Header Reasonableness Test RT 011/11 Northfield to Ingle Farm #2 66 kv Sub transmission line RT011-11 Northfield to Inglefarm Page 1 of 8
Reasonableness Test: Northfield to Ingle Farm 66 kv line DISCLAIMER The purpose of this document is to inform customers, Interested Parties, Registered Participants and solution providers of the outcome of the application of the Reasonableness Test to the network constraint of overload of the Northfield to Ingle Farm 66kV sub transmission line. This document is not intended to be used for other purposes, such as making decisions to invest in generation, transmission or distribution capacity. This document has been prepared using information provided by, and reports prepared by, a number of third parties. While care was taken in the preparation of the information in this paper, and it is provided in good faith, ETSA Utilities accepts no responsibility or liability for any loss or damage that may be incurred by any person acting in reliance on this information or assumptions drawn from it. This Reasonableness Test has been prepared in accordance with section 3 of ESCOSA Guideline 12 Demand Management for Electricity Distribution Networks for the purpose of consulting with Registered Participants, Interested Parties and customers regarding a potential network augmentation. The Reasonableness Test has been prepared with consideration for pertinent information provided by a number of third parties. It contains assumptions regarding, among other things, economic growth and load forecasts that, by their nature, may or may not prove to be correct. ETSA Utilities advises that anyone proposing to use this information should verify its reliability, accuracy and completeness before committing to any course of action. ETSA Utilities makes no warranties or representations as to its reliability, accuracy and completeness and ETSA Utilities specifically disclaims any liability or responsibility for any errors or omissions or not. It is important to note that ETSA Utilities as Distribution Network Service (DNSP) provider can only consider benefits available to the DNSP in evaluating the viability of Demand Management initiatives, e.g. transmission benefits, the possibility of reducing spot market prices and wider benefits like reducing green house gasses have not been considered. Page 2 of 8
N-1 Load - MVA Reasonableness Test: Northfield to Ingle Farm 66 kv line GUIDELINE 12 REASONABLENESS TEST Northfield to Ingle Farm #2 66kV sub transmission line 1. CURRENT SUPPLY ARRANGEMENT The Ingle Farm, Golden Grove, Tea Tree Gully and Hope Valley substations are currently supplied by a 66kV sub transmission line loop from Northfield and Holden Hill substations. Northfield is a Transmission Connection Point and at Holden Hill there are multiple sources of supply. The overall supply arrangement is shown in Figure 2 Northfield to Holden Hill 66kV loop on the next page. Following an outage of the Northfield to Ingle Farm line the Holden Hill - Hope Valley Tea Tree Gully line will be required to support all four substations within the loop and will be overloaded from 2013/14 as the maximum projected load of 168 MVA will exceed the 156 MVA emergency rating of the Holden Hill - Hope Valley Tea Tree Gully line as illustrated in Figure 1. This may require up to 12MVA or 3,235 customers to be involuntarily shed. The typical repair time for an overhead 66kV line fault is 12 hours, and for a 66kV underground cable fault is 10 days. A smaller, but similar constraint also exists on the Northfield to Ingle Farm line following the loss of the Holden Hill to Tea Tree Gully line. The reduced level of overload is due to the automatic loss of Hope Valley substation. 2. FORECAST LOAD AND CAPACITY Forecast diversified load in the Northfield to Holden Hill loop is growing at between 3 MW and 4 MW per year or just over 2% per annum corresponding to the typical Eastern Suburbs load growth. Individual substation growth in the loop ranges from 1.5% pa. at Ingle Farm to 3% pa. at Hope Valley. There is a 3.3 MW generation plant connected at Hope Valley. 185 Holden Hill to Tea Tree Gully Line Constraint 180 175 178 182 170 171 175 165 168 160 161 164 155 150 145 140 2011/12 2012/12 2013/14 2014/15 2015/16 2016/17 2017/18 Summer Line capacity N-1 Line Load Figure 1 N-1 Load (MVA) versus capacity Page 3 of 8
Reasonableness Test: Northfield to Ingle Farm 66 kv line Figure 2 Northfield to Holden Hill 66kV loop Page 4 of 8
Load Reasonableness Test: Northfield to Ingle Farm 66 kv line 3. LOAD CHARACTERISTICS The load on the Northfield to Holden Hill loop is mainly residential with substations at Golden Grove, Hope Valley and Tea Tree Gully peaking coincidentally at approximately 18:00 on a peak day. The load at Ingle Farm is more commercial and has a slightly earlier peak. This means that the peak period of the N-1 load on the loop is wider than normal for the Eastern Suburbs supply system with load in excess of 85% of peak occurring over an 8 hour period from 14:00 to 22:00 on a typical hot day. The load is very sensitive to temperature with peak loads only occurring at temperatures in excess of 37 o C. There is also a slightly greater likelihood for such peaks to occur on weekdays over weekends however, this effect is dominated by the impact of the temperature. This peak can be seen on the daily load curve (see Figure 3) for 31 st January 2011 when the temperature in the Eastern Suburbs reached 42 o C. The Northfield to Ingle Farm line was fairly flat from 14:00 to 20:00 reflecting the commercial component of the load at Ingle Farm, whereas the Holden Hill to Tea Tree Gully line is steeper and peaked later, at between 19:00 and 21:00. The composite curve representing the N-1 load is simply both of these lines added together with no allowance made for the likely increased system losses that would occur under these circumstances. The load duration curve (Figure 4) illustrates the extreme temperature dependence of the load with 95% of the load occurring for less than 8 hours of the year and 85% of the load for less than 21 hours of the year. However in a hot year, similar to that experienced in 2009, the number of hours at each threshold would be expected to rise above those of the relatively mild summer of 2010-2011. Northfield to Ingle Farm Daily Load Curve 31st January 2011 140 120 100 80 60 40 20 0 0:00 2:00 4:00 6:00 8:00 10:00 12:00 14:00 16:00 18:00 20:00 22:00 Time of day Northfield to Inglefarm Holden Hill to TeaTree Gully N-1 Figure 3 Daily Load Curve Northfield to Ingle Farm 31st January 2011 Page 5 of 8
% Load Reasonableness Test: Northfield to Ingle Farm 66 kv line Northfield to Ingle Farm 1st July 2010 to 30th June 2011 100 90 80 70 60 50 40 30 20 10 0 0 10 20 30 40 50 60 70 80 90 100 % Time Northfield to Inglefarm Figure 4 Load Duration Curve Northfield to Ingle Farm 2010-11 4. NETWORK UPGRADE OPTIONS Options that have been investigated to resolve these potential overloads at time of peak load include the following: Install a new 66kV Line from Northfield to Ingle Farm utilising part of a former 132 kv transmission corridor. This project has the benefit of relieving load off the Holden Hill to Hope Valley, Hope Valley to Tea Tree Gully and Northfield to Holden Hill 66kV Lines in the event of loss of the existing Northfield to Ingle Farm 66kV Line, while relieving load off the existing Northfield to Ingle Farm 66kV Line in the event of loss of the Holden Hill to Hope Valley and/or Hope Valley to Tea Tree Gully 66kV Line; or Construct a new 66kV Line from Northfield to Tea Tree Gully. This project has the benefit of increasing the capacity of the existing network to prevent line overloads at times of an outage of the existing Northfield to Ingle Farm 66kV line. Preferred Network Solution The preferred solution, when the net present value, timing and effectiveness of related upgrade projects is considered, is to construct a new 66kV overhead Line from Northfield to Ingle Farm Substation. The indicative cost of this project is between $5 million and $7 million. It is planned for completion in 2013. 5. DEMAND MANAGEMENT ANALYSIS 5.1 Required Demand Management Characteristics Any Demand Management solution must be available on hot summer afternoons between 16:00 and 21:00 and should deliver the firm capacity as outlined in Table 1 below, starting at 12 MW s in 2013 and growing by 3-4 MW s a year. The solution is required to be operational prior to an outage as the level of overload on this line is such that if it occurs, then customers would need to be immediately shed. Page 6 of 8
Reasonableness Test: Northfield to Ingle Farm 66 kv line It is expected that the overload will occur only during heat waves when there is a sustained period in excess of 37 o C. This limits the likely occurrence to no more than several days a year. 5.2 Demand Management Value The following table indicates the amount of load reduction required in each year and the available $/kva amount available to make Demand Management viable. To allow for oversubscription in order to guarantee the load reduction required, a range of deferral benefit values are provided. The stated benefits also include an allowance to cover administrative costs. Year Table 1 $ per kva available for Demand Management Load Reduction Required (kva) Typical number of Days at Risk $/kva available per year for DM 2013/14 12,000 1 20-36 2014/15 15,000 1 18-30 2015/16 19,000 2 15-25 5.3 Demand Management Options Considered Various Demand Management technologies were considered to determine their viability to assist in reducing the demand in the constrained area. These DM options were evaluated for both technical feasibility as well as cost effectiveness. 5.3.a Standby diesel generators Establish contracts with customers who have standby diesel generators on their premises and utilise the generators at peak load times. Given the size of the overload (12 MVA+) and the very low dollars per kva available as an incentive payment; there is no possibility of securing sufficient third party generation to delay the requirement for a second line. 5.3.b Install power factor correction There is already sufficient capacitance installed at Golden Grove substation to provide the required reactive requirements of the line under N-1 conditions. There is therefore no advantage in installing further power factor correction within the region. 5.3.c Retrofit commercial lighting with efficient lighting. Upgrade existing commercial fluorescent lighting to T5 lighting. Based on the upgrade of a 400W fluorescent bank with a 2x 80W efficient bank provides the equivalent lumen output. The demand saving per bank is 240W. The estimated cost for this option is $2,500/kVA. Significant disruption to the customer while the retrofit is carried out can be expected, which may influence the number of willing participants. 5.3.d Peak load control direct load control Direct load control technology may be available where tripping many small air conditioning units supplied from a single distribution transformer can be performed. Recent experiences have shown the costs to range from $300 to $800/kVA. Page 7 of 8
Reasonableness Test: Northfield to Ingle Farm 66 kv line 5.3.e Peak load control curtailable load This requires establishing a contract with one or more large customers to turn the power supply off to part of their business or to shift their load to off peak times. Given the size of the load required to be shifted or shed and the low dollars per kva available this is not practicable in this case. 5.3.f Residential compact fluorescent lamp (CFL) program This option was is not relevant due to peak load conditions occurring in daylight hours. Load contribution from residential housing lighting during daylight hours is believed to be minimal. 5.3.g Thermal storage systems A trial installation at a suitable site revealed a saving in load of 150kVA with an expected cost ranging between $1,000 and $1,600/kVA. Smaller scale installations have also been trialled, and are still very much in the development stage (More expensive per kva). 5.3.h Energy Storage Use of energy storage technology such as flow batteries is typically in the order of $6000 per kva. 6. CONCLUSION Based on the Demand Management options considered it is not likely that sufficient Demand Management could be implemented to achieve a demand reduction to make project deferral technically and economically viable. The constraint on the Holden Hill Hope Valley Tea Tree Gully line has failed the Reasonableness Test and a Request for Proposal (RFP) will not be issued. Page 8 of 8