crv-5 - gh power report-5!25!05

GARRADHASSAN

ASSESSMENT OF THE ENERGY PRODUCTION OF THE PROPOSED

SHEFFIELD WIND FARM

Client UPC Wind Management, LLC

Contact Tim Caffyn

Document No 4776/AR/01 Issue A Status FINAL Classification Client’s Discretion Date 25 May 2005

Author:

Ryan Adams

Checked by:

Adam Schwarz

Approved by:

Adam Schwarz

DISCLAIMER

Acceptance of this document by the client is on the basis that Garrad Hassan America are not in any way to be held responsible for the application or use made of the findings of the results from the analysis and that such responsibility remains with the client. GH has not conducted wind measurements itself and cannot, therefore, be responsible for the accuracy of the data supplied to it.

Key To Document Classification

Strictly Confidential : Recipients only

Private and Confidential : For disclosure to individuals directly concerned within the recipient’s organisation

Commercial in Confidence : Not to be disclosed outside the recipient’s organisation

GH only : Not to be disclosed to non GH staff

Client’s Discretion : Distribution at the discretion of the client subject to contractual agreement

Published : Available to the general public

© 2005 Garrad Hassan America, Inc.

Garrad Hassan America Document: 4776/AR/01 Issue: A FINAL

Revision History

Issue Issue date Summary

A

25.05.05

Original Issue

Circulation: Copy No:

Client

GH Bristol

GH San Diego

1 & 2

3

4

Copy No:


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CONTENTS

Page

1 INTRODUCTION 1

2 DESCRIPTION OF THE SITE AND MONITORING EQUIPMENT 2 2.1 The site 2 2.2 Monitoring equipment 2

3 SELECTION OF A REFERENCE METEOROLOGICAL STATION 5

4 WIND DATA 6 4.1 Wind data recorded at the site 6 4.2 Wind data recorded at the reference station 7

5 DESCRIPTION OF THE PROPOSED WIND FARM 8 5.1 The wind turbine 8 5.2 Wind farm layout 8

6 RESULTS OF THE ANALYSIS 10 6.1 Long-term mean wind regime at Burke Mountain reference station at 23 m 10 6.2 Long-term mean wind regime at the site masts 11 6.3 Hub height wind speeds 12 6.4 Site wind speed variations 13 6.5 Projected energy production 14 6.6 Uncertainty analysis 16 6.7 Seasonal and diurnal variations 18

7 CONCLUSIONS AND RECOMMENDATIONS 19 REFERENCES LIST OF TABLES LIST OF FIGURES APPENDIX 1 Data analysis procedure


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1 INTRODUCTION UPC Wind Management (UPC) is developing the Sheffield Wind Farm in Vermont. UPC have instructed Garrad Hassan America (GH) to carry out an independent assessment of the wind climate and expected energy production of the proposed wind farm. The results of the work are reported here. A description of the long-term wind climate at a potential wind farm is best determined using wind data recorded at the site. UPC has supplied two years and five months of data recorded at the Sheffield site to GH. When only a short period of site data are available, it is usual to combine the site measurements with long-term measurements from a local meteorological station. UPC has supplied extensive data from the Burke Mountain reference meteorological station. The layouts considered were prepared by GH while power curves for the turbine models currently under consideration have been provided by UPC. These have been analysed here, in conjunction with the results of the wind analysis, to predict the long-term energy output of the proposed wind farm.


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2 DESCRIPTION OF THE SITE AND MONITORING EQUIPMENT

2.1 The site The site is located approximately 90 km east northeast of Burlington, Vermont, as shown in Figure 2.1. Also shown in this figure is the location of the Burke Mountain Meteorological Station which has been considered as a source of long-term wind data in the assessment of the site wind regime. The proposed wind farm lies on several hills and ridges within the site boundary. The northern portion of the proposed wind farm lies on a broad hill of elevation between 650 m and 770 m above sea level which runs west-southwest to north-northeast while the southern portion of the proposed wind farm lies on two ridge-like features of elevation between 640 m and 680 m above sea level which run primarily south-southeast to north-northwest. The site is situated within an area of mountainous terrain comprising a variety of deciduous and coniferous trees reaching heights of approximately 10 m. The general terrain at the site and surrounding area can be described as complex with an abundance of steep undulating hills throughout. A more detailed map showing the site boundary is presented in Figure 2.2, which also shows the location of the anemometry masts. A view of the ridges located within the south-western portion of the site is presented in Figure 2.3 as seen from the valley floor in the center of the site facing southwest. The surface roughness length of the site and surrounding area was assessed during a site visit made by GH staff in March 2005. Following the Davenport classification [2.1], the following general figures are considered appropriate:

Dense wooded areas 0.5 m

Open wooded areas 0.4 m

Settlements 0.5 m

Farm land 0.1 m

Water 0.0002 m

2.2 Monitoring equipment Details of the measurements recorded on site and the grid co-ordinates of each mast are presented in Table 2.1. The wind data have been recorded using NRG systems throughout with Maximum 40 anemometers and 200 P wind vanes. The site measurement campaign began in November 2002 and consisted of a single tower, Mast 5211, with a SecondWind Nomad data logger programmed to record hourly mean wind speed and direction and wind speed average deviation. In June 2004 and September 2004 two additional towers were installed on site, Masts 4716 and 5210, with NRG Symphonie data loggers programmed to record ten minute mean, standard deviation, maximum and minimum wind speed


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and direction. In September 2004 the SecondWind Nomad data logger at Mast 5211 was replaced with an NRG Symphonie data logger recording the same measurements as the original installation. The following transfer function was applied to the output signal from the anemometers by these data loggers:

Recorded wind speed [mph] = 1.711 x Data frequency [Hz] + 0.78 mph The anemometers on the site have not been individually calibrated. An investigation of the calibration of 472 NRG Maximum 40 anemometers has been reported in [2.2], the results of which include a proposed consensus transfer function for this model of anemometer. Since the applied transfer function is equivalent to the consensus calibration, no adjustment of the mean wind speed was necessary other than the conversion to SI units. Maintenance records for the site measurements have been provided. The standard of documentation is good and considered sufficient to ensure full traceability of the instrumentation. Mast 5211 consists of a SecondWind WindMast 40 m, 6 inch diameter, tilt-up tubular tower. Instruments mounted on Mast 5211 include a top-mounted anemometer at 40 m and two boom-mounted anemometers at 32 m and 23 m with wind vanes at 40 m and 32 m. The stub-mounted anemometer is mounted approximately 3 mast diameters vertically above the top of the mast while all boom-mounted anemometers are mounted on booms approximately 7 mast diameters long oriented west. The cups of the boom-mounted anemometers are approximately 12 boom diameters above the booms. The wind vanes are mounted on the vertical extension of the upper two anemometers with a horizontal separation from the anemometer of approximately 12 inches. Though these wind vanes are oriented into the non-prevailing wind direction of north, due to the proximity to the wind vanes, these mounting arrangements, as well as the top-mounted anemometer, are considered inconsistent with IEA recommendations [2.3]. Field studies reported in [2.4] as well as GH’s own CFD investigations, indicate that top-mounted anemometers that are in close proximity to the mast top are likely to be in a region of accelerated flow compared to free stream. While the studies indicate that the extent of wind speed modification is highly sensitive to the exact geometry of the configuration, it is generally expected that the effect on the measured wind speeds will be an upward bias of approximately 3 %. It is noted, however, that measurements from Mast 5211 at 32 m height only have been retained for the assessment. The use of these data is discussed further in Section 6. Mast 5210 consists of an NRG 50 m HD, 8 inch diameter, tilt-up tubular tower. Instruments mounted on Mast 5210 include two boom-mounted anemometers at 48 m and one boom-mounted anemometer at 39 m and 30 m with wind vanes at 48 m and 39 m. All boom-mounted anemometers are mounted on booms approximately 7 mast diameters long oriented west with the redundant 48 m anemometer oriented south. The cups of the boom-mounted anemometers are approximately 12 boom diameters above the boom. These mounting arrangements are broadly consistent with the recommendations of the IEA [2.3]. Mast 4716 consists of an NRG 50 m HD, 8 inch diameter, tilt-up tubular tower. Instruments mounted on Mast 4716 include two boom-mounted anemometers at 48 m and one boom-mounted anemometer at 40 m and 30 m with wind vanes at 48 m and 40 m. All boom-mounted anemometers are mounted on booms approximately 7 mast diameters long oriented north. Both 48 m anemometers are mounted on the same boom with a horizontal separation of approximately


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0.6 m. The cups of the boom-mounted anemometers are approximately 12 boom diameters above the boom. The wind vanes are mounted on the vertical extension of the anemometers at 48 m and 40 m with a horizontal separation from the anemometer of approximately 12 inches. Given the mounting arrangements and proximity to the wind vanes and additional anemometer at 48 m, these mounting arrangements are not consistent with the recommendations of the IEA [2.3].


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3 SELECTION OF A REFERENCE METEOROLOGICAL STATION In the assessment of the wind regime at a potential wind farm site it is generally necessary to correlate data recorded on the site with data recorded from a nearby long-term reference meteorological station. Wind data at a site are often only recorded for a short period and such correlation is required to ensure that the estimates of the wind speeds at the site are representative of the long-term. When selecting an appropriate meteorological station for this purpose it is important that it should have good exposure and that data are consistent over the measurement period being considered. A meteorological station located at Burke Mountain Ski Resort has been identified by UPC as a potential reference station and wind data have been supplied to GH for the period from December 1997 to February 2005. This station is situated some 15 km east-southeast of the site, as illustrated in Figure 2.1. Table 2.1 provides a description of measurements made at the Burke Mountain Meteorological Station. The meteorological station was visited by GH staff in March 2005. Presented in Figure 3.1 is a view of the tower from the west. The station is installed on an existing radio tower with a square section and consistent face width of approximately 2.5 m. The top of the tower extends to approximately 35 m height and has several antennae and instruments mounted on the tower. The wind speed sensors are mounted at approximately 23 m height on a horizontal boom approximately 2 m in length installed on the northwest corner of the tower and oriented west, providing good exposure to the predominant winds from the south through northwest. The station currently comprises one NRG IceFree2 anemometer, one NRG Max40 anemometer and one NRG IceFree2 wind vane.. It is noted that given extremely poor data coverage due to several instrument malfunctions and long periods of icing, the NRG Max40 anemometer has been excluded from the assessment. The station appears to be well maintained with reasonable data coverage for the NRG IceFree2 anemometer. The IceFree2 wind vane was not recording measurements for a substantial period of time the reasons for which are unknown. Structures which could affect the exposure of the measurement mast include several additional radio towers to the north and east; however, given the distance between the measurements and these additional towers as well as the towers being located within non-prevailing direction sectors they are not considered to significantly affect the measurements. Review of the site commissioning form indicates that the measurements have maintained consistency through the measurement period. While the IceFree2 anemometer does not meet industry best practice standards for resource assessment, as a source of reference data for the assessment consistency and not absolute accuracy is required. The analysis of the long-term wind regime therefore relies on data recorded at the Burke Mountain Ski Resort since December 1997. The uncertainty associated with assuming this period to be representative of the long-term is considered in Section 6.


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4 WIND DATA

4.1 Wind data recorded at the site The data sets which have been used in the analysis described in the following sections are summarised in Table 2.1. The wind data have been subject to a quality checking procedure by GH to identify records which were affected by equipment malfunction and other anomalies. The check of the site mast data revealed several hours where wind speed data were missing or suspect. These data were excluded from the analysis. The main periods for which valid data were not available are summarised below, together with details of the errors identified: Mast 4716

• Periods of icing: 7 December 2004 to 24 December 2004, 2 January 2005 to 11 January 2005, 14 January 2005 to 19 January 2005, 21 February 2005 to 27 February 2005 and 8 March 2005 to 14 March 2005.

Mast 5210

• Periods of icing: 7 December 2004 to 19 December 2004, 4 January 2005 to 7 January 2005 and 21 February 2005 to 25 February 2005;

• 48 m west anemometer malfunction: 19 October 2004 to 23 October 2004.

Mast 5211

• Periods of missing data: 19 March 2003 to 7 May 2003, 23 January 2004 to 27 January 2004 and 3 December 2004 to 8 December 2004;

• Periods of icing: 14 December 2002 to 19 December 2002, 17 December 2003 to 22 December 2003, 27 November 2004 to 4 December 2004, 7 December 2004 to 22 December 2004 and 8 March 2005 to 12 March 2005;

• 40 m anemometer malfunction: 1 July 2003 to 11 May 2004. In an attempt to minimise mast effects in the measured wind speed data from Mast 5210 at 48 m, “selective averaging” of the data recorded by the two, south and west, boom-mounted anemometers at a given height was undertaken as follows: • For north and east direction sectors, wind speeds from the west oriented and south oriented

anemometers, respectively, were taken. • For the remaining direction sectors, wind speeds from both anemometers were averaged. In the case of Mast 4716 it is unclear which of the two 48 m anemometers corresponds with which logger input channel. Therefore an average of the two concurrent wind speed measurements was employed within the analysis. The duration, basic statistics and data coverage for Masts 4716, 5210 and 5211 are summarised in Tables 4.1 to 4.3, respectively.


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4.2 Wind data recorded at the reference station The data sets which have been used in the analysis described in the following sections are summarised in Table 2.1. The wind data have been subject to a quality checking procedure by GH to identify records which were affected by equipment malfunction and other anomalies. The check of the Burke Mountain reference station data revealed several hours where wind speed data were missing or suspect. These data were excluded from the analysis. The main periods for which valid data were not available are summarised below, together with details of the errors identified: Periods of missing data: 19 December 1998 to 30 December 1998

Wind vane malfunction: 21 September 1998 to 30 December 2002 and 1 February 2003 to 27 February 2003.

The duration, basic statistics and data coverage for the Burke Mountain reference station data are summarised in Table 4.4.


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5 DESCRIPTION OF THE PROPOSED WIND FARM

5.1 The wind turbine The turbines which are under consideration for the Sheffield Wind Farm are the GE 1.5sle, GE 1.5xle and the Vestas V82. The basic parameters of the turbines are presented in Table 5.1. The power curves used in this analysis have been supplied by UPC [5.1] and are presented in Table 5.2. The GE 1.5sle and GE 1.5xle power curves are for an air density of 1.180 kg/m³ and a turbulence intensity of 10 % to 15 %. The V82 power curve is for an air density of 1.180 kg/m³ and a turbulence intensity of 11 % to 16 %. The supplied power curves are based on calculations and exhibit peak power coefficients, Cp, of 0.45, 0.44 and 0.46 for the GE 1.5sle, GE 1.5xle and V82, respectively. These values are considered to be reasonable for modern wind turbines. Using historical pressure and temperature records from nearby meteorological stations and standard lapse rate assumptions, GH has estimated the long-term mean air density at the site to be 1.171 kg/m³ at an average hub elevation of 759 m above sea level. The supplied power curve used in this analysis has been adjusted to the predicted site air density, in accordance with the recommendations of [5.2]. This has been undertaken on an individual turbine basis.

5.2 Wind farm layout GH has designed individual layouts for the GE 1.5sle, GE 1.5xle and the V82 at 80 m hub height. It was requested by UPC that GH undertake a review on the installed site capacity verse the estimated capacity factor with the concept of maximising the capacity factor while retaining a reasonable site installed capacity. This was undertaken based by the method detailed below. The only criterion provided with regard to the maximum installed capacity was that, due to the restrictions of the local transmission line, the maximum power output from the wind farm can not exceed 100 MW [5.3]. Based on the site boundary provided by UPC [5.4] GH undertook a review of the expected installed capacity for the site. It is noted that the site boundary encompasses a limited number of ridges and hill tops to which, based on wind flow modelling over the site as described in Section 6, the development has been restricted. Based on this review and conversations between GH and UPC [5.5] it was requested by UPC that GH provide individual layouts with options of 29 and 35 turbines for each of the three turbine models being considered. Maps of the site showing the wind turbine locations in each of the layouts are presented in Figures 5.1 to 5.6 with the grid reference of each of the turbines given in Tables 5.3 to 5.8. Since definitive exclusion zones were not provided by UPC, GH has assumed in the layout optimisation a pragmatic set-back from the site boundary and the transmission line of the turbine fall-over distance (turbine rotor radius plus the tower height).


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A minimum inter-turbine spacing of 4 rotor diameters (D) is proposed for all layouts. It is noted that turbines are proposed in the immediate vicinity of trees. It is recommended that the turbine manufacturer be approached at an early stage to gain approval for the location of the turbines in relation to the trees.


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6 RESULTS OF THE ANALYSIS The analysis of the wind farm involved several steps, which are summarised below: The wind speed and direction frequency distribution at the Burke Mountain reference station

at 23 m height was derived for the period from December 1997 to February 2005. The wind speed and direction frequency distribution at Mast 5211 at 32 m height was derived

for the period from November 2002 to April 2005. Data recorded at site Masts 4716 and 5210 were correlated to data recorded at Mast 5211.

These correlations were used to derive the annual wind speed and direction frequency distributions at Masts 4716 and 5210.

Data recorded at Burke Mountain reference station were correlated to data recorded at Masts

4716 and 5210. This correlation was used to derive the long-term mean wind speeds at Masts 4716 and 5210. The individual masts annual wind speed and direction frequency distributions were scaled to reflect these long-term mean wind speed predictions.

The measured shear was used to extrapolate the long-term mean wind speed and direction

frequency distributions at the site masts to the proposed hub height of 80 m. Wind flow modelling was carried out to determine the hub height wind speed variations over

the site relative to the anemometry masts. The energy production of the wind farm was calculated taking account of array losses,

topographic effects, availability, electrical transmission efficiency, air density effects and other potential losses.

An assessment of the uncertainty in the predicted wind farm energy production was

undertaken. A more complete description of the methods employed is included in Appendix 1.

6.1 Long-term mean wind regime at Burke Mountain reference station at 23 m As detailed in Section 4, wind measurements from the Burke Mountain reference station over a period of approximately 7.2 years were available for the analysis. From the 7.2 years of measurements a total of approximately 7.1 years of valid wind data were available. In order to avoid the introduction of bias into the annual mean wind speed estimate from seasonally uneven data coverage, the following procedure was followed:

The mean wind speed for each month was determined from the average of all valid data recorded in that month over the period. This was taken as the monthly mean thereby assuming that the valid data are representative of any missing data.

The mean of the monthly means was taken to determine the annual mean (“mean of means”) to eliminate the effect of seasonal bias in the data.


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By this method, as shown in Table 6.1, the predicted long-term mean wind speed at Burke Mountain was found to be 8.4 m/s. It is observed that the wind rose at the Burke Mountain reference station has a predominance of winds from the south and northwest, with a significant proportion from the remaining westerly sectors.

6.2 Long-term mean wind regime at the site masts The long-term mean wind speeds derived at the site masts involved several steps which are detailed below. With approximately 2.4 years of measurements available from Mast 5211, this mast currently provides the longest period of record at the Sheffield site. As detailed in Section 4, there was a significant period where the 40 m anemometer malfunctioned and therefore the 32 m anemometer provides the longest period of site measurements. From the 2.4 years of measurements a total of approximately 2.1 years of valid data were available from the 32 m anemometer. In order to avoid the introduction of bias into the annual mean wind speed and direction frequency distribution estimate from seasonally uneven data coverage, the following procedure was followed:

The mean wind speed and direction frequency distribution for each month was determined from the average of all valid data recorded in that month over the period. This was taken as the monthly mean thereby assuming that the valid data are representative of any missing data.

The mean of the monthly means was taken to determine the annual mean (“mean of means”) to eliminate the effect of seasonal bias in the data.

By this method, as shown in Table 6.2, the predicted long-term eman wind speed at Mast 5211 at 32 m was found to be 4.5 m/s. The corresponding long-term joint wind speed and direction frequency distribution is presented in Table 6.3 and in Figure 6.1 in the form of a wind rose. Given the relatively low, 40 m height of Mast 5211, the potential measurement bias associated with the stub-mounted 40 m anemometer and the proximity of Mast 5210, use of Mast 5211 is limited to the use of the period of 32 m data as the on site reference in establishing the site wind speed and direction frequency distribution. The measure-correlate-predict approach (MCP), which is described in Appendix 1, was used to predict the wind speed and direction frequency distributions at Masts 5210 and 4716 at 48 m. The measured wind speeds at Mast 5210 at a height of 48 m in each of the twelve 30 degree direction sectors are compared to the concurrent wind speeds measured at Mast 5211 at 32 m in Figure 6.2. The correlation of wind speeds is good within most sectors, with minimal levels of scatter for the most frequent direction sectors. It is noted that there is significant scatter as well as a large speed up between the two masts for the 120 and 150 degree direction sectors. This is due to the location of Mast 5211 not being very well exposed to the southeast, yet due to the minimal amount of winds within these sectors this is not considered to be an issue. As a check of the validity of the MCP methodology, synthesised data were compared with concurrent periods of measured data and were noted to be in close agreement. Figure 6.3 presents the correlation of wind direction between the two masts. The data are observed to be well correlated, albeit with


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some non-linearity which has been corrected for in the prediction of wind direction frequency distribution at the target mast. The measured wind speeds at Mast 4716 at a height of 48 m in each of the twelve 30 degree direction sectors are compared to the concurrent wind speeds measured at Mast 5211 at 32 m in Figure 6.4. The correlation of wind speeds is reasonable within most sectors, with quite significant levels of scatter for the most frequent direction sectors. As noted within the correlation between Masts 5210 and 5211, there is significant scatter as well as a large speed up between the two masts for the 120 and 150 degree direction sectors. This is due to the location of Mast 5211 not being very well exposed to the southeast, yet due to the minimal amount of winds within these sectors this is not considered to be an issue. As a check of the validity of the MCP methodology, synthesised data were compared with concurrent periods of measured data and were noted to be in close agreement. Figure 6.5 presents the correlation of wind direction between the two masts. The data are observed to be well correlated, albeit with some non-linearity which has been corrected for in the prediction of wind direction frequency distribution at the target mast. By this method, the annual mean wind speeds based upon the 2.1 year period of site data from Mast 5211 were found to be 6.0 m/s and 7.2 m/s at Masts 5210 and 4716 at 48 m, respectively. In order to reference the 2.1 years to the longer term, correlation analyses between Masts 4716 and 5211 and the Burke Mountain reference station were undertaken. Due to the observed differences in hourly wind speed frequency distributions between the site and Burke Mountain, the non-directional correlation of daily mean wind speeds was employed. The linear-regression fit to the daily correlation to Masts 4716 and 5210 at 48 m returned correlation coefficients (r2) of 0.83 and 0.77, respectively. The correlation of daily mean wind speed at Burke Mountain and Masts 4716 and 5210 are presented in Figures 6.4 and 6.5. By this method the long-term mean wind speeds at Masts 4716 and 5210 at 48 m were predicted to be 7.1 m/s and 5.9 m/s, respectively. The site predicted wind speed and direction frequency distribution derived above were then factored to reflect this predicted mean wind speed. The corresponding long-term joint wind speed and direction frequency distributions at Mast s 4716 and 5210 at 48 m are presented in Tables 6.4 and 6.5 and in Figures 6.6 and 6.7, respectively. It is observed that the wind rose at Mast 4716 at 48 m has a predominance of winds from the northwest, with a significant proportion from the south. The wind rose at Mast 5210 at 48 m has a predominance of winds from the west and west-northwest, with a significant proportion from the south and south-southeast. The differences in the shapes of the wind roses are due to local topographical effects, as reflected within the non-linearity within the directional correlations to Mast 5211. It is noted that the Mast 4716 wind rose is very similar to that observed at the Burke Mountain reference station due to the similar exposure at each location.

6.3 Hub height wind speeds As noted in Section 2.1, there is significant forestry throughout the site which is located within the immediate vicinity of the existing mast locations and proposed turbine locations. The wind flow modelling therefore needs careful consideration. Where there are obstacles to the wind flow, such as buildings or trees in the vicinity of a wind turbine, it is necessary to include the effect of the obstacles in the wind flow modelling [6.1]. According to the guidance in [6.1],


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the forestry at this site should, in several areas, be treated as an obstacle rather than simply a surface roughness element. The trees located within the areas of dense forestry are estimated to be approximately 8 m high on average and are assumed to affect a displacement height of 8 m for the purposes of the wind flow model. The following methodology has been applied to attempt to account for the effect of the forestry on the measured wind speeds. Due to the complexity of the ground cover at this site, a detailed review has been undertaken in order to apply individual displacement heights where appropriate at each site mast and proposed turbine location. This has been undertaken by assessing the distance from each mast and turbine to the nearest forestry clearing at each turbine base. The displacement heights were calculated as follows:

Displacement height [m] = Tree height [m] – Distance to forest [m] / 50 By this method, displacement heights of 7 m and 7 m at the locations of Masts 4716 and 5210 were estimated. The measured wind speed data between each mast’s anemometers at the upper two measurement heights were used to derive the boundary layer power law exponents at each site mast inclusive of the estimated displacement height. These values were used to predict the 80 m long-term mean wind speed at each mast. At Mast 4716 the 48 m wind speed measurements were correlated to the 40 m measurements to derive the predicted shear exponent. Given the north orientation of the anemometers for the predominant southerly winds there appears to be a significant difference to exposure between the two heights. This results in significant uncertainty and an unreliable shear prediction for the southerly winds. By accounting for this effect by interpolating between adjacent sectors, the shear exponent is predicted to be 0.25, resulting in an 80 m predicted long-term mean wind speed of 8.2 m/s. At Mast 5210 the 48 m westerly oriented anemometer was correlated to the 40 m anemometer to derive the predicted shear exponent. Due to the minimal proportion of winds from the east the differing configuration of the instruments is not expected to significantly bias the predicted shear exponent. The predicted vertical shear exponent at Mast 5210 is 0.19, resulting in an 80 m predicted long-term mean wind speed at Mast 5210 of 6.6 m/s.

6.4 Site wind speed variations The variation in wind speed over the wind farm site has been predicted using the WAsP computational flow model as described in Appendix 1. The wind flow model has been initiated from the long-term mean wind speed and direction frequency distributions derived for Masts 4716 and 5210 at 80 m height. Table 6.6 includes a comparison of predicted long-term mean wind speeds at the site masts using the MCP methodology and using WAsP initiated from the nearest mast location. These results indicate that there are significant differences within the projected wind speeds when using WAsP to extrapolate across the site as compared to the predicted long-term mean winds speeds. This is primarily due to the complexity of the topography as well as the influence of the forestry throughout the site.


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It is clear from the above that the prediction of the variation in wind speed over the site is challenging and an additional allowance has been made for the uncertainty in the wind flow modelling, as detailed in Section 6.6. In complex terrain, GH generally recommends that all proposed turbine locations are within 1 km of a measurement mast which is at least two thirds of the proposed turbine hub height. These conditions are not met at this site, and there is therefore additional uncertainty in predicting the variation in wind flow using the WAsP computational flow model. It is recommended that additional measurements of at least 60 m height are conducted at the site to bring these uncertainties to within an acceptable level, in particular within the south-western and north-western areas of the site. To facilitate the construction and operation of the wind farm, a forestry clearing of 250 ft radius at each turbine location has been assumed here, giving a maximum turbine displacement height of approximately 6 m. Tables 5.3 to 5.8 show the predicted long-term mean wind speeds at each turbine location at hub height for each of the six layouts. The average long-term mean hub height wind speed for the wind farm as a whole was found to be 7.3 m/s for the 29 x GE 1.5sle layout, 7.2 m/s for the 35 x GE 1.5sle, 29 x GE 1.5xle and 29 x V82 layouts, and 7.1 m/s for the 35 x GE 1.5xle and 35 x V82 layouts. The individual turbine predictions have been assessed by extrapolating from the nearest mast, resulting in Mast 4716 extrapolating to all turbine locations within the northern portion of the site and Mast 5210 extrapolating to all turbine locations within the southern portion of the site. It is noted that the predicted wind speeds in the southern portion of the site are much lower than that predicted in the north. While there are significant differences in wind speed predictions there is not sufficient evidence to correct for these differences at this time. Should additional measurements be undertaken within these areas it is recommended that the variation of wind speeds be reviewed at that time.

6.5 Projected energy production The energy production of the wind farm for each individual layout is detailed in the tables below and definitions of the various loss factors are included in Appendix 1. The energy capture of individual turbines is given in Tables 5.3 to 5.8.


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GE 1.5sle 29 x 35 x

Rated Power 43.5 52.5 MW

Ideal output 161.6 194.8 GWh/annum Topographic effect 89.8% 88.3% GH calculated Wake effect 94.9% 93.5% GH calculated Electrical efficiency 97.0% 97.0% GH assumption Availability 97.0% 97.0% GH assumption Icing and blade degradation 97.0% 97.0% GH assumption Low temperature shutdown 99.0% 99.0% GH assumption High wind hysteresis 99.9% 99.9% GH calculated Substation maintenance 99.8% 99.8% Typical value Utility downtime 100.0% 100.0% Not considered by GH Power curve adjustment 100.0% 100.0% GH estimate Wind sector management 100.0% 100.0% Assumed not required Wake effect from other sites 100.0% 100.0% Not considered by GH

Net output 124.0 144.9 GWh/annum

Net capacity factor 32.5 % 31.5 % GE 1.5xle 29 x 35 x




Net capacity factor 34.7 % 33.3 %


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V82 29 x 35 x




Net capacity factor 32.3 % 31.0 % The values for topographic and array effect have been calculated using the methods described in Appendix 1. It has been assumed that there are no other operational wind farms in the vicinity of the development. The table above includes potential sources of energy loss that have been estimated, assumed or not considered. It is recommended that the client consider each of these losses and the possible effect they may have on the wind farm.

6.6 Uncertainty analysis The main sources of deviation from the central estimate have been quantified and are shown in Tables 6.7 to 6.18 for each of the individual layouts. The figures in each table for each individual layout option are added as independent errors giving the following uncertainties in net energy production for the wind farm. These represent the standard deviation of what is assumed to be a Gaussian process: Turbine option GE 1.5sle

Number of turbines 29 x 35 x

In any one year period 19.7 23.6 GWh/annum

In any ten year period 15.1 18.0 GWh/annum


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Turbine option GE 1.5xle



In any ten year period 15.1 18.0 GWh/annum Turbine option V82



In any ten year period 16.0 19.1 GWh/annum The uncertainties that have been considered in the analysis of the Sheffield Wind Farm include the following: Accuracy of the wind measurements; Correlation accuracy; The assumption that the period of data available to is representative of the long-term wind

regime; The accuracy of the extrapolation of wind speeds from the mast height to hub height; The accuracy of the wind flow modelling; The accuracy of the wake modelling; The accuracy of the fiscal sub-station meter; The variability of the future annual wind speeds at the site.

There are a number of uncertainties that have not been considered at this stage, including those listed below. It is recommended that the client consider each of these uncertainties carefully. They can often be mitigated to some extent, especially in early years of the project, through appropriate warranty provisions. Therefore these uncertainties should be considered in combination with these provisions, for instance as part of a full technical due diligence exercise. Compliance with the assumed power curve; Turbine availability; Electrical losses; High wind hysteresis; Icing and blade degradation; Low temperature shutdown; Substation maintenance; Utility downtime.


18 of 25

6.7 Seasonal and diurnal variation A preliminary estimate of the expected long-term average seasonal and diurnal variation in energy production has been approximately assessed from the available measured and synthesised site measurements at Masts 4716 and 5210. In order to establish the seasonal and diurnal variations in expected energy production, a time-series of air density was derived from on site temperature and pressure records from data recorded nearby reference stations. These data were scaled to reflect the long-term site air density of 1.171 kg/m³. These data, together with expected wind speed variations, were used to model the expected variation in energy production on a seasonal and diurnal basis. Based on the modelled sensitivity of energy production to wind speed, the expected seasonal and diurnal variation in energy production is presented in Table 6.19 in the form of a 12 x 24 matrix. It is noted that the uncertainty associated with the prediction of any given month or hour of day is significantly greater than that associated with the prediction of the mean annual production as presented above. It is noted that these results presented are inclusive of the topographic effect and array losses only. Given the period of data and data coverage available on site, the above is considered preliminary. Depending upon the accuracy of the distribution of energy production required, it is recommended that this analysis be refined with additional reference data.


19 of 25

7 CONCLUSIONS AND RECOMMENDATIONS Wind data have been recorded at the Sheffield site for a period of approximately 2.4 years and at the Burke Mountain reference station for a period of 7.2 years. Based on the results from the analysis of these data the following conclusions are made concerning the site wind regime. 1. The long-term mean wind speed is estimated to be 8.2 m/s and 6.6 m/s at a height of 80 m

above ground level at the location of Masts 4716 and 5210, respectively. 2. The standard errors associated with these predictions of long-term mean winds speed are

0.5 m/s and 0.4 m/s for Masts 4716 and 5210. If a normal distribution is assumed, the confidence limits for the predictions are as given in the table below:

Probability of exceedance [%]

Long-term mean wind speed at 80 m hub height

[m/s] Mast 4716 Mast 5210

90 7.6 6.1 75 7.9 6.4 50 8.2 6.6

Standard error [m/s] 0.46 0.39

Site wind flow and array loss calculations have been carried out and from these we draw the following conclusions:

3. The average long-term mean hub height wind speed for the wind farm as a whole was found to

be 7.3 m/s for the 29 x GE 1.5sle layout, 7.2 m/s for the 35 x GE 1.5sle, 29 x GE 1.5xle and 29 x V82 layouts, and 7.1 m/s for the 35 x GE 1.5xle and 35 x V82 layouts.

4. The projected energy capture of the proposed wind farm is 124.0 GWh/annum and

144.9 GWh/annum for the GE 1.5sle 29 and 35 turbine layouts, respectively. The projected energy capture of the proposed wind farm is 132.2 GWh/annum and 153.4 GWh/annum for the GE 1.5xle 29 and 35 turbine layouts, respectively. The projected energy capture of the proposed wind farm is 135.5 GWh/annum and 156.8 GWh/annum for the V82 29 and 35 turbine layouts, respectively. This includes calculation of the topographical, array and air density effects and assumptions or estimates for electrical transmission losses, availability, power curve adjustment, high wind hysteresis, substation maintenance, and the effect of blade fouling or icing.

There are a number of other losses that could affect the net energy output of the wind farm, as

detailed in Appendix 1, but these have not been considered here. It is recommended that the client considers each of these losses and the possible effect they may have on the net energy production.

The net energy prediction presented above represents the long-term mean, 50 % exceedance

level, for the annual energy production of the wind farm. This value is the best estimate of the long-term mean value to be expected from the project. There is therefore a 50 % chance that,


20 of 25

even when taken over very long periods, the mean energy production will be less than the value given.

5. The standard error associated with the prediction of energy capture has been calculated for

each individual turbine layout and the confidence limits for the predictions are given in the tables below:

GE 1.5sle x 29

Probability of Net energy output Exceedance

[%] 1 year average [GWh/annum]

10 year average [GWh/annum]

90 98.7 104.6

75 110.7 113.8

50 124.0 124.0 GE 1.5sle x 35




90 114.7 121.8

75 129.0 132.8

50 144.9 144.9 GE 1.5xle x 29




90 107.1 112.8

75 119.0 122.0

50 132.2 132.2 GE 1.5xle x 35




90 123.3 130.3

75 137.6 141.2

50 153.4 153.4


21 of 25

V82 x 29




90 108.9 115.0

75 121.5 124.7

50 135.5 135.5 V82 x 35




90 125.0 132.4

75 140.1 144.0

50 156.8 156.8 There are a number of uncertainties that have not been considered at this stage, as detailed in Section 6. It is recommended that the client consider each of these uncertainties carefully. They can often be mitigated to some extent, especially in early years of the project, through appropriate warranty provisions. Therefore these uncertainties should be considered in combination with these provisions, for instance as part of a full technical due diligence exercise.

6. In order to reduce the uncertainty within the correlations to the Burke Mountain reference

station it is recommended that the analysis be updated one additional data become available, preferably once at least a full year of data have been recorded at Masts 5210 and 4716.

7. In order to reduce the uncertainty with the 48 m measurements and shear extrapolation at Mast

4716, it is recommended that Mast 4716 be instrumented with additional anemometers mounted on separate booms at 48 m oriented south and west, similar to the configuration at Mast 5210.

8. In order to reduce the vertical shear extrapolation and topographical modelling uncertainties, it

is recommended that additional measurements be undertaken at a minimum of 60 m height and that additional measurement be undertaken within the south-western and north-western portions of the site.


22 of 25

REFERENCES

2.1 “Wind speed profiles over terrain with roughness changes”, Engineering Sciences Data , Item No. 84011, April 1993.

2.2 Lockhart T J and Bailey B H, “The Maximum Type 40 Anemometer Calibration Project”, Proceedings of the AWEA Conference, California 1998.

2.3 Recommended Practices for Wind Turbine Testing and Evaluation, “11. Wind speed measurement and use of cup anemometry”, IEA, Edition 1, 1999.

2.4 Kline J, “Effects of Tubular Anemometer Towers on Wind Speed Measurements”, AWEA 2002

5.1 Email from Mohit Dua, UPC, to Ryan Adams, GH, on 13 April 2005.

5.2 “Wind turbine generator systems – Part 12: Wind turbine power performance testing”, BS EN 61400-12: BSI, 1998.

5.3 Email from Tim Caffyn, UPC, to Ryan Adams, GH, on 8 April 2005.

5.4 Email from Tim Caffyn, UPC, to Ryan Adams, GH, on 14 February 2005.

5.5 Conversations between Tim Caffyn and Mohit Dua, UPC, and Ryan Adams, GH, on 4 May 2005.

6.1 Cook N J “The Designer’s” guide to wind loading of building structures”., Part 1, Butterworths, 1985.


23 of 25

LIST OF TABLES

2.1 Summary of measurements made at the Sheffield site and Burke Mountain reference station

4.1 Measurements made at Mast 4716 at a height of 48 m



4.4 Measurements made at Burke Mountain reference station at a height of 23 m

5.1 Main parameters of the wind turbines analysed

5.2 Performance data for the wind turbines analysed

5.3 Turbine layout with predicted individual turbine wind speed and energy production – GE 1.5sle x 29

5.4 Turbine layout with predicted individual turbine wind speed and energy production – GE 1.5sle x 35

5.5 Turbine layout with predicted individual turbine wind speed and energy production – GE 1.5xle x 29

5.6 Turbine layout with predicted individual turbine wind speed and energy production – GE 1.5xle x 35

5.7 Turbine layout with predicted individual turbine wind speed and energy production – V82 x 29

5.8 Turbine layout with predicted individual turbine wind speed and energy production – V82 x 35

6.1 Measured monthly and annual mean wind speeds at Burke Mountain reference station at 23 m (1998 to 2005)

6.2 Measured monthly and annual mean wind speeds at Mast 5211 at 32 m (2002 to 2005)

6.3 Measured wind speed and direction frequency distribution at Mast 5211 at 32 m

6.4 Predicted long-term wind speed and direction frequency distribution at Mast 4716 at 48 m

6.5 Predicted long-term wind speed and direction frequency distribution at Mast 5210 at 48 m

6.6 Predictions of the wind speeds at the site masts from Mast 5210


24 of 25

LIST OF TABLES

6.7 Uncertainty in projected energy output of Turbines x to x based on Mast 4716 at 80 m – GE 1.5sle x 29




6.11 Uncertainty in projected energy output of Turbines x to x based on Mast 4716 at 80 m – GE 1.5xle x 29




6.15 Uncertainty in projected energy output of Turbines x to x based on Mast 4716 at 80 m – V82 x 29




6.19 Predicted seasonal and diurnal variation in energy production


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LIST OF FIGURES

2.1 Location of the wind farm

2.2 Map of the site

2.3 View of ridges located within the south-western extent of the site as seen from the valley floor facing southwest

3.1 View of the Burke Mountain reference station from the west

5.1 Layout of the proposed Sheffield Wind Farm - GE 1.5sle x 29 layout

5.2 Layout of the proposed Sheffield Wind Farm - GE 1.5sle x 35 layout

5.3 Layout of the proposed Sheffield Wind Farm - GE 1.5xle x 29 layout

5.4 Layout of the proposed Sheffield Wind Farm - GE 1.5xle x 35 layout

5.5 Layout of the proposed Sheffield Wind Farm - V82 x 29 layout

5.6 Layout of the proposed Sheffield Wind Farm - V82x 35 layout

6.1 Measured wind rose at Mast 5211 at 32 m

6.2 Correlation of wind speed between Mast 5211 at 32 m and Mast 5210 at 48 m

6.3 Correlation of wind direction between Mast 5211 at 32 m and Mast 5210 at 48 m

6.4 Correlation of wind speed between Mast 5211 at 32 m and Mast 5210 at 48 m

6.5 Correlation of wind direction between Mast 5211 at 32 m and Mast 5210 at 48 m

6.6 Daily correlation of wind speed from Burke Mountain reference station at 23 m to Mast 4716 at 48 m

6.7 Daily correlation of wind speed from Burke Mountain reference station at 23 m to Mast 5210 at 48 m

6.8 Predicted long-term wind rose at Mast 4716 at 48 m

6.9 Predicted long-term wind rose at Mast 5210 at 48 m


Location

Description of measurements

Period

Mast 4716 (Grid ref 730305, 4951368; zone 18)

Ten-minute mean, standard deviation, maximum and minimum wind speed recorded at 2 x 48 m, 40 m and 30 m height.

29 Jun 2004 to 1 Apr 2005

Ten-minute mean, standard deviation, maximum and minimum wind direction recorded at 48 m and 40 m height.


Ten-minute mean, standard deviation, maximum and minimum wind speed recorded at 2 x 48 m, 39 m and 30 m height.

29 Sep 2004 to 1 Apr 2005


Table 2.1 Summary of measurements made at the Sheffield site and Burke Mountain

reference station (continued)


Location

Description of measurements

Period


Hourly mean and average deviation wind speed recorded at 40 m, 32 m and 23 m height.

10 Nov 2002 to 28 Sep 2004

Hourly mean wind direction recorded at 40 m and 32 m height.

Ten-minute mean, standard deviation, maximum and minimum wind speed recorded at 40 m, 32 m and 23 m height.

28 Sep 2004 to 1 Apr 2005


Burke Mountain (Grid ref 270230, 4939125; zone 19)

Ten-minute mean, standard deviation, maximum and minimum wind speed recorded at 2 x 23 m height.

31 Dec 1997 to 28 Feb 2005

Ten-minute mean, standard deviation, maximum and minimum wind direction recorded at 23 m height.

Table 2.1 Summary of measurements made at the Sheffield site and Burke Mountain

reference station (concluded)


Month Mean wind speed

[m/s]

50m ws3 50m ws4

Wind speed data coverage

[%]

Wind direction data coverage

[%]

Jun-04 6.4 6.4 5 5 Jul-04 5.8 5.8 100 100

Aug-04 6.1 6.1 100 100 Sep-04 6.8 6.8 100 100 Oct-04 6.7 6.6 99 99

Nov-04 8.0 8.0 73 73 Dec-04 7.9 7.9 36 36 Jan-05 7.5 7.4 55 22 Feb-05 7.1 7.0 70 44 Mar-05 7.9 7.9 92 72 Apr-05 5.9 5.8 1 1

Table 4.1 Measurements made at Mast 4716 at a height of 48 m


[m/s]

50m W 50m S


[%]


[%]

Sep-04 2.8 2.6 4 4 Oct-04 6.0 5.5 89 100

Nov-04 6.9 6.7 97 97 Dec-04 7.0 7.0 46 45 Jan-05 6.2 5.8 69 59 Feb-05 6.3 6.1 72 72 Mar-05 6.6 6.5 93 87 Apr-05 6.6 6.3 3 3




[m/s]


[%]


[%] Nov-02 4.7 55 30 Dec-02 5.3 82 77 Jan-03 4.9 85 85 Feb-03 5.0 87 87 Mar-03 4.9 60 60 Apr-03 - 0 0

May-03 3.1 79 79 Jun-03 4.0 100 100 Jul-03 3.9 100 100

Aug-03 3.8 100 100 Sep-03 3.8 100 100 Oct-03 4.7 84 84

Nov-03 5.1 95 95 Dec-03 5.7 74 75 Jan-04 5.2 84 58 Feb-04 4.6 93 93 Mar-04 4.5 100 100 Apr-04 5.0 100 100

May-04 4.4 96 96 Jun-04 4.5 100 100 Jul-04 3.4 100 100

Aug-04 3.6 100 100 Sep-04 4.0 98 98 Oct-04 4.2 98 98





[m/s]


[%]


[%] Dec-97 8.8 0 0 Jan-98 8.3 100 100 Feb-98 8.7 100 100 Mar-98 8.5 100 100 Apr-98 7.8 100 100

May-98 8.3 100 100 Jun-98 7.5 100 100 Jul-98 7.1 100 100

Aug-98 6.2 100 100 Sep-98 7.7 100 68 Oct-98 9.0 100 0


May-99 8.0 100 0 Jun-99 7.1 100 0 Jul-99 7.1 100 0

Aug-99 6.8 100 0 Sep-99 8.7 100 0 Oct-99 10.1 100 0


May-00 7.8 100 0 Jun-00 7.8 100 0 Jul-00 6.8 100 0

Aug-00 7.1 100 0 Sep-00 8.1 100 0 Oct-00 8.4 100 0

Nov-00 8.1 100 0 Dec-00 10.1 100 0 Jan-01 7.6 100 0 Feb-01 10.1 100 0 Mar-01 8.6 100 0

Table 4.4 Measurements made at Burke Mountain reference station at a height of 23 m

(continued)



[m/s]


[%]


[%] Apr-01 8.6 100 0

May-01 7.8 100 0 Jun-01 7.3 100 0 Jul-01 6.8 100 0

Aug-01 6.7 100 0 Sep-01 7.9 100 0 Oct-01 9.1 100 0


May-02 9.1 100 0 Jun-02 7.1 100 0 Jul-02 7.6 100 0

Aug-02 6.6 100 0 Sep-02 7.9 100 0 Oct-02 8.9 100 0


May-03 5.9 100 100 Jun-03 7.2 100 100 Jul-03 7.0 100 100

Aug-03 7.2 100 100 Sep-03 8.0 97 97 Oct-03 8.7 100 100


May-04 8.2 100 100 Jun-04 7.7 100 100 Jul-04 6.6 100 100


(continued)



[m/s]


[%]


[%] Aug-04 7.2 100 100 Sep-04 7.6 100 100 Oct-04 7.6 100 100

Nov-04 9.7 100 100 Dec-04 10.2 100 100 Jan-05 9.5 100 100 Feb-05 8.2 100 100


(concluded)


Turbine option GE 1.5sle GE 1.5xle V82

Diameter

Hub height

Rotor speed

Power regulation

Nominal rated power

77

80

10 - 20

Pitch

1500

82.5

80

10.2 - 18.5

Pitch

1500

82

80

14.4

Pitch

1650

m

m

rpm

kW

Table 5.1 Main parameters of the wind turbines analysed


Electrical power [kW] Wind speed

[m/s at hub height] GE 1.5sle1 GE 1.5xle1 V822

3 0 2 0 3.5 18 24 4 40 56 25

4.5 79 99 5 125 151 138

5.5 176 210 6 240 282 296

6.5 312 367 7 399 467 491

7.5 499 584 8 615 712 722

8.5 757 861 9 889 998 968

9.5 1029 1142 10 1151 1260 1217

10.5 1257 1357 11 1339 1427 1453

11.5 1391 1466 12 1431 1490 1628

12.5 1457 1497 13 1476 1500 1646

13.5 1486 1500 14 1494 1500 1648

14.5 1500 1500 15 1500 1500 1650

15.5 1500 1500 16 1500 1500 1650

16.5 1500 1500 17 1500 1500 1650

17.5 1500 1500 18 1500 1500 1650

18.5 1500 1500 19 1500 1500 1650

19.5 1500 1500 20 1500 1500 1650

20.5 1500 0 21 1500 0 0

21.5 1500 0 22 1500 0 0

22.5 1500 0 23 1500 0 0

23.5 1500 0 24 1500 0 0

24.5 1500 0 25 1500 0 0

Notes 1 Performance for air density 1.180 kg/m3 and 10 to 15 % turbulence intensity 2 Performance for air density 1.180 kg/m3 and 10 to 15% turbulence intensity 3 Performance for air density 1.180 kg/m3 and 11 to 16 % turbulence intensity Table 5.2 Performance data for the wind turbines analysed


Turbine Easting1

[m] Northing1

[m] Mean hub-height wind speed2

[m/s] Energy output3

[GWh/annum] 1 728624 4950172 8.0 5.8 2 728915 4950298 7.3 5.0 3 729195 4950426 7.2 4.8 4 729482 4950223 7.3 4.7 5 729082 4951211 7.2 4.7 6 729137 4950902 7.4 4.9 7 729483 4951173 7.3 4.8 8 729923 4951492 7.6 5.3 9 730102 4951056 7.8 5.3

10 730355 4950800 7.7 5.0 11 730526 4950403 7.7 5.3 12 730226 4951541 8.2 5.7 13 730354 4951233 8.2 5.4 14 730599 4950995 7.9 5.3 15 730529 4951485 8.1 5.5 16 730830 4951513 7.3 4.9 17 731218 4951731 7.6 5.4 18 731499 4951867 7.9 5.6 19 731734 4951653 7.4 4.9 20 732005 4951797 8.2 6.0 21 728800 4948038 6.4 3.8 22 728952 4947367 6.2 3.7 23 729246 4947273 6.2 3.5 24 730053 4947655 6.3 3.6 25 730298 4947407 6.2 3.4 26 730521 4947178 6.5 3.8 27 730415 4946888 6.5 3.8 28 730344 4946528 6.7 4.1 29 730327 4946178 6.4 3.9

Notes 1 Co-ordinate system is UTM NAD27, Z18 2 Wind speed at the location of the turbine, not including wake effects 3 Individual turbine output figures include topographic, array and air density adjustments only Table 5.3 Turbine layout with predicted individual turbine wind speed and energy

production – GE 1.5sle x 29


Turbine Easting1

[m] Northing1



[GWh/annum] 1 728532 4950360 7.3 5.0 2 728660 4950079 7.8 5.4 3 728840 4950329 7.5 5.0 4 729201 4950468 7.1 4.7 5 729471 4950298 7.2 4.6 6 729074 4951218 7.1 4.6 7 729131 4950905 7.4 4.9 8 729528 4951051 7.3 4.8 9 730033 4950858 7.3 4.8

10 730489 4950408 7.7 5.2 11 730785 4950341 7.2 4.5 12 729919 4951494 7.6 5.1 13 730063 4951186 7.8 5.0 14 730307 4950993 7.9 5.1 15 730609 4950852 7.7 4.9 16 730203 4951613 8.0 5.5 17 730334 4951334 8.2 5.3 18 730588 4951159 8.0 5.1 19 730529 4951569 7.9 5.3 20 730832 4951517 7.3 4.8 21 731264 4951732 7.6 5.4 22 731537 4951882 7.9 5.6 23 731757 4951628 7.4 4.9 24 732005 4951812 8.2 6.0 25 728750 4948593 5.9 3.2 26 728809 4948027 6.4 3.8 27 728975 4947370 6.3 3.7 28 729260 4947251 6.2 3.5 29 729829 4947602 6.0 3.2 30 730126 4947694 6.1 3.3 31 730298 4947436 6.2 3.3 32 730537 4947220 6.5 3.7 33 730426 4946929 6.5 3.8 34 730385 4946491 6.7 4.0 35 730312 4946163 6.4 3.9


production – GE 1.5sle x 35


Turbine Easting1

[m] Northing1



[GWh/annum] 1 728629 4950179 8.0 6.2 2 728928 4950315 7.3 5.3 3 729076 4951224 7.1 5.1 4 729142 4950901 7.4 5.3 5 729238 4950464 7.1 5.1 6 729514 4950232 7.2 5.0 7 729493 4951153 7.3 5.2 8 729871 4951498 7.5 5.5 9 730043 4951107 7.7 5.6

10 730340 4950804 7.6 5.4 11 730536 4950394 7.7 5.7 12 730198 4951553 8.1 5.9 13 730342 4951245 8.2 5.7 14 730600 4951009 7.9 5.6 15 730526 4951517 8.1 5.9 16 730849 4951517 7.2 5.2 17 731226 4951697 7.6 5.7 18 731509 4951871 7.9 5.9 19 731740 4951622 7.3 5.2 20 732003 4951821 8.2 6.3 21 728797 4948044 6.4 4.2 22 728950 4947372 6.2 4.1 23 729267 4947270 6.1 3.8 24 730047 4947668 6.3 3.9 25 730283 4947407 6.2 3.7 26 730514 4947165 6.5 4.2 27 730398 4946852 6.4 4.0 28 730325 4946526 6.7 4.4 29 730349 4946178 6.4 4.2


production – GE 1.5xle x 29


Turbine Easting1

[m] Northing1



[GWh/annum] 1 728497 4950401 7.2 5.2 2 728626 4950095 7.8 5.8 3 728827 4950357 7.4 5.4 4 729077 4951211 7.2 5.1 5 729145 4950888 7.4 5.3 6 729457 4950297 7.3 5.2 7 729530 4951052 7.3 5.2 8 730023 4950832 7.2 5.1 9 729854 4951490 7.4 5.4

10 730094 4951153 7.9 5.5 11 730353 4950948 7.8 5.4 12 730650 4950805 7.4 5.0 13 730462 4950386 7.6 5.6 14 730789 4950337 7.2 5.0 15 730176 4951591 8.0 5.9 16 730374 4951326 8.2 5.7 17 730640 4951134 7.7 5.2 18 730504 4951625 7.7 5.5 19 730824 4951513 7.3 5.0 20 731264 4951732 7.6 5.7 21 731565 4951873 7.9 5.9 22 731717 4951567 7.1 4.9 23 732000 4951768 8.3 6.3 24 728768 4948581 5.9 3.6 25 728799 4948029 6.4 4.2 26 728953 4947373 6.2 4.1 27 729271 4947269 6.1 3.8 28 729829 4947602 6.0 3.6 29 730168 4947570 6.2 3.5 30 730202 4947237 6.1 3.5 31 730535 4947225 6.4 4.0 32 730419 4946912 6.5 4.1 33 730404 4946487 6.6 4.3 34 730093 4946376 6.2 3.9 35 730261 4946024 6.4 4.2


production – GE 1.5xle x 35


Turbine Easting1

[m] Northing1



[GWh/annum] 1 728629 4950179 8.0 6.4 2 728928 4950315 7.3 5.5 3 729076 4951224 7.1 5.2 4 729142 4950901 7.4 5.4 5 729238 4950464 7.1 5.2 6 729514 4950232 7.2 5.1 7 729493 4951153 7.3 5.3 8 729871 4951498 7.5 5.6 9 730043 4951107 7.7 5.7

10 730340 4950804 7.6 5.6 11 730536 4950394 7.7 5.8 12 730198 4951553 8.1 6.2 13 730342 4951245 8.2 5.9 14 730600 4951009 7.9 5.8 15 730526 4951517 8.1 6.0 16 730849 4951517 7.2 5.3 17 731226 4951697 7.6 5.9 18 731509 4951871 7.9 6.1 19 731740 4951622 7.3 5.4 20 732003 4951821 8.2 6.5 21 728797 4948044 6.4 4.3 22 728950 4947372 6.2 4.1 23 729267 4947270 6.1 3.9 24 730047 4947668 6.3 4.0 25 730283 4947407 6.2 3.8 26 730514 4947165 6.5 4.3 27 730398 4946852 6.4 4.1 28 730325 4946526 6.7 4.5 29 730349 4946178 6.4 4.3


production – V82 x 29


Turbine Easting1

[m] Northing1



[GWh/annum] 1 728497 4950401 7.2 5.3 2 728626 4950095 7.8 6.0 3 728827 4950357 7.4 5.5 4 729077 4951211 7.2 5.2 5 729145 4950888 7.4 5.5 6 729457 4950297 7.3 5.4 7 729530 4951052 7.3 5.4 8 730023 4950832 7.2 5.2 9 729854 4951490 7.4 5.5

10 730094 4951153 7.9 5.7 11 730353 4950948 7.8 5.5 12 730650 4950805 7.4 5.1 13 730462 4950386 7.6 5.7 14 730789 4950337 7.2 5.1 15 730176 4951591 8.0 6.1 16 730374 4951326 8.2 5.9 17 730640 4951134 7.7 5.3 18 730504 4951625 7.7 5.7 19 730824 4951513 7.3 5.2 20 731264 4951732 7.6 5.9 21 731565 4951873 7.9 6.1 22 731717 4951567 7.1 5.0 23 732000 4951768 8.3 6.6 24 728768 4948581 5.9 3.6 25 728799 4948029 6.4 4.3 26 728953 4947373 6.2 4.1 27 729271 4947269 6.1 3.8 28 729829 4947602 6.0 3.6 29 730168 4947570 6.2 3.5 30 730202 4947237 6.1 3.5 31 730535 4947225 6.4 4.0 32 730419 4946912 6.5 4.1 33 730404 4946487 6.6 4.4 34 730093 4946376 6.2 3.9 35 730261 4946024 6.4 4.2


production – V82 x 35



[m/s]


[percentage]


[percentage] January 9.3 100 50 February 9.3 100 38 March 9.1 100 43 April 8.3 100 43 May 7.9 100 43 June 7.4 100 43 July 7.0 100 43 August 6.8 100 43 September 8.0 100 38 October 8.8 100 29 November 9.5 100 29 December 9.7 94 29

Mean of means 8.4

Table 6.1 Measured monthly and annual mean wind speeds at Burke Mountain reference station (1998 to 2005)


[m/s]


[percentage]


[percentage] January 4.9 79 70 February 4.7 87 84 March 4.8 85 81 April 5.0 51 51 May 3.8 88 88 June 4.3 100 100 July 3.7 100 100 August 3.7 100 100 September 3.9 99 99 October 4.4 91 91 November 4.9 93 84 December 5.4 67 67

Mean of means 4.5

Table 6.2 Measured monthly and annual mean wind speeds at Mast 5211 at 32 m (2002 to 2005)


Table 6.3 Measured wind speed and direction frequency distribution at Mast 5211 at 32 m

Site: Mast 5211 at 32 m Period: Annual (2002 to 2005)

Wind Speed Wind Direction (degrees) No Total (m/s) 0 30 60 90 120 150 180 210 240 270 300 330 Direction (%)

0 0.13 0.14 0.31 0.45 0.17 0.22 0.22 0.31 0.31 0.18 0.13 0.14 0.05 2.77 1 0.45 0.47 0.53 0.83 0.67 0.74 0.77 0.76 0.92 0.46 0.50 0.51 0.16 7.77 2 0.86 0.51 0.63 0.67 0.51 1.07 1.15 0.84 1.06 0.68 0.76 0.84 0.31 9.90 3 1.57 0.51 0.68 0.72 0.22 1.06 2.22 0.99 1.47 1.54 1.48 1.69 0.43 14.56 4 1.97 0.58 0.52 0.40 0.06 0.61 3.08 1.25 1.85 2.73 2.37 1.87 0.48 17.76 5 1.38 0.49 0.31 0.16 0.03 0.26 3.99 1.45 1.77 2.96 2.41 1.50 0.49 17.20 6 0.74 0.28 0.13 0.08 0.12 3.61 1.34 0.87 2.20 1.92 0.67 0.28 12.22 7 0.37 0.11 0.07 0.06 0.04 2.67 0.73 0.73 1.42 1.28 0.27 0.28 8.01 8 0.22 0.21 0.09 0.13 0.01 1.59 0.23 0.36 0.85 0.80 0.14 0.24 4.85 9 0.20 0.05 0.02 0.05 0.01 0.53 0.11 0.19 0.78 0.42 0.04 0.21 2.61

10 0.05 0.01 0.01 0.01 0.18 0.01 0.08 0.44 0.28 0.04 0.12 1.21 11 0.03 0.02 0.09 0.02 0.03 0.26 0.14 0.01 0.10 0.68 12 0.01 0.02 0.05 0.14 0.07 0.02 0.30 13 0.01 0.01 0.07 0.01 0.08 14 0.01 0.02 0.03 0.05 15 0.02 0.02 16 0.01 0.01 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38

39 - 44 45 and over

Total (%) 7.96 3.36 3.30 3.56 1.66 4.13 20.09 8.04 9.69 14.75 12.60 7.70 3.16 100 Av.Speed (m/s) 4.15 3.76 2.92 2.58 1.64 2.64 5.11 4.22 4.18 5.39 5.10 3.90 5.17 4.45

NB: + indicates non-zero percentage <0.005%, blank indicates zero percentage


Table 6.4 Predicted long-term wind speed and direction frequency distribution at Mast 4716 at 48 m



0 0.08 0.04 0.12 0.29 0.20 0.11 0.14 0.20 0.11 0.11 0.13 0.14 0.03 1.71 1 0.27 0.14 0.24 0.53 0.41 0.26 0.41 0.50 0.32 0.28 0.37 0.42 0.08 4.24 2 0.32 0.17 0.26 0.55 0.49 0.36 0.47 0.55 0.36 0.33 0.46 0.53 0.11 4.96 3 0.46 0.17 0.28 0.53 0.46 0.42 0.63 0.59 0.39 0.40 0.63 0.82 0.19 5.98 4 0.60 0.17 0.27 0.53 0.43 0.47 0.78 0.71 0.54 0.70 1.09 1.08 0.23 7.59 5 0.74 0.19 0.24 0.46 0.40 0.68 1.17 0.79 0.61 0.93 1.49 1.67 0.26 9.62 6 0.86 0.17 0.17 0.31 0.35 0.74 1.38 0.93 0.69 1.18 2.13 1.94 0.28 11.14 7 0.73 0.14 0.11 0.18 0.23 0.79 1.61 0.97 0.66 1.23 2.21 1.93 0.30 11.09 8 0.57 0.08 0.06 0.10 0.14 0.89 1.93 0.92 0.46 1.02 2.07 1.73 0.29 10.27 9 0.32 0.04 0.04 0.08 0.13 0.91 1.98 0.79 0.32 0.82 1.70 1.38 0.23 8.75

10 0.27 0.06 0.04 0.06 0.05 0.81 1.77 0.63 0.27 0.57 1.30 0.95 0.17 6.95 11 0.18 0.05 0.03 0.03 0.04 0.64 1.56 0.43 0.17 0.42 0.98 0.67 0.17 5.37 12 0.10 0.02 0.01 0.02 0.04 0.56 1.22 0.18 0.11 0.32 0.72 0.38 0.17 3.85 13 0.08 0.03 0.04 0.43 0.90 0.12 0.07 0.27 0.61 0.31 0.14 3.01 14 0.07 0.01 0.03 0.04 0.29 0.68 0.06 0.04 0.19 0.39 0.20 0.14 2.14 15 0.03 0.02 0.02 0.17 0.28 0.02 0.02 0.13 0.29 0.13 0.12 1.24 16 0.02 0.01 0.01 0.12 0.19 0.01 0.01 0.08 0.22 0.08 0.07 0.82 17 0.01 0.01 0.07 0.07 0.02 0.02 0.06 0.12 0.06 0.07 0.49 18 0.01 0.01 0.06 0.06 0.01 0.01 0.04 0.09 0.04 0.05 0.37 19 0.01 0.03 0.03 0.01 0.02 0.05 0.02 0.02 0.18 20 0.02 0.01 0.01 0.01 0.01 0.01 0.01 0.07 21 0.01 0.01 0.01 0.01 0.04 22 0.01 0.01 0.02 0.01 0.03 23 0.01 0.01 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38

39 - 44 45 and over

Total (%) 5.74 1.45 1.88 3.75 3.50 8.83 17.28 8.42 5.19 9.15 17.09 14.51 3.15 100 Av.Speed (m/s) 6.14 4.90 3.97 3.90 4.50 8.19 8.47 6.35 6.02 7.35 7.86 7.04 8.34 7.14



Table 6.5 Predicted long-term wind speed and direction frequency distribution at Mast 5210 at 48 m



0 0.09 0.08 0.28 0.24 0.14 0.15 0.16 0.22 0.22 0.18 0.12 0.11 0.04 2.02 1 0.31 0.26 0.47 0.45 0.33 0.43 0.46 0.52 0.62 0.45 0.39 0.35 0.11 5.15 2 0.41 0.29 0.53 0.43 0.43 0.57 0.59 0.57 0.72 0.58 0.54 0.48 0.18 6.32 3 0.57 0.31 0.58 0.36 0.42 0.73 0.82 0.64 0.89 0.88 0.73 0.71 0.24 7.88 4 0.89 0.31 0.53 0.37 0.39 1.09 1.23 0.74 1.12 1.41 1.32 1.16 0.33 10.90 5 1.03 0.34 0.39 0.37 0.38 1.33 1.62 0.89 1.26 2.22 1.84 1.39 0.34 13.42 6 1.09 0.29 0.24 0.22 0.28 1.51 1.93 0.99 1.16 2.28 2.07 1.50 0.36 13.91 7 0.77 0.21 0.11 0.16 0.22 1.57 2.01 0.90 0.59 1.94 2.01 1.26 0.34 12.07 8 0.56 0.12 0.07 0.08 0.16 1.34 1.78 0.67 0.49 1.51 1.62 1.01 0.21 9.60 9 0.37 0.08 0.07 0.05 0.09 1.02 1.29 0.38 0.32 1.03 1.25 0.51 0.21 6.66

10 0.22 0.12 0.04 0.04 0.07 0.73 0.89 0.14 0.18 0.67 0.93 0.33 0.20 4.57 11 0.15 0.04 0.01 0.03 0.05 0.44 0.52 0.07 0.10 0.58 0.62 0.20 0.17 2.98 12 0.12 0.01 0.01 0.06 0.04 0.22 0.21 0.02 0.04 0.45 0.41 0.12 0.14 1.83 13 0.09 0.01 0.06 0.03 0.09 0.08 0.01 0.02 0.28 0.29 0.08 0.11 1.16 14 0.04 0.01 0.03 0.01 0.07 0.04 0.01 0.03 0.17 0.20 0.04 0.08 0.73 15 0.02 0.01 0.01 0.03 0.02 0.01 0.11 0.11 0.03 0.06 0.41 16 0.01 0.01 0.01 0.01 0.01 0.01 0.07 0.07 0.02 0.02 0.21 17 0.01 0.01 0.01 0.03 0.03 0.01 0.01 0.09 18 0.02 0.01 0.03 19 0.01 0.02 0.03 20 0.01 0.01 0.01 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38

39 - 44 45 and over

Total (%) 6.73 2.47 3.31 2.96 3.07 11.34 13.66 6.76 7.77 14.89 14.59 9.30 3.15 100 Av.Speed (m/s) 5.76 4.67 3.39 4.05 4.48 6.38 6.43 5.13 4.85 6.59 6.88 5.90 6.91 5.95



Mast Measurement Long-term mean wind speed height Long-term prediction WAsP [m] [m/s] [m/s]

4716 80 8.2 7.0

Table 6.6 Predictions of the wind speeds at the site masts from Mast 5210

Source of uncertainty Wind speed

Energy output 1

[%] [m/s] [%] [GWh/annum]Anemometer accuracy 3.0 Correlation accuracy to Burke Mountain 2.8 Shear prediction to 80 m 3.0 Variability of 7.1 year period 2.2 Overall historical wind speed 0.46 8.8 Substation metering 0.3 0.3 Wake and topographic calculation 6.0 5.6 Representative frequency distribution 0.5 0.5 Future wind variability (1 year) 6.0 0.49 9.5 Future wind variability (10 years) 1.9 0.16 3.0 Overall energy uncertainty (1 year) 14.2

Overall energy uncertainty (10 years) 10.9 Note: Sensitivity of net production to wind speed is calculated to be 19.3 GWh/annum.(m/s)

Table 6.7 Uncertainty in projected energy output of Turbines 1 to 20 based on Mast 4716 – GE 1.5sle x 29


Energy output 1

[%] [m/s] [%] [GWh/annum]

Anemometer accuracy 2.5 Correlation accuracy to Burke Mountain 4.2 Shear prediction to 80 m 2.5 Variability of 7.1 year period 2.2 Overall historical wind speed 0.39 3.8 Substation metering 0.3 0.1 Wake and topographic calculation 4.0 1.2 Representative frequency distribution 0.5 0.2 Future wind variability (1 year) 6.0 0.40 3.9 Future wind variability (10 years) 1.9 0.13 1.2 Overall energy uncertainty (1 year) 5.6





Energy output 1





Energy output 1







Energy output 1




Table 6.11 Uncertainty in projected energy output of Turbines 1 to 20 based on Mast 4716 – GE 1.5xle x 29


Energy output 1







Energy output 1






Energy output 1







Energy output 1



Table 6.15 Uncertainty in projected energy output of Turbines 1 to 20 based on Mast 4716 – V82 x 29


Energy output 1







Energy output 1






Energy output 1






Energy production1 [%]

Hour Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 0000 0.42 0.35 0.44 0.44 0.26 0.32 0.23 0.24 0.33 0.37 0.41 0.55 0100 0.43 0.38 0.40 0.44 0.25 0.32 0.27 0.24 0.30 0.35 0.37 0.54 0200 0.45 0.38 0.40 0.41 0.26 0.33 0.24 0.23 0.27 0.33 0.39 0.54 0300 0.44 0.38 0.39 0.45 0.29 0.30 0.24 0.22 0.26 0.32 0.40 0.51 0400 0.45 0.37 0.39 0.45 0.24 0.28 0.21 0.23 0.25 0.30 0.38 0.50 0500 0.41 0.35 0.37 0.42 0.24 0.24 0.18 0.21 0.28 0.33 0.41 0.50 0600 0.40 0.38 0.36 0.42 0.22 0.21 0.17 0.19 0.24 0.33 0.39 0.50 0700 0.40 0.38 0.34 0.36 0.23 0.21 0.17 0.19 0.21 0.30 0.40 0.50 0800 0.39 0.35 0.28 0.35 0.23 0.21 0.17 0.19 0.19 0.29 0.41 0.46 0900 0.40 0.35 0.31 0.37 0.28 0.23 0.18 0.19 0.19 0.31 0.39 0.45 1000 0.40 0.36 0.32 0.41 0.27 0.27 0.20 0.19 0.20 0.30 0.40 0.44 1100 0.43 0.33 0.34 0.45 0.32 0.29 0.22 0.22 0.21 0.32 0.41 0.46 1200 0.45 0.35 0.35 0.44 0.30 0.33 0.23 0.22 0.20 0.31 0.43 0.45 1300 0.44 0.35 0.36 0.45 0.33 0.33 0.22 0.23 0.22 0.32 0.46 0.48 1400 0.43 0.34 0.39 0.48 0.31 0.37 0.23 0.24 0.23 0.32 0.47 0.46 1500 0.41 0.33 0.40 0.43 0.30 0.35 0.21 0.23 0.23 0.30 0.47 0.52 1600 0.42 0.32 0.42 0.43 0.28 0.34 0.19 0.22 0.24 0.31 0.47 0.51 1700 0.47 0.32 0.43 0.39 0.31 0.31 0.18 0.21 0.30 0.33 0.45 0.51 1800 0.49 0.35 0.45 0.46 0.31 0.29 0.23 0.26 0.32 0.35 0.48 0.54 1900 0.49 0.34 0.48 0.45 0.33 0.31 0.26 0.26 0.34 0.34 0.46 0.55 2000 0.46 0.35 0.48 0.45 0.33 0.33 0.27 0.28 0.35 0.35 0.45 0.53 2100 0.44 0.36 0.46 0.47 0.34 0.32 0.27 0.27 0.36 0.38 0.47 0.59 2200 0.43 0.34 0.47 0.41 0.31 0.31 0.26 0.26 0.36 0.42 0.43 0.58 2300 0.40 0.34 0.45 0.39 0.28 0.31 0.23 0.24 0.36 0.42 0.42 0.57 Total 10.3 8.4 9.5 10.2 6.8 7.1 5.3 5.4 6.4 8.0 10.2 12.2 Note Energy production has been modelled using the Sheffield 29 x V82 layout at 80 m. The values presented are inclusive of topographical and array losses only.

Table 6.19 Predicted seasonal and diurnal variation in energy production

Garrad Hassan America, Inc. Document: 4776/AR/01 Issue: A FINAL

Figure 2.1 Location of the Sheffield Wind Farm

Sheffield Wind Farm Burke Mtn.


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Figure 2.2 Map of the site


Figure 2.3 View of ridges located within the south-western extent of the site as seen from the valley floor facing southwest


Figure 3.1 View of the Burke Mountain reference station from the west


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Figure 5.1 Layout of the proposed Sheffield Wind Farm - GE 1.5sle x 29 layout


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Figure 5.2 Layout of the proposed Sheffield Wind Farm - GE 1.5sle x 35 layout


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Figure 5.3 Layout of the proposed Sheffield Wind Farm - GE 1.5xle x 29 layout


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Figure 5.4 Layout of the proposed Sheffield Wind Farm - GE 1.5xle x 35 layout


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Figure 5.5 Layout of the proposed Sheffield Wind Farm – V82 x 29 layout


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Figure 5.6 Layout of the proposed Sheffield Wind Farm – V82 x 35 layout


5 % 10% 15%

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Figure 6.1 Measured wind rose at Mast 5211 at 32 m


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Figure 6.2 Correlation of wind speed between Mast 5211 at 32 m and Mast 5210 at 48 m (continued)


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Figure 6.2 Correlation of wind speed between Mast 5211 at 32 m and Mast 5210 at 48 m (concluded)


0 50 100 150 200 250 300 350Mast 5211 at 40m direction (degrees)

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Figure 6.3 Correlation of wind direction between Mast 5211 at 40 m and Mast 5210 at 48 m



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st 4

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PCA fit

Data



Figure 6.4 Correlation of wind speed between Mast 5211 at 32 m and Mast 4716 at 48 m (concluded)


0 50 100 150 200 250 300 350Mast 5211 at 40m direction (degrees)

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gree

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Wind speeds greater than 5.0 m/s

Figure 6.5 Correlation of wind direction between Mast 5211 at 40 m and Mast 4716 at 48 m


y = 0.8469x

R2 = 0.8302

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Burke Moutain daily mean wind speed at 23 m [m/s]

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Figure 6.6 Daily correlation of wind speed from Burke Mountain reference station at 23 m to Mast 4716 at 48 m


y = 0.706x

R2 = 0.7689

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Burke Moutain daily mean wind speed at 23 m [m/s]

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Figure 6.7 Daily correlation of wind speed from Burke Mountain reference station at 23 m to Mast 5210 at 48 m


5 % 10% 15%

0-3 3-6 6-9 >9 m/s

Figure 6.8 Predicted long-term wind rose at Mast 4716 at 48 m


5 % 10% 15%

0-3 3-6 6-9 >9 m/s

Figure 6.9 Predicted long-term wind rose at Mast 5210 at 48 m


APPENDIX 1

Data analysis procedure

1. Correlation of wind speed and direction at the site.

2. Site wind speed variations.

3. Projected energy production.

4. Confidence analysis.

5. References.


1 Correlation of wind speed and direction at the site

The method used to determine the long-term mean wind speed for a “target” site from a “reference” site is based on the Measure-Correlate-Predict approach, which is outlined below.

The first stage in the approach is to measure, over a period of about one year, concurrent wind data from both the “target” site and the nearby “reference” site for which well established long-term wind records are available. The short-term measured wind data are then used to establish the correlation between the winds at the two locations. Finally, the correlation is used to adjust the long-term historical data recorded at the “reference” site to calculate the long-term mean wind speed at the site.

The concurrent data are correlated by comparing wind speeds at the two locations for each of twelve 30 degree direction sectors, based on the wind direction recorded at the “reference” site. This correlation involves two steps:

• Wind directions recorded at the two locations are compared to determine whether there are any local features influencing the directional results. Only those records with speeds in excess of 5 m/s at both locations are used.

• Wind speed ratios are determined for each of the direction sectors using a principal component analysis with the solution forced through the origin. This method is equivalent to a linear least-squared regression forced through the origin minimising the orthogonal offset.

In order to minimise the influence of localised winds on the wind speed ratio, the data are screened to reject records where the speed recorded at the “reference” site falls below 3 m/s or a slightly different level at the “target” site. The average wind speed ratio is used to adjust the 3 m/s wind speed level for the “reference” site to obtain the higher level for the “target” site, to ensure unbiased exclusion of data. The wind speed at which this level is set is a balance between excluding low winds from the analysis and still having sufficient data for the analysis. The level used excludes only winds below the cut-in wind speed of a wind turbine which do not contribute to the energy production.

The result of the analysis described above is a table of wind speed ratios, each corresponding to one of twelve direction sectors. These ratios are used to factor the wind data measured at the “reference” site over the historical reference period, to obtain the long-term mean wind speed at the “target” site. 2 Site wind speed variations

To calculate the variation of mean wind speed over the site, the computer wind flow model, WAsP is used. Details of the model and its validation are given by Troen and Petersen [1].

The inputs to the model are a digitised map of the topography and surface roughness length of the terrain for the site and surrounding area. A digitised map of an area surrounding the site of 21 km x 24 km was derived from 10 m DEM maps obtained by GH. Although this domain size is much larger than the area of the site itself, such an area is necessary since the flow at any point is dictated by the terrain several kilometres upwind.


Wind flow is affected by the roughness of the ground. The surface roughness length of the site and surrounding area has been estimated, as detailed in the main text.

The wind flow calculations were carried out for 30 degree steps in wind direction corresponding to the measured wind rose and results were produced as speed-up factors relative to the mast location for a grid encompassing the site area.

To determine the long-term mean wind speed at any location, the speed-up factor for each wind direction was weighted with the measured probability previously derived for the mast location. All directions were then summed to obtain the long-term mean wind speed at the required location.

3 Projected energy production

The components of the derivation of the wind farm net energy output prediction are listed and described below:

Ideal energy output

The ideal energy production is the theoretical output of the wind farm with the hub height wind speeds at the appropriate mast location applied for all associated turbines. Any density adjustment required due to a difference between the air density at hub height at the reference mast location and that assumed for the turbine power curve is applied as discussed in the main body of the report and included in the ideal energy output.

Topographic and wake effect calculations

The first step in modelling flow through an array of wind turbines is the calculation of the flow in the wake of a single machine. Immediately downstream of the rotor, there is a momentum deficit with respect to free stream conditions, which is equal to the thrust force on the machine. As the flow proceeds downstream, there is a spreading of the wake and recovery to free stream conditions. Turbulent momentum transfer is important in this process.

The model used here, WindFarmer, has been developed by GH and validated using measurements on both full-scale machines and on wind-tunnel models [2, 3, 4].

The model is employed in a scheme which, taking each wind speed and direction in turn calculates the power production of the wind farm. The important parameters used in this process are:

array layout

upstream mean wind speed

ambient turbulence

wind turbine thrust characteristic

wind turbine power characteristic

rotor speed

topographical speed-up factors from site wind flow calculations


Topographical effects are accounted for in the model using the speed-up factors calculated by the wind flow model described above. Any air density adjustments required due to differences between the hub height air density at the turbine locations and that at the reference mast location is applied as discussed in the main body of the report and included in the topographic effect. The array model is used to calculate the wind speed in the turbine wakes, assuming the terrain is flat, and the wind speed is adjusted by the speed-up factor when the wake reaches a downstream turbine. Electrical transmission efficiency

A figure of 97 % has been assumed for the electrical efficiency of the wind farm based on GH’s experience of typical wind farm electrical distribution system designs. A formal calculation of the electrical loss should be undertaken when the electrical system has been defined. Turbine availability

A figure of 97 % has been assumed for turbine availability based on data from modern operational wind farms. However, availability may be a matter of warranty between the owner and the turbine supplier and the assumed figure should be reviewed when the terms of that warranty are clear. Blade degradation and fouling

The turbine production may be affected by the build up of insects, dirt or ice on the blades. This build up will change the characteristics of the blade and therefore effect the performance of the blades and the turbine output.

An adjustment has been included to allow for lost production due to blade fouling. A figure of 97 % has been assumed to be appropriate for the pitch regulated turbines. Low temperature shutdown

The turbine production may be shut down due to extreme cold temperatures on site. Assuming arctic packages will be acquired for the proposed turbines, most turbines will require automatic shutdown for temperatures below minus 30 degrees Celsius. The potential loss associated with this has been assessed by reviewing the temperatures observed on site from the available temperature data recorded at Mast 5211. It is recommended that a detailed review of the specific turbine to be installed at the site should be undertaken in regards to this issue.

An adjustment has been included to allow for lost production due to low temperature shutdown. A figure of 99 % has been assumed to be appropriate for these turbines. High wind hysteresis

This is caused by the turbine cut in and cut out control criteria for high wind speeds. The magnitude of this loss is influenced by three factors.

1 The turbine will cut out when the maximum mean wind speed is exceeded and it will not cut in again until this mean wind speed is below a mean wind speed level lower than the cut out mean wind speed.

2 The turbine will cut out if the instantaneous gust wind speed exceeds a maximum level and the turbine will not cut in until the wind speed drops to a lower value.


3 The accuracy of the calibration of the instruments that are determining the wind characteristics at the turbine.

These three effects will cause the turbine to possibly lose production for some proportion of high mean wind speed occurrences. The magnitude of this lost production has been estimated by GH by repeating the analysis using a power curve with the cut out wind speed reduced by 2.5 m/s for the GE 1.5sle and GE 1.5xle and reduced by 1 m/s for the V82. Substation maintenance

Net wind farm production may be reduced due to the electrical output not being transferred to the grid network while the substation is shutdown for maintenance. A typical figure of 99.8 % is assumed in this analysis to represent one day per year of planned maintenance. This is included as scheduled maintenance can not generally be accurately planned to occur on a day with low wind speeds. Utility downtime

Net wind farm production will be reduced if the grid is not available for the wind farm to output electricity to it. This type of loss must be considered on a site specific basis. It has not been considered in this analysis. Power curve adjustment

Adjustment to the energy prediction to account for variations in the actual turbine performance in comparison to the supplied power curve. This may be a matter of warranty between the owner and the turbine supplier and the estimated figure should be reviewed when the terms of that warranty are clear and a detailed assessment of this issue has been conducted. Wind sector management

If wind turbine spacing is close the site conditions may exceed the wind conditions within the wind turbine certification criteria. In these circumstances it may be necessary to shut down some turbines which are closely spaced when the wind direction is parallel to the line of turbines. This issue has not been considered in this analysis. 4 Confidence analysis

There are 5 categories of uncertainty associated with the site wind speed prediction at the proposed site:

1. There is an uncertainty associated with the measurement accuracy of the anemometers. The instruments used have not been individually calibrated. In addition the mounting arrangement of the instruments is not to recommended standards. A figure of 2.5 % or 3.0 % is assumed here to account for these and other second order effects such as over-speeding, degradation, air density variations and additional turbulence effects.

2. The long-term mean wind speeds at Masts 4716 and 5210 were derived from correlation analyses, using the Burke Mountain reference station as a long-term reference. The uncertainty associated with correlating and extrapolating between masts is evaluated from the statistical scatter in the correlation plots.


3. There is uncertainty associated with the derivation of the wind shear between heights on the masts an d the assumption that this is representative of the wind flow at heights up to hub height. A figure of 2.5 % and 3.0 % are assumed here for the site mats based on the anemometer configuration.

4. There is an uncertainty associated with the assumption made here that the historical period at the meteorological site is representative of the climate over longer periods. A study of historical wind records indicates a typical variability of 6 % in the annual mean wind speed [5]. This figure is used to define the uncertainty in assuming the long-term mean wind speed is defined by a period approximately 7.1 years in length.

5. Additionally, even if the long-term mean wind speed were perfectly defined there will be variability in future mean wind speeds observed at the wind farm site. The variability in future mean wind speeds is dependant on the period considered. Performance over one and ten years of operation are therefore included in the uncertainty analysis. Account is taken of the future variability of wind speed in the energy confidence analysis but not the wind speed confidence analysis.

It is assumed that the time series of wind speed is random with no systematic trends. Care was taken to ensure that consistency of the reference measurement system and exposure has been maintained over the historical period and no allowance is made for uncertainties arising due to changes in either.

Uncertainties type 1 to 4 from above are added as independent errors on a root-sum-square basis to give the total uncertainty in the site wind speed prediction for the historical period considered.

It is considered here that there are 6 categories of uncertainty in the energy output projection:

1. Long-term mean wind speed dependent uncertainty is derived from the total wind speed uncertainty (types 1 to 4 above) using a factor for the sensitivity of the annual energy output to changes in annual mean wind speed. This sensitivity is derived by a perturbation analysis about the central estimate.

2. There is uncertainty within the assumption that the wind speed and direction frequency distribution at Mast 5211 at 32 m is representative at 80 m at Masts 4716 and 5211. A figure of 0.5 % has been included to account for this.

3. Wake and topographic modelling uncertainties. Validation tests of the methods used here, based on full-scale wind farm measurements made at small wind farms have shown that the methods are accurate to 2 % in most cases. For this development an uncertainty in the wake and topographic modelling of 4 % to 6 % is assumed due to the expanse of wind speed predictions.

4. Future wind speed-dependent uncertainties described in 5 above have been derived using the factor for the sensitivity of the annual energy output to changes in annual mean wind speed.

5. Accuracy of the fiscal substation energy meter. An uncertainty of 0.3 % is assumed here based on typical utility meter accuracy.


6. Turbine uncertainties are generally the subject of contract between the developer and turbine supplier and we have therefore made no allowance for them in this work.

Again those uncertainties which are considered are added as independent errors on a root-sum-square basis to give the total uncertainty in the projected energy output.

5 References

1. I Troen and E L Petersen, “European Wind Atlas”, Risø National Laboratory, Denmark, 1989.

2. U Hassan, A G Glendinning and C A Morgan, “ A Wind Tunnel Investigation of the wake structure and machine loads within small wind turbine farms”, Proc of the 12th BWEA Wind Energy Conference, IMechE, 1990.

3. J Højstrup, “Turbulence measurements in a windfarm”, Proc. EWEA Wind Energy Conference, Madrid, 1990.

4. J G Warren et al. "Performance of wind farms in complex terrain", Proc. Of the 17th BWEA Wind Energy Conference, 1995.

5. P Raftery, A J Tindal and A D Garrad, “Understanding the risks of financing windfarms”, Proc. EWEA Wind Energy Conference, Dublin, 1997.

crv-5 - gh power report-5!25!05

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