one NREL employee, and several KEA employees and contractors, although not all individuals were present for the entire installation. This section presents an overview of the installation and commissioning activities. The tower foundation used for the NW 100 is similar to the foundations designed for the AOC turbines using “freezeback pilings.” The foundation design is based on standard construction techniques used in other arctic applications and is specifically designed to prevent significant temperature changes in the permafrost. The pilings, pictured in Figure 5-1, are 9.1 m (30 ft) long, with a 30 cm (12 in) diameter, and have 3.7 m (12 ft) of helix coil. Holes were drilled, the pilings were set in place, and a slurry of gravel and water was poured around the pilings. The slurry freezes, holding the pilings in place similar to the effect that adding cement would have. When set, the top of the pilings are approximately 1.5 m (5 ft) above the ground. The foundation for the NW 100 consists of eight freezeback pilings set in an octagon compared to the AOC foundations which consist of three pilings that anchor the three legs of the lattice tower to the ground. For the NW 100, the piles were bolted to a steel weldment that comprises the tower bolt ring. An octagon-shaped steel plate was welded to the bottom of the steel weldment, creating the floor of the tower. The NW 100 foundation pilings were installed in March and April 2002 in conjunction with the foundations for the new AOC turbines. KEA also pre-assembled the tower sections at the site. NPS and NREL employees arrived in Kotzebue on April 23 to begin the tower and turbine erection. As specified in the NPS Commissioning Report, the general steps conducted during this procedure included: 5-2 Project Expansion Activities and Plans Installation Steps The tower cable bundle, lights, and ladder safety climb equipment were installed (and wired) while the tower was on the ground. The base controller was placed on the tower foundation floor. The tower was lifted over the base controller and placed onto the foundation. The tower was bolted to the foundation weldment. The nacelle was lifted into place atop the tower, and bolted to the tower. The nacelle roof panels were lifted and bolted in place on top of the nacelle. The blades were pitched and bolted to the hub on the ground. The hub and blades were lifted up to the nacelle and the hub was bolted to the rotor mainshaft brake disc. The dynamic brake resistor assembly was installed and wired. The tower cable bundle wiring was terminated at both ends. Commissioning Steps The installation wiring was checked for accuracy. The heaters were energized to warm up the electrical control systems. The electrical control systems were energized; the Programmable Logic Controller (PLC) was turned on. A communications link was established between the PLC and a local test laptop. The commissioning test plan was executed, which includes thorough testing of all turbine systems. A communications link was established between the PLC and a desktop PC located in the data shed using NPS’s RemoteView software.’ A communications link was established between the desktop PC and the outside world using a phone modem and PC Anywhere. The installation and commissioning went quite smoothly and were successful, but several problems occurred during the procedure. Some of the issues resolved by the installation crew included the following: Installation was delayed for approximately two days in April due to a snowstorm that impeded access to the site. A significant oil leak was discovered in the yaw drive gearbox. The source of the leak was a stripped drain plug on the bottom of the gearbox. The leak was successfully sealed with a metal epoxy seal around the plug. Several electrical connections were either incorrectly wired with respect to the schematic, or the schematic was incorrect. The circuits were rewired correctly and the schematics were updated as necessary. ” NPS’s RemoteView is an Excel-based user interface that provides a link to the NW 100’s Programmable Logic Controller. Shortly after the NW 100 was installed at KEA, NPS completed the development of a new Visual Basic- based user interface. KEA’s NW 100 has now been upgraded with this new interface program. 5-3 Project Expansion Activities and Plans e Several minor difficulties were experienced with the tower installation, including a section of the tower ladder that was installed upside down, tower sections that were bolted together without washers, small gaps between the foundation weldment and the tower base flange, and problems mounting the controller cabinet onto the tower floor. These problems were addressed and were noted by KEA and NPS as issues to avoid in future turbine installations. The turbine was fully operational and generating power when NPS staff left the project on May 17, 2002. Although minor difficulties were experienced with communications to the turbine due to poor phone connections to Kotzebue, the turbine has operated well since commissioning. Figures 5-2 through 5-8 show various steps in the installation process. In October 2002, NPS personnel returned to Kotzebue to perform scheduled maintenance on the NW 100. Table 5-1 lists the scheduled maintenance activities specified by NPS for annual turbine maintenance. Each of these tasks was performed during their site visit and the NW 100 was found to be in very good condition. In addition to the scheduled maintenance tasks, NPS replaced the defective yaw drive gearbox, installed redesigned brake pads, upgraded the RemoteView software, and installed a Starband™ system (a satellite-based internet access) to improve remote connectivity. NPS is confident that the NW 100 will perform well throughout the coming winter. Figure 5-1 Freezeback Piling Used for Turbine Foundation 5-4 Project Expansion Activities and Plans Table 5-1 NW 100 Maintenance Checklist Inspect lightning protection system Inspect mainshaft Clean generator fac screens Inspect bedplate Change hydraulic fluid as needed Torque check: Torque (Nm Blade / Hub 1 IBlade/Hub2 —_ Blade / Hub 2 Bedplate / Yaw Bearing Yaw Brake M30 Tower / Foundation Inspect nacelle Inspect electrical systems Notes / Comments: Technician / Engineer Date 5-5 Project Expansion Activities and Plans Figure 5-2 NW 100 Tower on Ground Figure 5-3 NW 100 Hub on Ground 5-6 Project Expansion Activities and Plans Figure 5-4 NW 100 Tower Being Lowered onto Foundation Figure 5-5 NW 100 Tower Being Positioned on Foundation Base Project Expansion Activities and Plans Figure 5-6 NW 100 Tower in Position on Foundation Base 5-8 Project Expansion Activities and Plans Figure 5-7 NW 100 Hub Being Raised into Position Project Expansion Activities and Plans Figure 5-8 NW 100 Hub Being Attached to Nacelle 5.3 Two Additional AOC 15/50s KEA is in the process of installing two additional AOC 15/50 turbines. The turbines were ordered in late 2000 and were originally intended for installation in the spring of 2001. These turbines have been designated as Turbines | 1 and 12 and are being installed at the southwest and southeast corners of the existing turbine array. The AOC turbine nacelles arrived in Kotzebue in November 2001. The pile foundations were installed in March and April 2002 in conjunction with the NW 100 foundation. Delivery of the towers, controllers, and blades was delayed for a variety of reasons. They have also not yet received two rotary transformers and the Enerpro softstart. Consequently, KEA was unable to complete the installation of Turbines 11 and 12 during the spring of 2002. During the summer, the tundra thaws and KEA is unable to place a crane at the site. KEA expects to complete the installation of the two AOCs in late winter or early spring 2003, depending on the weather. The new AOC turbines will be incorporated into the existing Second Wind SCADA system. The preliminary wiring and setup for connecting these turbines were completed in September 2002 when Second Wind was on site connecting the NW 100 turbine to the SCADA system. The additional AOC turbines will be included in the future TVP performance reporting. 5-10 Project Expansion Activities and Plans 5.4 Future Project Expansion KEA continues to work towards a long-term goal of 2 to 4 MW of wind generation capacity at Kotzebue, enough to meet the entire electrical needs of the community during peak demand. Currently Kotzebue uses about 20 million kWh of electricity and 5.7 million liters (1.5 million gallons) of diesel fuel each year. The next expansion is likely to include additional AOC 15/50 wind turbines. However, depending on turbine availability, other turbines may be considered for installation in Kotzebue. 5-11 6 OUTREACH ACTIVITIES AND FUTURE PLANS The primary objective of KEA’s wind energy program is to bring more affordable electricity and jobs to remote Alaska communities. During its third year of operation, KEA continued its community outreach, technology transfer, and wind project planning and development activities. 6.1 Community Education and Outreach Activities KEA continues to promote and participate actively in outreach activities within the local community and at the state and national level. In 2002, KEA received the National Community Service Award for their wind energy project from the National Rural Electric Cooperative Association (NRECA). KEA continued to work with local and state educational organizations in support of renewable energy programs. In the coming year, KEA will assist the Alaska Technical Center in Kotzebue in developing their Renewable Energy Program including the installation of a photovoltaic panel. KEA developed a resource booklet for middle and high school teachers to teach the concepts and principles of wind power. The resource booklet is a curriculum guide that gives students the opportunity to build their own wind machines. Students also learn about the history of wind power. The KEA website’ provides a variety of information, including an overview of KEA’s wind energy-related goals, some wind energy basics, and specific information about the AOC wind turbines. KEA provides some wind project statistics, such as energy produced and diesel fuel saved, and gives a summary of the expected benefits of their wind energy program. KEA provides site tours for interested groups within the constraints of KEA’s employee resources. Special efforts are made to accommodate local school groups, the news media, public policy officials, and utility and other technical groups with a specific need for information about the project. 6.2 Technology Transfer and Information Dissemination In addition to community education, KEA’s outreach includes technical information dissemination including project performance reporting through the TVP, participation in the Utility Wind Interest Group (UWIG) program, and presentations to local, regional and state * http://www. kotzelectric.com 6-1 Outreach Activities and Future Plans officials, and wind and utility industry groups. In 2000, 2001 and 2002, papers related to the KEA wind experience were presented at a number of industry events including the annual conference of the American Wind Energy Association, a meeting of the UWIG, and the annual TVP workshop. Throughout the past several years, the majority of KEA’s technical analysis and information dissemination has been performed as part of the TVP program. This includes monthly performance reporting that tracks the production, availability, and maintenance activities of the KEA wind project as well as routine interaction with the TVP support contractor and other utilities. The TVP provides statistics for all of the TVP projects, including KEA, in its quarterly TVP Bulletin. KEA continues to be actively involved with UWIG. Brad Reeve has served as UWIG President for the past four years. Participation in UWIG activities provides KEA with opportunities to interact on a regular basis with other utilities from around the country that are using or considering wind energy as part of their energy mix. Mr. Reeve continues to make presentations on the project experience at UWIG meetings and other utility and renewable energy conferences. As the President of UWIG, Mr. Reeve has been instrumental in planning the annual TVP Workshop, which is held in conjunction with the fall UWIG meeting. In 2001 the TVP/UWIG Workshop was held in Abilene, Texas, and included a tour of the new 150 MW Trent Mesa wind project. The 2002 workshop was held in Nebraska City, Nebraska. 6.3 Wind Project Planning and Development During the past year KEA continued to promote the integration of wind energy into the power systems of surrounding communities. KEA continued to provided project engineering for the Wales wind project, a high-penetration installation completed in the fall of 2000. Wales, a community of approximately 160 people, is the first community in Alaska powered almost exclusively by wind energy. KEA owns the turbines and sells the power to the Alaska Village Electric Cooperative (AVEC) who serves the electrical needs of the community. The two AOC 15/50 turbines are expected to provide the community with 100% of their electricity during a significant portion of the year. In order to accomplish this level of wind penetration on the grid, the power plant is instrumented with a state-of-the-art control system, developed by NREL, that allows the use of excess electricity produced during periods of high winds. During this past year many of the past issues have been resolved and the project has operated more reliably. The ongoing operation of the project continues to provide challenges related to the remote location and harsh climate. As intended, NREL now has minimal involvement in the operations and maintenance of the Wales project. An AVEC employee who lives in Wales is responsible for daily operation of the power plant including operation of the wind turbines. KEA travels to Wales to perform turbine maintenance and repairs as required. KEA expects to be involved with the development of a three- to four-turbine project in Selawik, which is located about 70 miles southeast of Kotzebue. Like Kotzebue, Selawik is an isolated community with no roads linking them to other parts of the state. The wind project is being developed by AVEC, who provides the electricity to the community and will use the AOC 15/50 turbine and the arctic pile foundations designed by KEA. Selawik, with approximately 660 6-2 Outreach Activities and Future Plans residents, is a larger community than Wales and consequently will be a low-penetration wind project requiring a significantly less sophisticated control system than Wales. 6-3 v4 CONCLUSIONS Through their involvement in the TVP, KEA has successfully developed, constructed, and is now operating a wind power plant in Kotzebue, Alaska. For the third year in a row the ten-turbine project performed well. KEA added the NW 100 turbine to their project and began the installation of two additional AOC 15/50 turbines. While the type and quantity of turbines has not been determined, KEA anticipates further expansion of their wind project to an eventual capacity of 2 to4 MW. During the third year of operation the project produced approximately 858.4 MWh of energy with an average TVP system availability of 94.5%. The generation was approximately 28% lower energy than the estimated long-term annual energy of 1,187 MWh primarily because the average wind speed was 5.8 m/s (12.9 mph), approximately 5% lower than the long-term average. During the second year of operation, the average wind speed at the site was 6.5 m/s (13.6 mph), approximately 7% higher than the long-term average. As evident over the three years of operation, the annual variation in wind speeds has a significant effect on the annual energy production. While the third year availability was 94.5%, slightly lower than long-term expected availability of 95%, the three-year average availability for the project is 95.7%. KEA is successfully meeting the challenges of operating a commercial wind project in the Arctic. The AOC 15/50 turbine is performing well in the cold, harsh environment and AOC has provided support to the project with configuration adjustments and appropriate component upgrades. Although, AOC is unlikely to provide any extensive support in the future due to the restructuring of the company, KEA personnel have become quite knowledgeable about the operation and maintenance of the AOC turbines. Through NREL, the TVP program continues to provide technical support to the KEA wind project. The success of the KEA Wind Power project has aided the continuing development of wind energy in Alaska, including the completion of the high-penetration wind project in Wales, Alaska, and the initiation of a three- to four-turbine project proposed for the community of Selawik. The KEA project has also been effective in achieving the TVP’s objectives of verifying the performance, reliability, maintainability, and cost of new wind turbine designs and system components in commercial utility environments. Consistent with TVP objectives, KEA is also providing other utilities and stakeholders with information about wind technology and the development and operation process from the perspective of utility owners and operators. With the incorporation of the larger North Wind 100-kW turbine and the installation of two additional AOC 15/50 turbines, the TVP expects to continue its support of the KEA project during 2003. The TVP plans to provide ongoing technical support as well as performance evaluation and reporting beyond the original three-year evaluation period. The unique 7-1 Conclusions environment of the KEA wind project is providing valuable lessons learned to wind industry stakeholders. The TVP is continuing to provide utilities and turbine manufacturers with valuable experience in wind power plant development, operation and maintenance, and technology transfer. The lessons learned through the TVP will be passed on to other projects in which EPRI and DOE have a management role and to the rest of the wind and utility industry through continuing outreach activities. A TVP-RELATED DOCUMENTS EPRI Reports Wind Turbine Verification Project Experience: 1999, EPRI 1000961, December 2000. Big Spring Wind Power Project Second- Year Operating Experience: 2000-2001, EPRI 1004042, December 2001. Big Spring Wind Power Project First Year Operating Experience: 1999-2000, EPRI 1000958, December 2000. Project Development Experience at the Big Spring Wind Power Project, EPRI TR-113919, December 1999. Iowa/Nebraska Distributed Wind Generation Projects First- and Second-Year Operating Experience: 1999-2001, EPRI 1004039, December 2001. Lessons Learned at the Iowa and Nebraska Public Power Wind Projects, EPRI 1000962, November 2000. Project Development Experience at the Iowa and Nebraska Distributed Wind Generation Projects, EPRI TR-112835, December 1999. Kotzebue Electric Association Wind Power Project Third- Year Operating Experience: 2001- 2002: U.S. Department of Energy-EPRI Wind Turbine, EPRI 1004206, December 2002. Kotzebue Wind Power Project Second- Year Operating Experience: 2000-2001, EPRI 1004040, December 2001. Kotzebue Wind Power Project First Year Operating Experience: 1998-2000, EPRI 1000957, December 2000. Project Development Experience at the Kotzebue Wind Power Project, EPRI TR-113918, December 1999. Tennessee Valley Authority’s Buffalo Mountain Wind Power Project Development, EPRI 1004207, December 2002. A-1 TVP-Related Documents Wisconsin Low Wind Speed Turbine Third-Year Operating Experience: 2000-2001, EPRI 1004041, December 2001. Wisconsin Low Wind Speed Turbine First and Second Year Operating Experience: 1998-2000, EPRI 1000959, December 2000. Wisconsin Low Wind Speed Turbine Project Development, EPRI TR-111438, December 1998. Green Mountain Power Wind Power Project Third Year Operating Experience: 1999-2000, EPRI 1000960, December 2000. Green Mountain Power Wind Power Project Second Year Operating Experience: 1998-1999, EPRI TR-113917, December 1999. Green Mountain Power Wind Power Project First Year Operating Experience: 1997-1998, EPRI TR-111437, December 1998. Green Mountain Power Wind Power Project Development, EPRI TR-109061, December 1997. Central & South West Wind Power Project Third Year Operating Experience: 1998-1999, EPRI TR-113916, December 1999. Central & South West Wind Power Project Second Year Operating Experience: 1997-1998, EPRI TR-111436, December 1998. Central & South West Wind Power Project First Year Operating Experience: 1996-1997, EPRI TR-109062, December 1997. Central and South West Wind Power Project Development, EPRI TR-107300, December 1996. DOE-EPRI Wind Turbine Verification Program TVP MI-112231 Status Report, 1998. Building Community Support for Local Renewables and Green-Pricing Projects EPRI TR- 114203, 1999. NREL/AWEA WindPower Published Papers Applicability of Nacelle Anemometer Measurements for Use in Turbine Power Performance Tests. G. Randall and T. McCoy, Global Energy Concepts, B. Smith and H. Link, National Renewable Energy Laboratory. Presented at WindPower 2002. Central & South West’s 1998 Operations and Maintenance Field Experiences. B. Givens, Central & South West Services. Presented at WindPower 1999. A-2 TVP-Related Documents Characterizing the Effects of High Wind Penetration on a Small Isolated Grid in Arctic Alaska. G. Randall, R. Vilhauer, Global Energy Concepts, LLC, C. Thompson, Thompson Engineering Company. Presented at Windpower 2001. Characterizing Wind Turbine System Response to Lightning Activity: Preliminary Results. McNiff, B.; LaWhite, N.; Muljadi, E. Collection of the 1998 ASME Wind Energy Symposium Technical Papers Presented at the 36" AIAA Aerospace Sciences Meeting and Exhibit, 12-15 January 1998, Reno, Nevada. New York: American Institute of Aeronautics and Astronautics, Inc.(AIAA) and American Society of Mechanical Engineers (ASME); pp. 147-156; NICH Report No. 25563. 1998. Comparison of Projections to Actual Performance in the DOE-EPRI Wind Turbine Verification Program. H. Rhoads, J. VandenBosche, T. McCoy, A. Compton, Global Energy Concepts, LLC, B. Smith, National Renewable Energy Laboratory. 14 pp.; NICH Report No. CP-500-28608. Presented at WindPower 2000. CSW Small Wind Farm Operating Experience ’96 — °98. W. Marshall, Central & South West Services, Inc. Presented at WindPower 1998. Development and Plans for the Kotzebue Wind Power Plant. B. Reeve, Kotzebue Electric Association, and E. Davis, Wind Energy Consulting & Services. Presented at WindPower 1998. Distribution Line Power Quality Experience with the Nebraska Distributed Wind Generation Project. M. Hasenkamp, Nebraska Public Power District. Presented at WindPower 2000. DOE-EPRI Distributed Wind Turbine Verification Program (TVP III). C. McGowin and E. DeMeo, Electric Power Research Institute, S. Calvert and P. Goldman, U.S. Department of Energy, B. Smith, S. Hock and R. Thresher, National Renewable Energy Laboratory. Presented at WindPower 1997. DOE-EPRI Wind Turbine Verification Program (TVP). C. McGowin, EPRI, T. Hall, U.S. Department of Energy and B. Smith, National Renewable Energy Laboratory. Presented at WindPower 1998. EPRI/DOE Wind Turbine Performance Verification Program. Calvert, S.; Goldman, P.; DeMeo, E.; McGowin, C.; Smith, B.; Tromly, K. 6 pp.; NICH Report No. CP-440-22486. Presented at Solar Energy Forum 1997. Evaluation of Wind Shear Patterns at Midwest Wind Energy Facilities. K. Smith, G. Randall, D. Malcolm, Global Energy Concepts, and N. Kelley, B. Smith, National Renewable Energy Laboratory. Presented at WindPower 2002. Evaluation of Lightning Protection Retrofit on the Z-750s in Springview, Nebraska. M. Hasenkamp, Nebraska Public Power District. Presented at Windpower 2001. Green Mountain Power’s 6-MW TVP Wind Project in Searsburg, Vermont. J. Zimmerman, Green Mountain Power Corporation. Presented at WindPower 1998. A-3 TVP-Related Documents Green Mountain Power’s Searsburg Project. B. Ralph, Green Mountain Power Corporation. Presented at WindPower 1999. Iowa TVP III Project. T. Wind, Cedar Falls Utilities. Presented at WindPower 1999. Lightning Activities in the DOE-EPRI Turbine Verification Program. T. McCoy, H. Rhoads, T. Lisman, Global Energy Concepts, LLC, B. McNiff, McNiff Light Industry, B. Smith, National Renewable Energy Laboratory. 14 pp.; NICH Report No. CP-500-28604. Presented at WindPower 2000. Nebraska TVP III Project. M. Hasenkamp, Nebraska Public Power District. Presented at WindPower 1999. Power Performance Testing Activities in the DOE-EPRI Turbine Verification Program. J. VandenBosche, T. McCoy, H. Rhoads, Global Energy Concepts, LLC, B. McNiff, McNiff Light Industry, B. Smith, National Renewable Energy Laboratory. 15 pp.; NICH Report No. CP-500- 28589. Presented at WindPower 2000. Power Performance Testing Progress in the DOE-EPRI Wind Turbine Verification Program. J. VandenBosche, G. Randall, T. McCoy, Global Energy Concepts, LLC. Presented at Windpower 2001. Power Quality of Distributed Wind Projects in the Turbine Verification Program. J. VandenBosche, T. Lettenmaier, Global Energy Concepts, LLC, T. Wind, Wind Utility Consulting, M. Hasenkamp, Nebraska Public Power District. Presented at Windpower 2001. Program on Lightning Risk and Wind Turbine Generator Protection. Muljadi, E.; McNiff, B. National Renewable Energy Laboratory 8 pp.; NICH Report No. CP-440-23159. 1997. Project Performance in the DOE-EPRI Wind Turbine Verification Program. J. VandenBosche, R. Vilhauer, G. Randall, Global Energy Concepts, LLC, B. Smith, J. Green, National Renewable Energy Laboratory, National Wind Technology Center. Presented at Windpower 2001. “Projects-at-a-Glance” Summaries of Projects Within the DOE-EPRI Wind Turbine Verification Program. K. Conover, S. Meyer, H. Rhoads, S. Simon, K. Smith, J. VandenBosche and R. Vilhauer, Global Energy Concepts, LLC. Presented at WindPower 2000. Review of Operation and Maintenance Experience in the DOE-EPRI Wind Turbine Verification Program. K. Conover, J. VandenBosche, H. Rhoads, Global Energy Concepts, LLS, B. Smith, National Renewable Energy Laboratory. 13 pp.; NICH Report No. CP-500-28620. Presented at WindPower 2000. TU/York Big Springs Project. L. Herrera, TU Electric. Presented at WindPower 1999. Wind Farm Generation Impact on a Small Municipal Utility System. T. Wind, Wind Utility Consulting. Presented at WindPower 2000. A-4 TVP-Related Documents Wisconsin Low Speed Wind Turbine Project Development Experience. J. VanCampenhout, Wisconsin Public Service Corporation. Presented at WindPower 1998. Other TVP Resources Joint Utility Wind Interest Group/Turbine Verification Program/Wind Powering America Technical Workshop. 2000. TVP News Bulletins. Global Energy Concepts. 1999-2001. A-5 B MONTHLY AVAILABILITY AND PRODUCTION BY TURBINE KEA Turbine Availability - July 2001 through June 2002 WT Ju August Sept Oct Nov Dec Jan Feb Mar Apr Ma Jun Average 1 83.3% 99.5% 98.9% 99.9% 99.0% 100.0% 99.2% 99.9% 100.0% 99.9% 100.0% 84.4% 97.0% 2 61.9% 99.9% 98.7% 99.6% 99.0% 100.0% 99.2% 99.9% 100.0% 99.9% 99.4% 97.3% 96.2% 3 25.6% 96.0% 99.7% 99.9% 99.0% 100.0% 96.3% 38.9% 29.1% 99.9% 100.0% 99.5% 82.0% 4 99.7% 85.4% 99.7% 99.9% 99.0% 96.4% 99.2% 99.9% 100.0% 94.8% 99.8% 895% 96.9% 5 99.8% 85.4% 99.7% 99.9% 99.0% 100.0% 99.2% 91.3% 88.3% 91.6% 75.8% 91.1% 93.4% 6 100.0% 85.5% 99.7% 99.9% 99.0% 100.0% 99.2% 99.9% 100.0% 77.2% 99.8% 99.0% 96.6% 7 85.1% 60.0% 99.4% 79.6% 94.8% 98.2% 99.2% 70.5% 73.2% 97.2% 99.8% 99.1% 88.0% 8 100.0% 85.5% 99.7% 99.9% 99.0% 100.0% 99.2% 99.9% 100.0% 98.8% 99.8% 99.2% 98.4% 9 100.0% 85.4% 99.7% 99.7% 99.0% 100.0% 99.2% 99.9% 99.7% 99.9% 95.9% 99.2% 98.1% 10 100.0% 85.5% 99.5% 99.9% 99.0% 100.0% 99.2% 99.9% 100.0% 98.8% 99.8% 99.2% 98.4% Project 85.6% 86.8% 99.5% 97.8% 986% 99.4% 98.9% 90.0% 89.0% 95.8% 97.0% 95.7% 94.5% KEA Energy Production - July 2001 through June 2002 WT July August Sept Oct Nov Dec Jan Feb Mar Apr May Jun Total 1 3,914 5,824 5.442 4,465 1,440 5,777 9,805 9,120 20,486 9,733 10,927 4,502 91,436 2,025 5,751 5,542 4,369 1,437 5,471 8998 8,386 18.424 9,724 9,550 5,485 85,161 178 6,094 5,145 4358 1,665 5,175 7,535 0 5,842 8225 9,563 6866 60,648 4,324 5,495 6,290 4,719 1,434 6,033 9,875 9,311 20,054 6916 10,855 5,611 90,918 4,303 5,141 5,841 4,136 1,562 6,094 10,542 5617 16,986 7,723 9,149 5,802 82,897 4,195 5,341 5,873 4,865 1880 6,115 10,366 9,954 19,744 7,066 10,976 7,462 93,837 4,030 2,256 5,879 4,471 2,062 6,142 11,544 2,638 11,027 10,249 11,135 7,107 78,541 3,746 4,970 5,844 4,470 1,289 5,926 8,800 7,561 17,143 8602 9,702 6,541 84,594 9 3,729 4,962 5,265 4,436 1,462 5,824 8697 7,163 21,644 10,412 9,799 7,284 90,678 10 3,945 5,723 6,082 5,053 2,172 6,340 11,507 9,343 21,603 9,726 10,507 7,705 99,708 Project 34,387 51,558 57,203 45,342 16,406 58,897 97,671 69,092 172,953 88,377 102,167 64,366 858,419 ONOnhWND B-1 C TVP AVAILABILITY DESCRIPTION There are a number of different ways to define and track availability for individual turbines and wind power plants. To ensure consistency among the projects involved in the program, the TVP developed a definition of availability to be used for reporting on performance statistics throughout the program. The TVP definition of availability takes into account all downtime experienced by the individual wind turbines in the project and divides the available hours by the total hours in the period. For each turbine, the TVP availability is: % Turbine Availability = {[H- (Downtime Hours for Turbine) ]/H} X 100% where H is the number of hours in the period and Downtime Hours for Turbine accounts for all downtime experienced by the turbine during the period of interest (i.e., week, month, year-to- date, or 8760 hours for an annual period). For a wind power plant, the TVP availability is: % Wind Power Plant Availability = {[(H X N)-(Sum of the Downtime Hours for N Turbines) ](H X N)} X 100% where H is the number of hours in the period and N is the number of turbines in the project. Although the above definitions use “hours” in the calculation, it is important to collect data that shows the turbine status (i.e., available or unavailable) on a time interval of 10 minutes or less so that fractions of an hour can be included in the availability calculation. The TVP availability includes downtime caused by different events including: e research activities; e testing; e delays in responding to faults; e public relations (i.e., site tours); e turbine maintenance and retrofit activities; C-1 TVP Availability Description e scheduled maintenance and routine inspections; e troubleshooting; e delays for parts or equipment; e line outages; and e force majeure events. There are several of other availability definitions that exclude some of these events. Although these approaches are intended to serve a specific purpose, the TVP uses the TVP Wind Power Plant Availability definition to ensure consistency among the projects. C-2 SPECIFIC DOWNTIME CAUSES BY TURBINE Turbine 1 Downtime: 265 hours Controller F Fauts ‘MiscFaults |i. outage 6% a 8% Other 45% Anem. O&M 39% Turbine 3 Downtime: 1,539 hours Electrical Line Outage oam 1% 25% Tip Brake O&M 74% Turbine 5 Downtime: 573 hours Controller Electrical Project Misc Faults Faults Expansion 2% 3% ™% 19% Line Outage 4% Electrical 08M 65% Turbine 2 Downtime: 328 hours Controller Fouts MISC Faults Line Outage ae 1% 7% Other 34% Misc O&M Tip Brake 3% am 50% Turbine 4 Downtime: 272 hours Controller Faults line Outage Electrical 5% Se O&M 15% Project Tip Brake Expansion O&M 59% 12% Turbine 6 Downtime: 304 hours Unknown O&M Line Outage Project 1% 8% Electrical O&M 55% D-1 Specific Downtime Causes by Turbine Turbine 7 Downtime: 1,041 hours Unknown Electrical Fyaite Controller Faults 50, = O8M Project 3% 10% Line Outage 2% | O&M 69% Electrical Faults 6% Line Outage 16% Project Expansion 78% Turbine 8 Downtime: 142 hours Turbine 9 Downtime: 165 hours Line Outage Electrical 14% O&M 17% Misc 2% Project | Expansion | 67% Turbine 10 Downtime: 143 hours Electrical Faults Misc O&M 6% 1% Expansion 77% Line Outage | 16% E NW 100 TURBINE DESCRIPTION Table of Contents 1.0 Introduction 1.1 Market 1.2 Design Philosophy 1.2.1 Rotor...... 1.2.2 Drivetrain . 1.2.3 Safety System.. 1.2.4 Serviceability... 1.2.5 Village Power Applicability . 1.3 Performance.. 1.4 Design Codes and Stan 2.0 Turbine Description......... 2.1 General Configuration 2.2 Subsystem and Component Descriptions .. 2.1.1 Rotor....... 2.1.2 Drivetrain .. 2.1.3 Bedplate.. 2.1.4 Yaw Assembly . 2.1.5 Nacelle Assembly 2.1.6 Tower 2.1.7 Foundation. 2.1.8 Electrical.... 2.3 Specifications and Turbine Data 3.0 Appendices .. Appendix 1: Performance Data . Appendix 2: Drawings.............+. Appendix 3: Configuration Document . Appendix 4: Masses and Centers of Gravity .. Appendix 5: Coordinate Systems SewVUUQUUARDUERERRYNVKKKNKKKN Northern Power Systems Turbine Description v.3.3.doc Page | of 9 NW 100 Turbine Description 1.0 Introduction 1.1 Market The NW100 is a 100kW turbine designed to be a highly reliable power system for the remote, cold weather village power market. The turbine is also intended to be a robust energy source for isolated research bases, such as on the Antarctic Continent. The turbine incorporates design features that make it especially suited to these applications. 1.2 Design Philosophy The NW100 turbine is designed with the following principles in mind to create a successful product: 1.2.1 Rotor The 3-bladed, rigid rotor is designed for safe, stall-regulated operation without the use of an aerodynamic braking system such as tip brakes or tip flaps. This fixed-pitch design minimizes moving parts which increases reliability. 1.2.2 Drivetrain The direct drive generator has inherent advantages for an extreme environment turbine. The elimination of the gearbox from the turbine design removes the component notorious for unreliable operation in wind turbines, especially at cold temperatures. 1.2.3 Safety System The NW100 uses a fail-safe mainshaft disc brake and an electrical dynamic brake to meet code requirements for two separate, independent braking systems. 1.2.4 Serviceability The NW100 is designed so that most service activities can occur without subjecting personnel to harsh environmental conditions while on the tower. The tubular tower allows internal climbing access to the tower top, and a full nacelle allows all routine service operations to occur in a protected space. 1.2.5 Village Power Applicability Village Power standalone grids are typically soft, and power quality and system stability can be compromised by the incorporation of conventional fixed speed turbines. The variable speed drive used in the NW100 design eliminates current in rush during control transitions and operation, and is designed to comply with IEE 519 power quality specifications. 1.3 Performance The turbine operates at variable speed, which allows the optimum rotor speed to be maintained during below-rated operation. This strategy optimizes energy capture. Power is limited to 100kW by fixing the rotor speed, which produces stall at higher wind speeds. The power curve for operation in standard atmosphere, is shown in Figure 1. er ai iti e rotor speed can be adjusted.to.maintain the 100kW _ rated.outp nd.optimum.en The power curve was calculated using modern aerodynamic theory. Eppler code predictions for the below-stall aerodynamic characteristics of the S819, S820, and S821 airfoil sections were blended with high angle of attack data to produce the aerodynamic input data. A detailed model of the electrical power train was used to derive the overall electrical efficiency. Energy capture for standard atmosphere, at a range of wind speeds, is shown in Figure 1. Data are shown in Appendix 1. Northern Power Systems Turbine Description v.3.3.doc Page 2 of 9 NW 100 Turbine Description = Electrical Power [kW] 0 5 10 15 20 25 Energy Production TTT | UT eer TT A err TT FEE : 6 7 8 : 1 Average Wind Speed [mps] 500 400 300 200 Energy [MWHrs] 100 Figure 1. Power Curve and Energy Capture, Standard Atmosphere Northern Power Systems Turbine Description v.3.3.doc Page 3 of 9 E-3 NW 100 Turbine Description 1.4 Design Codes and Standards The NW 100 was designed to WTGS Class I, under IEC 6-14001 Edition 2: e International Standard IEC 61400-1 Edition 2. Wind Turbine Generator Systems - Part 1: Safety Requirements. Geneva, Switzerland. 1998. This standard is an “umbrella” standard, which references many other codes for detailed aspects of the machine design. To augment the 1400-1 standard, the following standards and codes were applied: e Eurocode 3: Design of Steel Structures Partl.1: General Rules and Rules for Buildings. ENV-1993-1-1. English trans. European Committee for Standardization (CEN). ° VDI Society for Product Development, Design and Marketing. VDJ 2230: Systematic Calculation of High Duty Bolted Joints, Joints with One Cylindrical Bolt. Part 1. Verein Deeutscher Ingenieure. Dusseldorf, Germany. 1988. ° IEEES19: Recommended Practices and Requirements for Harmonic Control in Electric Power Systems. e ULSO8A: Outline of Investigation for Industrial Control Panels, Underwriters Laboratories Inc, 1993. e NEC1999: National Electric Code 1999, National Fire Protection Association, 1998. The following standard was used for reference purposes: ¢ Germanischer Lloyd. Rules and Regulations, Volume IV, Part 1, Regulation for the Certification of Wind Energy Conversion Systems. Ch. 1-10. Germanischer Lloyd. Hamburg. Germany. 1993. 2.0 Turbine Description 2.1 General Configuration The NW100 configuration and design is driven by the requirement for a fixed-pitch rotor, and the physical and electrical characteristics of the direct drive, low speed generator. The three bladed rigid rotor is bolted directly to the generator shaft. The generator input shaft and bearing assembly act as the turbine mainshaft system. The generator is in turn bolted onto a flange on the bedplate, and all turbine loads are transferred to the bedplate through this connection. The bedplate is mounted to the tower through a yaw slew bearing. An electric gear drive yaw system is utilized to actively orient the NW100 to the wind. A spring applied, hydraulically released caliper brake system is the primary emergency brake. An electrodynamic brake acts as a secondary braking system for normal shutdown and mechanical brake fault cases. A full nacelle and freestanding steel tubular tower allow access to the uptower equipment without exposing personnel to the severe environment of the target market sites. Figure 2 shows an assembly drawing of the tower top structure. The generator output is rectified and then inverted by a power converter system for connection to AC conventional or isolated village scale grid systems. The power converter is required because of the very low output frequency of the direct drive generator, and also allows for variable speed operation and stall point control of the turbine. The electrical one-line is shown in Appendix 2. The machine configuration is shown in Appendix 3. Northern Power Systems Turbine Description v.3.3.doc Page 4 of 9 E-4 NW 100 Turbine Description —— PT-B-0100 Rotor North Wind 100 Turbine Assembly PT-B-0000-D-0100 PT-B-0200 Drive Train PT-B-0300 Nacelle —_— PT-B-0400 Yaw System —— PT-B-0500 Tower Figure 2. NW100 Tower Top Assembly 2.2 Subsystem and Component Descriptions 2.1.1 Rotor Blades The NW100 turbine utilizes a blade manufactured by TPI Composites of Warren, RI, USA. The blade was developed specifically for the NW100, and is constructed using fiberglass reinforced vinylester. It incorporates the wind turbine specific S819, S820, S821 airfoil series. This series was developed to reduce sensitivity to roughness caused by dirt, bugs, and wear. The blade has an advanced root design which is suitable for low temperature operation, and integral lightning protection is provided. Northern Power Systems Turbine Description v.3.3.doc Page 5 of 9 E-5 NW 100 Turbine Description Hub The rotor hub is of Y-shaped design with integral shaft mounting flange. The material is A352-LCC cast steel. 2.1.2 Drivetrain Main Shaft Brake Assembly The NW100 uses a mainshaft braking system consisting of two spring applied, hydraulically released calipers for fail-safe operation, a 1.25m brake disk clamped between the hub and mainshaft flanges, and a hydraulic power pack and associated controls. The hydraulic power pack is supplied with a 200 watt heater, and is housed in an insulated enclosure to enhance low temperature performance. The hydraulic schematic as well as electrical connections are shown in Appendix 2. Generator Assembly The generator configuration is a 28 pole synchronous machine, with a salient pole wound rotor. Rotor The rotor poles are built up from 1.5mm low carbon cold rolled steel laminations. The rotor poles were stacked in a jig, then compressed and welded together. The poles are wound with 120 turns of 2.9mm X 7.34mm nominal conductor with quad build Class H insulation. The individual pole assemblies were dipped and baked using the VPI process. The rotor spider is a machined weldment, to which the 28 field pole assemblies are bolted. The rotor spider is attached to the generator mainshaft with a shrink disk device. The field poles are wired in a series connection, with alternating CW and CCW wound assemblies to create N and S poles. The field power leads are connected to a slipring assembly mounted on the mainshaft. Stator The stator is built up from 0.5mm thick, 60° arc lamination segments, using M-36 electrical grade silicon steel, with a C-5 coating system. The stator also incorporates quarter section fingerplates and full section stiffening rings on each side of the stack. The stator windings are form wound, with nine turns per coil of four 1.83mm X 5.18mm nominal conductor with quad build Class H insulation. The stator is insulated, wired, brazed, tested, dipped, and baked in the horizontal plane in a wiring/dipping jig to maintain the stator roundness and flatness criteria. The VPI process was used for the stator dipping step. Generator Frame The stator assembly is mounted in a welded generator housing, which consists of the structural stator frame and integral mounting pad for connection of the generator to the turbine bedplate. The generator housing also contains the bearing mounts for the generator mainshaft, which serves as the rotor mainshaft in this integrated design configuration. The generator housing and shaft assembly is designed to transfer all turbine loads to the turbine bedplate without affecting the generator operating clearances. Dual squirrel cage fan assemblies are mounted to the stator frame to provide active cooling of the generator. A rear generator cover shields the rear side of the generator, and provides mounting areas for the stator, field, and RTD junction boxes, air exhaust hood, and slipring access door. 2.1.3 Bedplate The NW100 bedplate is the main structural element of the towertop assembly, transmitting the rotor loads from the mainshaft and bearings to the tower. The bedplate is a A633 weldment consisting of an L-shaped rectangular tube to which the drivetrain assembly is bolted, and which is welded to a circular tube support frame that bolts directly to the yaw slew bearing. The weldment was stress relieved during manufacturing. The brake caliper mounts, rotor service lock and yaw drive mount are integral to the bedplate. Northern Power Systems Turbine Description v.3.3.doc Page 6 of 9 E-6 NW 100 Turbine Description 2.1.4 Yaw Assembly The NW100 uses an active yaw drive system to orient the turbine to the wind. It is comprised of a single planetary drive, pinion and integral slew ring/bull gear. A 2 hp gearmotor mounted to the turbine bedplate drives against the bull gear to yaw the turbine. A wind azimuth error sensor mounted on the nacelle provides the yaw command input. A proprietary friction system provides constant yaw friction to minimize low amplitude vibration of the nacelle. 2.1.5 Nacelle Assembly The NW 100 nacelle consists of a welded aluminum frame bolted directly to the bedplate. Aluminum panels comprise the walls, floor, and roof. A rear door and removable front and top panels make possible all service operations that cannot be carried out entirely within the nacelle. The nacelle is sized so that it can be shipped, assembled, in a standard ISO container. 2.1.6 Tower The standard NW 100 tower is a 23.4 m tapered tubular steel tower. Access is gained through a door located at the tower base. The turbine controller and power converter are located in the tower base for protection and ease of service. Access to the nacelle is accomplished by an internal ladder equipped with a fall restraint system. The foundation design for the NW 100 is site specific. Concrete pad or pile type foundations are dimensioned using design loads provided by NPS. .1.8 Electrical Turbine Controller The NW100 turbine controller manages all aspects of turbine operation, environmental control, safety, fault monitoring, and remote access. The turbine controller is PLC based, with a master controller located at the tower base, and a slave module located in the nacelle. Local operator access is via a touchscreen panel located on the base controller cabinet. Remote access is via modem to the remote PC operating NPS’s remote access and control software, RemoteView. The one line power diagram of the overall POC turbine electrical system is shown in Appendix 2. The input section of the power converter rectifies the 575Vac nominal output of the generator to an 825Vdc nominal DC bus. The power converter then synthesizes AC sine wave current and passes power to the utility grid. Varying the generator field excitation current, which causes the power converter to vary its output power in order to maintain an 825Vdc bus, sets the power output. The dynamic brake subsystem serves dual purposes; it applies load to the turbine for use as a braking system, and it functions as a generator voltage limiter during transient converter fault conditions, regulating the maximum dc bus voltage, protecting the power converter input circuitry from high voltage events. The main, or base, controller is housed in a freestanding IP65/NEMA 12 rated enclosure in the base of the turbine tower. The base enclosure houses the PLC CPU and base backplane, power circuits, field exciter, dynamic brake controls, and the variable speed power converter. The base controller monitors the power circuits and the power converter, issues field exciter and dynamic brake current commands, , and communicates with the upper controller, the local operator interface, and the remote operator interface. The slave, or nacelle controller is interfaced to the base controller, and is mounted in the turbine nacelle. The base controller communicates with the nacelle controller through a dedicated RS485 serial link, reducing the conductor count required in the tower cable system. The upper controller operates in slave mode to the base controller, monitors the towertop subsystems, generator temperature, and environmental conditions, and controls the mainshaft brake, yaw, and temperature control systems. Northern Power Systems Turbine Description v.3.3.doc Page 7 of 9 NW 100 Turbine Description The power converter is an open frame device that mounts in the base system controller enclosure. The power converter is interfaced to and receives operating commands from the overall turbine controller. The unit is designed to comply with IEEE 519, and uses air-cooled IGBT switching devices. The power converter input stage rectifies the generator output with a passive full bridge rectifier to create the internal 825V nominal DC bus. This DC bus is then inverted and injected into the grid through a passive filter and reactor in order to ensure low harmonic output. The exciter/dynamic brake control assembly is mounted in the base system turbine controller enclosure, and the dynamic brake resistive elements reside on a platform located above the foundation level. The exciter/dynamic brake control has two main operating modes. In the normal mode, the utility is present and the PLC active. The main controller CPU sends analog current commands to both the exciter and the dynamic brake circuit in response to system conditions. If either utility power is lost, the CPU drops out of “RUN” mode, or an electrical braking mode is selected, the exciter/dynamic brake control goes to preset duty cycles to modulate a controlled current level to both the field and the dynamic brake dump load bank. The net result is to provide a controlled deceleration of the turbine. Additionally, the dynamic brake control acts to limit turbine speed to a safe value in case of mechanical brake failure. The base controller provides a local user interface through a touch screen display that allows access to all turbine operating parameters. In addition, hard controls are provided for emergency stop and other critical user functions. The nacelle controller is equipped with hard switches to allow safe service mode access to the nacelle, as well as manual yaw and brake control. Transformer The POC is connected to the utility tie-in point typically through an 112.5kVA oil filled, pad-mounted transformer. The transformer typically is located adjacent to the tower base on a concrete pad. A power one line is shown in Appendix 3: Power Schematic. 2.3 Specifications and Turbine Data Detailed specifications for the turbine are presented in Appendix 3, while component masses are shown in Appendix 4. Coordinate systems used to describe component centers of gravity and in loads reporting are shown in Appendix 5. Northern Power Systems Turbine Description v.3.3.doc Page 8 of 9 E-8 NW 100 Turbine Description Appendices Appendix 1: Performance Data Appendix 2: Drawings Appendix 3: Configuration Documents Appendix 4: Masses and Centers of Gravity Appendix 5: Coordinate Systems Northern Power Systems Turbine Description v.3.3.doc Page 9 of 9 NW 100 Turbine Description Appendix 1: Performance Data E-10 NW 100 Turbine Description NW100 Power Curve Turbine: 19.1 m dia, -0.75 Pitch Power Curve: Power Curves 030801.xIs Enviromental Conditions: Standard atmosphere NW100 Power Curve 140 70.0 120 65.0 100 = > 60.0 & =< 80 os 5 55.0 5 60 a Ti 8 ms —Pmech 50.0 3 — Pelec 20 7 45.0 — Rotor Speed 0 40.0 0 5 10 15 20 25 V, mps Page 11 E-11 NW 100 Turbine Description NW100 Power Curve Turbine: 19.1 m dia, -0.75 Pitch Power Curve: Power Curves 030801.xIs Enviromental Conditions: Standard atmosphere Windspeed Rotor speed Rotor Power Grid power Elec. Eff. Losses included in efficiency mis RPM kw kW % 3 49.2 06 -1.5 0.0 Field and stator I*I*R losses 4 49.2 41 0.1 5.0 Field supply |GBT losses 5 50.3 97 5.7 58.0 Inverter IGBT losses 6 55.6 17.4 13.5 78.0 Rectifier diode losses 7 63.5 27.8 23.7 85.2 Hotel loads (I.e. heaters, fans, power supplies) 8 66.5 41.8 36.6 87.5 9 66.7 57.9 50.9 87.8 10 66.9 76.0 66.4 87.3 11 67.0 94.9 82.0 86.4 12 67.2 414 95.0 85.5 13 67.2 119.2 101.4 85.1 14 67.2 116.4 99.2 85.2 15 67.2 110.9 94.9 85.5 16 67.1 101.6 87.5 86.1 17 67.1 98.2 84.7 86.2 18 67.0 91.4 79.2 86.6 19 67.0 91.3 79.0 86.6 20 67.0 90.4 78.3 86.6 21 67.0 88.4 76.7 86.7 22 67.0 92.6 80.1 86.5 23 67.0 96.3 83.2 86.3 24 67.1 99.5 85.8 86.2 25 67.1 102.7 88.3 86 Page 12 E-12 NW 100 Turbine Description Annual Energy Calculation Turbine: 19.1 m dia, -0.75 Pitch Power Curve: Power Curves 030801.xis Enviromental Conditions: Standard atmosphere Vhub 7.5 mps Availability 99% Net Losses 0% Covered in calculation of Pe; transformer not included Time-on-Line 6935 Hours/Yr Energy 311,820 kWHrs/Yr ind Speed Distribution (Rayleigh) Energy Production (Annual Energy Production P(U<Vm) p(Vm) vm Run Time Wind Speed Annual Output Page 13 E-13 NW 100 Turbine Description Appendix 2: Drawings OMITTED E-14 NW 100 Turbine Description Appendix 3: Configuration Documents E-15 NW 100 Turbine Description ioe heret ‘w National Renewable Energy Laboratory Wind Turbine Certification Team Turbine Characteristics 1. Wind Turbine Identification Wind Turbine Name: North Wind 100/19 Overall Drawings: 01-00285-A (number, revision) 2. Applicant Identification Company: Northern Power Systems Address: 182 Mad River Park, Waitsfield, VT 05673 Contact Person: Garrett Bywaters , 802-496-2955 X231, gbywaters@northernpower.com (name, phone, email) 3. Instructions e Save completed form with the following name “DF04-yymmdd W7name” e Use one form per WT type subject to certification e — Fill out all white table cells e Send completed form via E-mail along with any enclosures you have in electronic form. ¢ Mail referenced enclosures not available in electronic form as soon as possible. Turbine Characteristics Description If S-class enclose description according to IEC 61400-1, Annex A Ice Loading (e.g. non, according to GL-Guidelines) L Possible, according to GL Guidelines Design Life (years) 30 General Configuration: Manufacturer, Model Northern Power Systems, North Wind 100/19 | Wind Turbine Overall Drawing: number, enclose 01-00285-A drawing Nacelle Overall Drawing: number, enclose drawing 01-00289-A Orientation (upwind / downwind) Upwind Rotor Diameter (m) 19.1 Hub Height (m) 25 Performance: Rated Electrical Power (kW) 100 Rated Wind Speed (m/s) 13 Cut-in Wind Speed (m/s) 4 Cut-out Wind Speed (m/s) 25 Extreme Wind Speed (m/s) 70 [e Power Curve (enclose table and graph) DFO2 990818 Turbine Characteristics DFO2 NW100-19 012902.doc Page 35 E-16 NW 100 Turbine Description Description Manufacturer, Model of Blades TPI Composites, NPS-0100 ] Length (m) 9.2 Material FRP First flapwise frequency (Hz) 3.66 @ 65 RPM First edgewise frequency (Hz) 5.66 @ 65 RPM Mass (kg) 186 Rotor: Number of Blades 3 | Swept Area (m’) 287 Synchronous Rotational Speed (rpm) NA Rated Rotational Speed (rpm) 68.5 Design Maximum Rotational Speed (rpm) 90 Rotor Hub Type (e.g. rigid, teeter) Rigid Coning Angle (deg) 0 Tilt Angle (deg) 4 Rated Blade Pitch Angle (deg) | -0.75 Direction of Rotation (clockwise or counter- Clockwise clockwise looking downwind) Rotor mass incl. Blades (kg) 785 Drive Train: Gearbox Manufacturer, Type, Ratio Direct drive Generator: Manufacturer, Type Cantarey, Salient Pole Synchronous Generator: Voltage 7 Frequency 575 VAC / 30, 15.7 Hz Generator: Synchronous, Rated and Max Speed NA, 69 RPM, 72 RPM | Braking System: Parking / Service Brake: Manufacturer, Type, Location Normal Shutdown Brake: Manufacturer, Type, Location Dellner; Spring-applied calipers (Qty 2), Mainshaft — Northern Power Systems, Dynamic brake, Generator field circuit Emergency Shutdown Brake: Manufacturer, Type, Location and Torque Time History Dellner; Spring-applied calipers (Qty 2), Mainshaft, 200 ms response time, 37 KNm max torque Yaw System: Wind Direction Sensor NRG Yaw Control Method (passive, active) Active Yaw Actuator (electrical, hydraulic) Electrical Yaw Brake: Manufacturer, Type, Location Northern Power Systems, Constant friction, Slew bearing face Control / Electrical System: Controller: Manufacturer, Type Northern Power Systems, PS 2000 WT100 Software: Release, Version Number Monitoring System: Manufacturer, Type 1.10 Northern Power Systems, Remote View WT Power Regulation (e.g. pitch, stall, active stall) see Variable speed stall Over speed Control (e.g. tip brake, pitch, mech. brake) Caliper brake, dynamic brake DFO02 990818 Turbine Characteristics DF02 NW100-19 012902.doc Page 36 E-17 NW 100 Turbine Description Generator Connection Wye, 3 wire to rectifier 575 VAC nom., 15.7 HZ Power Factor Compensation >0.99 PF at rated, converter output to grid. Generator Phase Connection (Delta/Wye) Wye Electrical Output: Voltage, Frequency, Number of Phases 480 VAC, 36, 50/60 Hz Grid Tolerances (voltage, frequency) +/- 10%V, +/- 0.5 Hz Tower: Tower Type (lattice, tubular steel, tubular concrete) Tubular steel Height (m) 23.4 First tower modal frequency (Hz) 1.45 Tower head mass (kg) 7166 Tower mass (kg) 7391 Environmental Specification: Temperature Range -46°C to 40°C (-50° F to 104° F) Humidity 100%, condensing Rain Severe Salt Water Coastal siting possible, no direct spray Icing Possible, according to GL Guidelines Wind Blown Particulate Periodic exposure to blowing dust and sand Lightning — Probable - adequate grounding required Seismic Loading DFO02 990818 Turbine Characteristics E-18 Zone 4 DFO2 NW 100-19 012902.doc Page 37 NW 100 Turbine Description Appendix 4: Masses and Centers of Gravity OMITTED E-19 Target: Renewable Technology Options & Green Power Marketing About EPRI EPRI creates science and technology solutions for the global energy and energy services industry. U.S. electric utilities established the Electric Power Research Institute in 1973 as a nonprofit research consortium for the benefit of utility members, their customers, and society. Now known simply as EPRI, the company provides a wide range of innovative products and services to more than 1000 energy- related organizations in 40 countries. EPRI’s multidisciplinary team of scientists and engineers draws on a worldwide network of technical and business expertise to help solve today’s toughest energy and environmental problems. EPRI. Electrify the World © 2002 Electric Power Research Institute (EPRI), Inc.All rights reserved. Electric Power Research Institute and EPRI are registered service marks of the Electric Power Research Institute, Inc. EPRI. ELECTRIFY THE WORLD is a service mark of the Electric Power Research Institute, Inc. @ Printed on recycled paper in the United States of America 1004206 EPRI * 3412 Hillview Avenue, Palo Alto, California 94304 * PO Box 10412, Palo Alto, California 94303 * USA 800.313.3774 + 650.855.2121 + askepri@epri.com * www.epri.com