HomeMy WebLinkAboutReynolds Creek Hydroelectric Project Operations Studies Report - Jul 2012 - REF Grant 2195440
Page 1 AP&T Solutions
193 Otto Street PO Box 3222
Port Townsend, WA 98368
360.385.1733 / 800.982.0136
Email: aptsolutions@aptalaska.com
July 5, 2012
Corry Hildenbrand, Project Manager
Haida Energy
c/o Hildenbrand Associates LLC
17220 117th Avenue SE
Renton, WA 98058
Re: Reynolds Creek Hydroelectric Project
Report on Operations Studies
Dear Corry:
AP&T Solutions, the consulting subsidiary of Alaska Power & Telephone Co., is pleased to
submit this report on the operations studies conducted for the Reynolds Creek Hydroelectric
Project (Project) in accordance with our proposal dated May 30, 2012. These proposed studies
evaluate the firm and average annual generation available from the Project with the currently
licensed reservoir capacity and with an increased reservoir capacity using a custom spreadsheet
simulation model. The computer model and the input data and assumptions are discussed first
below, followed by the results of the studies.
EXECUTIVE SUMMARY
1. Flow data from the USGS gage on the outlet of Rich s Pond is for three discrete short periods, and
appears to show an increasing trend that may be consistent with data from other gages on POW. If
the increasing trend is real, there may be significantly more energy available from the Project than
originally expected (as much as 25% more).
2. The project as currently licensed has an active storage capacity of 553 acre-feet, which will provide
for about 1.5 GWh of firm generation during the winter and an average annual generation of about
20.1 GWh. If the reservoir is raised to El 900 (approximately the maximum practical raise), the
active storage would increase to 4,390 acre-feet, the firm winter generation would increase to
about 4.8 GWh, and the average annual generation would increase to about 21.4 GWh.
3. The 25 TJ HCTI turbine is probably a better choice than the 28 TJ HCTI turbine if the reservoir is not
raised due to its better efficiency at lower flows. If the lake is raised, low discharges will occur less
frequently, and the 28 TJ HCTI may be the better choice.
4. Neither turbine will be able to produce 5,000 kW at the licensed hydraulic capacity of 90 cfs. The
license should be amended to increase the hydraulic capacity, and Gilkes should be requested to
modify their proposal accordingly. We would not expect any significant environmental concerns
with an increased hydraulic capacity, and the licensed generating capacity would not change (i.e. it
would be a non-capacity amendment). The generating unit cost might increase due to an increase in
the generator rating however.
Page 2 AP&T Solutions
193 Otto Street PO Box 3222
Port Townsend, WA 98368
360.385.1733 / 800.982.0136
Email: aptsolutions@aptalaska.com
COMPUTER MODEL
The computer model used for the operations studies was derived from a model written for
Project, with the following modifications:
Inclusion of both a bypassed reach instream flow requirement (BRIFR) and an
anadromous reach instream flow requirement (ARIFR)
Calculation of both firm generation and average annual generation. Firm generation is
that available each year of the hydrologic record.
The primary input to the model is the 13-year record of average daily flows recorded by the
, as discussed below. For each day of the record, the model
performs the following calculations:
Calculate the BRIFR and ARIFR based on the month and the lake inflow (as currently licensed,
the Project is not required to release more than the lake inflow).
Calculate the daily average load based on an assumed load shape.
Calculate the power plant discharge required to meet the average daily load by an iterative
procedure.
Calculate the power plant discharge to utilize the releases for the ARIFR and to minimize spill.
Calculate the power output associated with each of the two discharges described immediately
above, based on the turbine, generator, transformer, transmission, and penstock efficiencies.
Calculate the water level and spill, if any, due to the inflows, power plant releases, and instream
flow releases by an iterative procedure.
Summarize the primary output in monthly tables.
HYDROLOGY
The operations studies conducted for the license application used the flow record from USGS
gage 15081995 (Reynolds Creek below Lake Mellen). The available record was only for 8 years
(water years 1952-56 and 83-85). That gage was reinstalled in 1997 and discontinued in 2003,
so there are now 5 more complete water years of data available (13 years total). Although 13
years is not a long record and it is not continuous, we believe it provides a reasonable basis for
the operations studies. We have done some preliminary work on correlating the Reynolds
Creek flow record with those of other nearby gages, and the results are not very promising.
For the three periods of record, the average annual streamflows are as follows:
WY 1952-1956 56.9 cfs
WY 1983-1985 66.7 cfs
WY 1998-2003 73.8 cfs
These average annual flows are significantly different, with an increasing trend. At this time,
we cannot say whether the difference is due to precipitation differences or to data quality. We
Page 3 AP&T Solutions
193 Otto Street PO Box 3222
Port Townsend, WA 98368
360.385.1733 / 800.982.0136
Email: aptsolutions@aptalaska.com
note that the USGS currently does not make the WY 1952-56 data available for download from
its website, which may indicate concerns about the data quality. The flow record for the USGS
gage on Old Tom Creek near Kasaan (which has a long record) shows a similar increasing trend,
but the long-term record for Staney Creek near Craig does not show any appreciable increasing
trend (see Figure 1). The best precipitation station in the area (on Metlakatla) also does not
show a significant increasing trend. Thus, we cannot say whether the increasing trend in the
Reynolds Creek record is legitimate, but it is an important consideration because use of the
older data results in reduced expectations for firm energy.
GENERATING UNIT EFFICIENCIES
The model uses the efficiency data for two models of Gilkes Turgo generating units; separate
studies have been conducted for each. As there is only a very small change in the generating
head between maximum and minimum reservoir level relative to the overall head, the
efficiency is assumed to vary only with the discharge. Also, the same efficiency curve was
utilized for all reservoir sizes, as the Gilkes efficiency curves indicate there would be a negligible
changes with the slightly higher head of the larger reservoir sizes. The assumed turbine
efficiency curves are shown in Figure 2.
Also shown in Figure 2 are curves of the overall efficiency, which includes the turbine efficiency
and the following:
Generator efficiency (varies with turbine output, from about 90% to 96%, as estimated by
Gilkes)
Transformer efficiency of 99.0%.
Transmission losses of 2.0%
Penstock head losses, as discussed below.
PENSTOCK HEAD LOSS
Penstock head losses are based on the penstock design as submitted for FERC approval in 2010,
¼ to ½ inch.
3.0 (times the velocity head) is assumed to account for intake, valve, and bend losses.
GENERATION PATTERN
The need for additional energy on POW is primarily in the winter and spring months when the
storage in Black Bear Lake is depleted. The operation studies assume that the Project storage is
utilized to provide a constant level of generation from December through April; the generation
level that lowers the reservoir completely just once during the period of record was found by
iterative runs of the model. Secondary generation is calculated from additional releases
required for the ARIFR and to minimize spills once the Project reservoir is full.
Page 4 AP&T Solutions
193 Otto Street PO Box 3222
Port Townsend, WA 98368
360.385.1733 / 800.982.0136
Email: aptsolutions@aptalaska.com
RESERVOIR CHARACTERISTICS
The operation studies conducted for the license application assumed storage in the existing
lake at 150 acre-feet per foot - - i.e., no surface area variation with elevation. That was a
reasonable assumption with the very limited elevation change proposed in the license (4 feet
maximum). For the current studies, the reservoir area-capacity curve was developed from the
topography of the USGS National Elevation Dataset as well as the USGS topographic maps. The
area-capacity curve is shown in Figure 3.
The operations studies have assumed that the reservoir is held as full as possible at all times,
i.e. a rule curve type of operation has not been modeled. Use of a rule curve might allow for a
small increase in the average annual generation by decreasing spill, but no gain in firm energy
would result.
Spillway discharge has been calculated from the equation Q=69*H1.5+7*H2.5, which assumes a
23 feet wide rectangular weir with a 3.0 crest coefficient plus a V-notch weir with 3H:1V slopes.
This closely approximates the spillway discharge curve shown in the HDR Supporting Design
Report for the Project.
OPERATIONS STUDIES RESULTS
Six cases have been evaluated, representing three different reservoir sizes and two turbine
sizes. The three reservoir sizes assumed are as follows:
Case 1 As currently licensed (553 ac-ft of storage between El 872 and El 876)
Case 2 Reservoir raised 14 feet (2,693 ac-ft of storage between El 872 and El 890)
Case 3 Reservoir raised 24 feet (4,390 ac-ft of storage between El 872 and El 900)
The winter firm energy, annual firm energy, annual energy values for dry, average, and wet
years, and the maximum power output as determined by the operations studies for the six load
cases are summarized in the following Table 1 and in Figures 4-7:
Winter firm energy is the energy available from the project during the months of November-
April in all 13 years of the operation study.
Minimum firm energy is the sum of the lowest monthly generation amounts
Dry year energy is the average of the generation amounts during the two lowest years (1952
and 1956)
Average year energy is the average of the generation amounts during all 13 years
Wet year energy is the average of the generation amounts during the two highest years (2000
and 2001)
Maximum power is the power delivered into the POW grid when the project is operating at 90
cfs and the reservoir is at the spillway crest elevation.
Page 5 AP&T Solutions
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Table 1
Annual Generation Summary
Reservoir storage 25 TJ HCTI Turbine 28 TJ HCTI Turbine
Maximum El 876 (553 ac-ft)
Winter firm energy
Minimum firm energy
Dry year energy
Average year energy
Wet year energy
Maximum power
1,522 MWh
6,048 MWh
14,509 MWh
20,106 MWh
25,760 MWh
4,311 kW
1,268 MWh
5,789 MWh
14,497 MWh
20,318 MWh
26,141 MWh
4,423 kW
Maximum El 890 (2,693 ac-ft)
Winter firm energy
Minimum firm energy
Dry year energy
Average year energy
Wet year energy
Maximum power
3,559 MWh
8,000 MWh
15,573 MWh
20,689 MWh
26,282 MWh
4,394 kW
3,494 MWh
7,896 MWh
15,657 MWh
20,939 MWh
26,676 MWh
4,507 kW
Maximum El 900 (4,390 ac-ft)
Winter firm energy
Minimum firm energy
Dry year energy
Average year energy
Wet year energy
Maximum power
4,798 MWh
9,307 MWh
16,303 MWh
21,105 MWh
26,670 MWh
4,453 kW
4,787 MWh
9,258 MWh
16,422 MWh
21,370 MWh
27,075 MWh
4,567 kW
Monthly generation values are shown in Figures 8-11. Figures 8-10 show the minimum firm
energy, dry year energy, average year energy, and wet year energy for the three reservoir
storages evaluated (one reservoir storage per figure) for both the 25 TJ HCTI turbine (solid lines)
and 28 TJ HCTI turbine (dashed lines). Figure 11 shows the dry year energy and average year
energy for the three reservoirs for the 25 TJ HCTI turbine. This last figure may best illustrate
the benefit from increasing the reservoir storage.
DISCUSSION
1. One notable conclusion of these operations studies is that with the maximum discharge
limited to 90 cfs as specified by the FERC license, neither generating unit will provide 5,000 kW
of output, even with a higher reservoir. The Gilkes turbine information suggests that both the
25 TJ HCTI and 28 TJ HCTI turbines should be about to discharge at least 100 cfs, so the actual
maximum power available should be at least 10% greater than shown above. If the license is
amended to increase the reservoir capacity, it should also be amended to increase the hydraulic
capacity to at least the flow required to produce 5,000 kW.
Page 6 AP&T Solutions
193 Otto Street PO Box 3222
Port Townsend, WA 98368
360.385.1733 / 800.982.0136
Email: aptsolutions@aptalaska.com
2. The studies suggest that the 25 TJ HCTI turbine may be a better choice than the 28 TJ
HCTI if the reservoir capacity is not increased. This is because with a small reservoir there will
be more operation in the low flow range during the winter, where there is an efficiency
advantage for the 25 TJ HCTI turbine. The 28 TJ HCTI turbine may have an advantage if the
reservoir is increased, as there will be more operation in the mid- and high-flow range where its
higher efficiency is advantageous.
3. The existing license allows the Project to release less than the instream flow
requirements if the inflow to Lake Mellen is less than the instream flow requirements, i.e. run-
of-river operation is allowed during low flow periods and the limited storage in Lake Mellen
does not need to be used to support the instream flow requirements. The operations studies
have assumed that those same conditions would apply with the larger reservoirs. This may be
wishful thinking. The resource agencies may want the storage to be utilized to support the
minimum flows as mitigation for fisheries losses that might occur in Lake Mellen with an
increased reservoir.
4. With the licensed reservoir capacity (which only supports a small release for firm
power), it was found that if the Lake Mellen inflows were between 12 and 21 cfs, the release
for generation would calculate to less than the minimum flow capability of the turbine
(assumed to be 9 cfs, in accordance with information from Gilkes). This rare situation was
addressed by forcing the model to release at least the minimum flow capability of the turbine
when firm energy was requested.
5. These operations studies indicate a significantly higher average annual generation
potential than previous studies for the license application. The difference can be attributed to
the current studies incorporating the 1998-2002 streamflow data, which is significantly higher
than the 1952-56/1983-85 data.
6. As noted earlier, the hydrology data appears to show an increasing trend, and use of the
full period of data may lead to erroneously low expectations for firm energy. To illustrate, we
have made one run based on winter firm energy during the 1998-2003 data period for the
highest reservoir and the 28 TJ HCTI turbine; the winter firm energy was found to be 8,154
MWh, an increase of 70%. The average annual energy was found to be 24,202 MWh, an
increase of 13%.
7. Computer simulations can overstate generation by assuming ideal modes of operation,
e.g. release of exactly 12 cfs for the BRIFR, when in reality there will be a tendency to release
slightly more to avoid compliance problems, or holding the reservoir slightly below the spillway
crest to avoid loss of water from waves or control equipment accuracy. In addition, no
reductions have been taken for loss of generation during outages or for station service usage.
Thus, the values provided in this report represent the maximum attainable generation, and
actual generation will probably be slightly less. The difference should be less than 5%.
Page 7 AP&T Solutions
193 Otto Street PO Box 3222
Port Townsend, WA 98368
360.385.1733 / 800.982.0136
Email: aptsolutions@aptalaska.com
If you have any questions regarding this report, please call me at (360) 385-1733, Ext. 155.
Sincerely,
AP&T Solutions
Larry D. Coupe
Senior Engineer
0 24 6 8 10 12 14 16 18 1950 1955 1960 1965 1970 1975 1980 1985 1990 1995 2000 2005 2010 2015 Unit flow, cfs/sm Year Figure 1 Average Annual Flow Comparison OLD TOM CREEK STANEY CREEK REYNOLDS CREEK Linear (OLD TOM CREEK) Linear (STANEY CREEK) Linear (REYNOLDS CREEK)
40.00%50.00%60.00% 70.00% 80.00% 90.00% 100.00% 0 10 20 30 40 50 60 70 80 90 100 Efficiency, % Turbine Discharge, cfsFigure 2 Turbine and Overall Efficiencies 25 TJ HCTI Turbine Efficiency 28 TJ HCTI Turbine Efficiency Overall Efficiency with 25 TJ HCTI Turbine Overall Efficiency with 28 TJ HCTI Turbine Note: Overall efficiency includes penstock and transmission losses as well as turbine, generator, and transformer efficiencies. Turbine and generator efficiency data from Gilkes 2/28/2012 comparison analysis.
Normal Maximum Reservoir Elevation, feet
870875880885 890 895 900 905 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 5,000 Normal Maximum Reservoir Elevation, feet November-April Firm Energy, MWh Figure 4 Winter Firm Energy 25 TJ HCTI Turbine28 TJ HCTI TurbineNote: Winter firm energy is the specifiedDecember through April generation that utilizes all of the reservoir storage once during the period of record.
870875880885 890 895 900 905 13,000 13,500 14,000 14,500 15,000 15,500 16,000 16,500 17,000 Normal Maximum Water Surface Elevation, feet Annual Firm Energy, MWh Figure 5 Annual Firm Energy 25 TJ HCTI Turbine28 TJ HCTI TurbineNote: Annual Firm Energy is the minimum annual generation during the period of record
870 875 880 885890 895 900 905 20,000 20,200 20,400 20,600 20,800 21,000 21,200 21,400 21,600Normal Maximum Water Surface Elevation, feet Average Annual Generation, MWh Figure 6 Average Annual Generation 25 TJ HCTI Turbine 28 TJ HCTI Turbine
870 875 880 885 890 895 900 905 4,250 4,300 4,350 4,400 4,450 4,500 4,550 4,600 Normal Maximum Water Surface Elevation, feet Maximum Power, kW Figure 7 Maximum Power 25 TJ HCTI Turbine 28 TJ HCTI Turbine Note: Values are for power delivered to the POW transmission system, and include transmission losses as well as turbine, generator, and transformer efficiencies.
0500,0001,000,0001,500,000 2,000,000 2,500,000 3,000,000 October November December January February March April May June July August September Monthly Generation, kWh FIGURE 8 MONTHLY GENERATION - - LICENSED RESERVOIR (SPILLWAY EL. 876) Wet Year (25) Average Year (25) Dry Year (25) Minimum Firm (25) Wet Year (28)Average Year (28)Dry Year (28)Minimum Firm (28)
0 500,000 1,000,000 1,500,000 2,000,000 2,500,000 3,000,000 October November December January February March April May June July August September Monthly Generation, kWh FIGURE 9 MONTHLY GENERATION - - RAISED RESERVOIR (SPILLWAY EL. 890) Wet Year (25)Average Year (25)Dry Year (25)Minimum Firm (25)Wet Year (28) Average Year (28) Dry Year (28) Minimum Firm (28)
0 500,0001,000,000 1,500,000 2,000,000 2,500,000 3,000,000October November December January February March April May June July August September Monthly Generation, kWh FIGURE 10 MONTHLY GENERATION - - RAISED RESERVOIR (SPILLWAY EL. 900) Wet Year (25)Average Year (25)Dry Year (25)Minimum Firm (25)Wet Year (28) Average Year (28) Dry Year (28) Minimum Firm (28)
0 500,0001,000,000 1,500,000 2,000,000 2,500,000 3,000,000October November December January February March April May June July August September Monthly Generation, kWh FIGURE 11 MONTHLY GENERATION - - DRY AND AVERAGE YEARS Average Year - El 900 Average Year - El 890 Average Year - El 876 Dry Year - El 900 Dry Year - El 890 Dry Year - El 876