590F EE Course Project, Due Dec 12, 2008 A. Transmission Planning: The objective of Part A of this project is to design a least-cost transmission 30-year plan for the US capable of moving electric energy from the wind-intense regions to major load centers. Although it represents an extreme scenario, it offers a data point that may well characterize upper-bound needs for major transmission infrastructure investments. You should use Plexos. The following information is given to help guide you. 1. You should read the AEP article, Interstate Transmission Vision for Wind Integration, available on the course
website. This article, at its end, illustrates a possible design. In designing your own transmission system, you might consider the AEP design and the reasons for its configuration.
2. Data on available transmission technologies are given in Table 1 below. Blanks indicate either not applicable
or that no data was identified. You may have access to additional or alternative data, and if you do, and if you trust it, feel free to use it. Alternatively, if you need data not given below and can find no sources, you may estimate it. Table 1 X (AC) or R (DC) ( /mile) SIL** (MW) 9-12 10-40 40-50 50-120 120-130 130-440 390 0.5925@ 0.5 1000 1300 ! 1100 ! 0.5069 0.4724 0.4 0.4787@ 0.0129 (/pole) 2250 2250 4000 5180>| 2400 3150/ 6400 HVDC Rating (Mw) Cost (million$)/mil e Cost
Equipment 69 kV sngl cct (SC) 69 kV HSIL 138 kV SC 138 kV HSIL SC 230 kV AC SC 230 kV AC HSIL SC 345 kV AC SC 345 kV AC dble cct (DbC) 500 kV AC SC 500 kV AC DbC 500 kV AC HSIL SC, 6bdl 500 kV AC HSIL DbC, 4bdl 765 kV AC, SC, 4bdl 765 kV AC, SC, 6bdl 765 kV AC HSIL SC 1100 kV AC SC 500 kV DC converters+ 500 kV DC Line 600 kV DC converters+ 600 kV DC Line 800 kV DC converters+ 800 kV DC Line
1.59* 2.65* 1.8* 3.38* 2.0* 2.5* 2.86* 3.3*~ 4.32* $131/kW< | 1.8 $200/kW 2.03*^ $250/kW 3.62*^
* 2008 dollars. +Bipole configuration assumed, with converter costs including both poles at both ends of line. ^ Estimates based on the rule of thumb that the cost of a DC transmission line may be 80% to 100% of the cost of an AC line whose rated line
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voltage is the same as the rated pole-to-ground voltage of the DC line. @These estimates came from 1984 paper by Scherer & Vassell. ~These estimates came from AEP planning engineers. ! Data came from slides by A. Dariani, Canada. >| These estimates came from the 1979 AEP paper by Dunlop, Gutman, and Marchenko. /This data comes from existing 600 kV line in Brazil (Itaipu). <| These costs came from presentation by ABB engineer Michael Bahrman. These were computed based on: 4bdl 1.5 diam bdl, Dipper - between Pheasant and Bobolink (Xa=.045), 45 phase spacing (Xd=.4619); 6bdl 2.5 square bdl, Tern (Xa=.0105.), 45 phase spacing (Xd=.4619). Estimated by Dr. McCalley. **SIL for double circuit lines is for one line only, and so capacity estimates should be based on twice the given amount.
3. Assume that each AC substation requires 1 transformer, and also, for each line terminating at the substation, 1
circuit breaker. Transformer and circuit breaker costs are given in Table 2 below. Costs for 345, 500, and 765 kV circuit breakers and transformers are taken from the 1990 Panel-Working Group paper on AC-DC economics chaired by Diemonds (escalated to account for inflation, given in 2008 dollars). All other costs are estimated. Table 2 Circuit breakers Transformer Voltage control eqpmnt 345 kV $1.07 million $5million $2.6 million 500 kV $2.14 million $6.4 million $3.3 million 765 kV $2.71 million $8.5million $4.0 million 1100 kV $4.5 million $12 million $6 million
4. Initial year 2008 national peak load, 810 GW, is allocated by region as shown in Table 3 below. Initial year
2008 national generation capacity, 909 GW, is also allocated by region in the Table. In addition, percent capacity among fuels is also indicated by region. This data comes from the NERC 2007 Long-Term Reliability Assessment, with exception of the Western Systems data, which is adapted from the PhD dissertation by A. Quelhas, (ISU, 2006).
Table 3 Region* Total 1.ERCOT 2.FRCC 3.MRO 4.NPCC 5.RFC 6.SERC 7.SPP 8. NW 9. CAL 10. SW 11. RM Peak Load (GW) 810 67 48 44 64 190 210 44 53 51 25 15 Capacity (GW) 909 72 54 50 70 214 230 49 63 60 29 18 Percent of Capacity For Each Generation Technology Nuclear Coal NGCC+ CT+ Hydro Wind Oil ** 7 8 8 14 15 16 1.4 2 8.3 14.8 0 22.1 19.5 66.5 9.3 48.1 44.1 43 20 1 38.4 67 55.1 41.5 13.5 36.3 20.1 17 39.9 6.6 46.4 23.4 13 10.1 8.5 7.4 8.4 7.1 6.3 7 3.7 13.8 7 5 1.1 0.1 7.5 12.4 3.0 10 4.7 67 26.9 16 10 0.3 0 0.3 0.04 0.04 0 0.01 0.7 2.8 0 1.1 5 22.5 8 18.4 7 7 4 0.2 1.5 1 1.3
*Only Continental US load and capacity data included in this table, i.e., no Canadian or Mexican load or capacity is included, and Hawaii & Alaska are excluded. ** Includes pumped storage. +The NERC data specifies all natural gas-consuming technologies under the single category of Gas, which is the total of CT and NGCC here. Thus, the total is considered to be accurate whereas the split is an estimate.
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5. The regions listed in Table 3 are shown in Fig. 1. Assume all load and generation for each region are located at a
single node in the middle of the square identifying the regions number.
8 1 1 9 1 0
4 3 5 7 6 2
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Fig. 1
6. The various generation technologies have the following data. Table 4 Technology Heat Rate MBTU/MWhr Pulverized Coal NGCC CT Hydro Wind Oil IGCC IGCC w/CarbSeq Solar 10.4 9.2 7.5 10.8 0 0 10.1 8.765 10.781 0 Data Values Investment Cost $/kW 2475 1534 706 500 N/A 1434 N/A 1733 2537 5649 Emission Rate lbs CO2/MBTU 0 215 117 117 0 0 162 199 20 0
7. Locationally variable data, for fuel prices and for wind/solar capacity factors, are given in Tables 5 and 6. These
data can be assumed to remain constant through time (an assumption worth exploring for fuel prices). 5 Table Region 1.ERCOT 2.FRCC Coal Fuel Prices, $/MBTU Natural Uraniu Gas m 1.90 7.00 0.75 1.95 8 0.75 Oil 12.00 12.00
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3.MRO 4.NPCC 5.RFC 6.SERC 7.SPP 8. NW 9. CAL 10. SW 11. RM
1.80 1.90 1.80 1.85 1.80 1.80 1.95 1.80 1.70 Table 6
8 9 8.5 8 7.5 8 8 8 8
0.75 0.75 0.75 0.75 0.75 0.75 0.75 0.75 0.75
12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00
Region 50 1.ERCOT 2.FRCC 3.MRO 4.NPCC 5.RFC 6.SERC 7.SPP 8. NW 9. CAL 10. SW 11. RM 40 x Wind 30 x x x x 20
Capacity Factors 10 25 22 x x x x x x x x x x x x x x x x Solar 20 x 15 10
8. Assume an annual load growth of 1.5% for all areas. A file is provided on the website that contains the 30 year
load at each node.
9. Assume there is no existing transmission interconnecting the regions at the initial 2008 year. This assumption
can be interpreted to indicate that although existing transmission will be used to perform inter-regional transfer for 2008 load levels, it will not be used to perform inter-regional transfer for additional load above 2008 levels.
10.Design a transmission system over a 30 year period that will accommodate the following:
Non-wind generation is replaced at a rate to exactly compensate for retirements of non-wind generation. Thus, you can assume non-wind generation capacities do not change over the entire 30 year period, so that all load growth is compensated only by wind growth. Assume storage technologies for wind farms (pumped storage, compressed air, hydrogen generation for fuel cells) mature enough so as to model wind capacity factors at 40% the values given in Table 6, and capacity credit at 25%. Note that capacity credit is used as follows: Reserve=0.12=( Cap_i -Load)/Load For all units except wind, Cap_i=Unit Capacity For wind units, Cap_i=(Capacity Credit)*Unit Capacity
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The national grid must maintain a 12% reserve (total capacity must be 12% greater than peak load). Every unit of national wind growth is split between the regions according to Table 7: Table 7 Region % 1.ERCOT 10 2.FRCC 5 3.MRO 25 4.NPCC 9 5.RFC 9 6.SERC 4 7.SPP 20 8.NW 5 9.CAL 6 10.SW 1 11.RM 6 Your transmission system must meet the following requirements:
a. Its cost should not exceed $60 billion (the cost of the AEP plan); the lower, the better. b. Emergency operation is defined by loss of one AC line or bipole loss of one DC line. Flows for 150
mile-long AC lines must be within 1.0 SIL under normal conditions and 1.5 SIL under emergency conditions. Lines significantly shorter or longer than 150 miles should have their ratings adjusted based on the Fig. 2 left-plot for lines of voltage class 500 kV or less, and based on the Fig. 2 right-plot for lines of voltage class 765 kV or above. These plots came from the 1979 AEP paper by Dunlop, Gutman, and Marchenko. (Substation placements incur significant costs, per the data in Table 2 above; however, voltage control devices, which can only be placed at substations, have the effect of terminating the line, limiting the length, and therefore preventing line capacity reduction characterized by Fig. 2.)
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Fig. 2
11. You should turn in the following:
A summary of the data you used together with the source of each data item. If any data was estimated without a source, indicate as much. Provide reasoning supporting your estimate. One or two tables summarzing by year the peak load and wind generation capacity for each region. Identification of new transmission to be built (type, distance, capacity, sub locations), & when. The net-present ...