Te Aponga Uira Final Energy Storage Feasibility Study€¦ · Energy Storage Feasibility Study 7...

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Te Aponga Uira Final Energy Storage Feasibility Study

Prepared by: KEMA Australia Pty Ltd Level 9, 189 Kent Street Sydney NSW 2000 T: +61 2 8243 7700 F: +61 2 9241 3998 Submitted to:

Te Aponga Uira Cook Islands KEMA Australia Pty Ltd

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Te Aponga Uira Proprietary Energy Storage Feasibility Study 7 September 2012

Table of Contents 1. Executive Summary ............................................................................................................. 1 2. Objectives and Overview...................................................................................................... 3 3. Overview of TAU and Rarotonga .......................................................................................... 4

3.1 The TAU Network ....................................................................................................... 4 3.2 Conventional Units ...................................................................................................... 4 3.3 Planned Upgrade ........................................................................................................ 5 3.4 The Government’s Renewable Energy Plan ............................................................... 6

4. Renewable Activities ............................................................................................................ 7 4.1 Experience with Net Metering ..................................................................................... 7 4.2 Renewable resources to date ..................................................................................... 8

4.2.1 Solar resource ................................................................................................. 8 4.2.2 Wind resource ................................................................................................. 9

4.3 Planned Utility Scale projects .................................................................................... 10 5. Existing situation ................................................................................................................ 11

5.1 Recent Sales ............................................................................................................ 11 5.2 Load and Energy Forecast ........................................................................................ 11 5.3 Load Shape .............................................................................................................. 13 5.4 Need for base load capacity ...................................................................................... 15

6. Storage Technologies ........................................................................................................ 16 6.1 Overview ................................................................................................................... 16 6.2 Technologies considered .......................................................................................... 17

6.2.1 Flywheels ...................................................................................................... 17 6.2.2 Pumped hydro storage .................................................................................. 18 6.2.3 Batteries ........................................................................................................ 19 6.2.4 Thermal energy storage ................................................................................ 21 6.2.5 Compressed Air Energy Storage ................................................................... 21

6.3 Costs ........................................................................................................................ 23 6.3.1 Indicative costs .............................................................................................. 23 6.3.2 Costs specific to application .......................................................................... 24

6.4 Risks ......................................................................................................................... 26 6.4.1 Batteries ........................................................................................................ 28 6.4.2 Flywheels ...................................................................................................... 29 6.4.3 Pumped hydro storage .................................................................................. 29 6.4.4 Thermal energy storage ................................................................................ 29

6.5 Emerging Technologies ............................................................................................ 29 6.6 Examples of All Renewable Islands .......................................................................... 30

6.6.1 El Hierro, Canary Islands ............................................................................... 30 6.6.2 Icaria, Greece – Hybrid Power Station ........................................................... 30

Te Aponga Uira Proprietary Energy Storage Feasibility Study 7 September 2012

6.6.3 Bonaire- Dutch ABCs in the Caribbean ......................................................... 32 6.6.4 Key findings ................................................................................................... 34

7. Possible Future Renewable Scenarios ............................................................................... 35 7.1 Key Assumptions: ..................................................................................................... 35 7.2 Scenarios .................................................................................................................. 35

7.2.1 50 % by 2020 ................................................................................................ 36 7.2.2 100% by 2020 Renewable with Biodiesel ...................................................... 36 7.2.3 100 % by 2020, Load shifting with batteries................................................... 37 7.2.4 High Solar – 50 % by 2015 100 Percent renewable by 2020 with biodiesel ... 37 7.2.5 50 % by 2015, 100% Renewable by 2020 using a mix of resource for

renewables and storage. ............................................................................... 37 7.2.6 Recommended Scenario – 50 % Renewable by 2015; 100% Renewable

by 2020; High Wind Case. ............................................................................. 38 7.3 Analysis of the scenarios .......................................................................................... 38 7.4 First installations and Representative Costs Today ................................................... 41 7.5 Costs of Storage for the Recommended Plan ........................................................... 42 7.6 Recommended Options for Rarotonga ...................................................................... 43

8. Applications........................................................................................................................ 45 9. Siting .................................................................................................................................. 46

9.1 Larger scale .............................................................................................................. 47 9.2 Suggested Initial Installations .................................................................................... 47

10. Environmental Impacts ....................................................................................................... 48 11. Overall Funding Plan .......................................................................................................... 49 12. Action Plan ......................................................................................................................... 51 Appendix A - All renewable islands ........................................................................................... 53 Appendix B - Findings from KEMA’s interviews ......................................................................... 61 Appendix C - Stakeholder interviewed/consulted January – May 2012 ..................................... 65 Appendix D - Product Specifications Zinc Bromide Batteries: .................................................... 66 Appendix E - Costs of Storage used in model: .......................................................................... 74

Te Aponga Uira 1 Proprietary Energy Storage Feasibility Study 7 September, 2012

1. Executive Summary

This report presents the findings of a feasibility study of an Energy Storage for Rarotonga. The research and analysis that supports this report was conducted by KEMA in 2012. The key findings of this report are:

o Most of the renewable energy to date has been distributed solar energy which produces electricity only during sunlight hours.

o Storage will be necessary and important to the stability of the grid as more variable renewable energy is added over time.

o Storage can also be used to load shifting as well as for grid stability.

o As TAU has a relatively flat load shape to get to 100 % renewable will need to include more than just solar.

o Using storage for load shifting to cover the night time hours will be very expensive.

o At the moment there are no large scale (above 500 kW) renewable installations planned.

o Batteries and storage cooling at present are the best match for TAU’s storage need for grid support and any load shifting.

o Pumped storage is attractive from an economic stand point; siting may be challenging.

o TAU should provide for future storage needs using distributed storage as well as larger scale storage.

o Most storage technologies at present would not be considered technologically mature.

o TAU will need storage in 2012-2013 time period.

o We recommend one installation of 120kW of batteries, followed by one of 240kW of batteries both in 2012-13.

o Based on the indicative cost estimates we received this will cost approximately $1.5- $2M US.


o This size storage is modular and could be housed at the power plant side and a substation.

o

o TAU’s initial focus should be on storage for grid stability.

o The best technologies for grid support are batteries and flywheels as they are not site- specific.

o Currently the most likely technologies for load shifting are batteries and storage cooling. Small pumped hydro also is potentially an option but is very site- specific.

o Storage technologies will be changing rapidly over time as will their costs.

o It may make sense to include storage for the grid support of larger scale renewable projects as part of the interconnection process. We anticipate this storage would be owned by the developer.

o Storage for smaller scale customer renewable installations should be owned and potentially coordinated by TAU.

o Funding for smaller scale storage for grid support to support customer side renewables could be derived from donor investment managed by TAU or possibly a fee on developers.

o Storage used for load shifting could be developed and owned by a developer as a hybrid component of a larger scale project.


2. Objectives and Overview

This report was developed by DNV KEMA for Te Aponga Uira (TAU) to assess the need and feasibility for storage for the Island of Rarotonga under selected future generation scenarios. Currently the island of Rarotonga does not have any large planned renewable projects. However the Prime Minister’s Renewable Plan does have the objective of the island becoming one hundred percent renewable by 2020. This report is based on future scenarios of renewable energy in Rarotonga. The major focus of this report is on storage for grid stability. Ultimately the future energy storage requirements will be based on the future energy production and the future electrical system of TAU will need to be designed to include storage to increase the percentage of renewable energy on the island. This report will provide a recommendation for the first storage investments that need to be made on Rarotonga and will provide a framework for the additional investments that will need to made as Rarotonga’s energy includes more and more renewables. The focus of this report is on the storage needs required based on the scenarios in the Economic Viability report. This report does not address or analyze the adequacy of any future renewable energy projects; such matters are the exclusive responsibility of the developer and owner. Moreover, this report is based upon certain assumptions and sample cases, and it is therefore intended to be advisory but not all-inclusive as to events and scenarios which could arise in reality. In no event should this report be relied upon as a guarantee of any performance results of any scenarios used here.


3. Overview of TAU and Rarotonga

3.1 The TAU Network

Rarotonga, the capital and the main island of Cook Islands, has the area of 67km2. The population of Rarotonga is 13, 097 according to the 2011 Census. Tourism is the dominant industry and visitor arrivals have been increasing steadily in the past years and were 112,461 in 20111

.

Rarotonga is fully electrified and Te Aponga Uira (TAU), the Government Business Enterprise (GBE), owns the power generation and distribution network serving 4,037 residential and 1,032 commercial customers2

. The power generation is heavily dependent on imported diesel.

The generation capacity of TAU is about 9.5 MW out of the nine gen-sets. The firm capacity has been reduced from 12MW due to de-rating of six gen-sets. The distribution network comprises 80km of 11kV underground cables and 200km of 415V low voltage distribution lines. TAU operates with IEC standards and the power supply quality has been benchmarked as the “best class” for similar island networks3

.

3.2 Conventional Units

The power station is located in the Avatiu Valley. There are nine generating units all burning diesel # 2 as the fuel. The gen-sets are of various ages and conditions of which two generating units (No.4 and No.5) are considered having reached the end of their lifetime. Power station control is done manually in the power station control room. The power station has 3 bulk fuel tanks of 54,000 liter each and 2 day tanks (13500 and 13,900 liters). Most of the installed generators’ capacity has been de-rated due to various engine problems. The total generation capacity is 12,300kW and the de-rated total capacity 9,500kW. As the result the firm capacity is 6,000kW under the n-2 policy. TAU has a spinning reserve policy that provides uninterrupted power supply in case the largest generator trips. Currently the system peak demand is 4,830kW (2011) and is expected to be further reduced due to recent PV installations and the on-going energy efficiency program. With the total available capacity

1 http://www.stats.gov.ck/ 2 TAU Facts 3 Quantification of the Power System Energy Losses in South Pacific Utilities, 2011

http://www.stats.gov.ck/�

http://www.stats.gov.ck/�


TAU can keep up with the n-2 criterion. However, there are issues to be addressed to ensure long-term power supply quality. The gen-set ratings are listed in the table below.

No. Make Rating *Actual Rating

Gen. 1 Duvant Crepelle / 12V26N rated 2000 kW de-rated 1500 kW

Gen. 2 Duvant Crepelle / 12V26N rated 2000 kW de-rated 1500 kW

Gen. 3 Mirrlees Blackstone / MB 275-8

rated 1600 kW de-rated 1200 kW

Gen. 4 Lister Blackstone / ETSL rated 600 kW de-rated 400 kW

Gen. 5 Lister Blackstone / ETSL rated 600 kW de-rated 400 kW

Gen. 6 Mirrlees Blackstone / ESL 16 rated 1200 kW Out of Service

Gen. 7 MAN B&W / L9-27/38 rated 2700 kW 2700 kW

Gen. 8 Cummins / KTA50-G3 rated 800 kW 800 kW

Gen. 9 Cummins / KTA50-G3 rated 800 kW 800 kW

Total 12,300 kW 9,500 kW

Table 3-1 Current TAU Generation

* Apart from No. 6 which has been taken out of service the other engines are temporarily de-rated. Each one is able to be run to full load but not continuously.

3.3 Planned Upgrade

In late 2007, TAU commissioned Hydro Tasmania Consulting (HTC) to conduct a power system review and upgrade option study. The focus of the study was the security of electricity supply and the HTC report identified a number of risks associated with the power system operation and evaluated upgrading options.

Key recommendations include:

o retain the existing power station;

o add a new power house to the existing power station;

o implement automation to improve asset protection and control;

o replace old inefficient medium speed generator sets with high speed generating

sets;


o investigate the feasibility of progressively installing wind turbines; and

o Implement a number of minor projects to improve system security.

Following the HTC 2008 report, TAU has developed the power house upgrade plan. However, the upgrade is now incorporating the Cook Island Government’s Renewable Energy Plan.

3.4 The Government’s Renewable Energy Plan

The Cook Islands enjoyed a high level of electrification. However, the energy supply has been heavily dependent on imported fossil fuels, exposing the Cook Islands to the risks of energy security and international oil price volatility.

In July 2011, the Prime Minister, Hon. Henry Puna announced the Cook Islands Government’s ambitious renewable energy targets: to achieve 50% electricity supply by renewable energy by 2015 and 100% by 2020.

The Cook Islands Government has established a Renewable Energy Development Division (REDD) with the Office of the Prime Minister as an indicator of leadership. The Government has also openly voiced to the International Community, the Region and the Country of its commitment to achieving, by Renewable Energy means, the electricity demand of the country by 2020.

REDD has recently developed the Cook Islands Renewable Energy Chart Implementation Plan. The Implementation Plan is focused mainly on the outer islands. According to the Implementation Plan, the cost for achieving 100% renewable energy supplied electricity for Rarotonga is NZ $208m. It is expected that the future electricity supply for Rarotonga will be a mix of mature renewable energy technologies including Solar (PV), wind, waste to energy and other emerging renewable energy technologies with energy storage and backed-up by diesel generators4

.

4 REDD: Cook Islands Renewable Energy Chart Implementation Plan, March 2012


4. Renewable Activities

There is a high penetration of solar hot water on Rarotonga. It is estimated that 90%-95% of homes have installed solar water heaters5

On the other hand, although the electricity has been high, there were only a handful small Photovoltaics (PV) and wind projects installed on Rarotonga before the “Net-Metering” policy due to lack of knowledge and experience of renewable energy and other barriers.

.

The recent commitment by Government to fulfill 50% of the country’s energy needs from renewable sources by 2015 (50/15), and 100% by 2020 (100/20) has brought a sharp focus on renewable energy to ensure energy security. Additionally, it has also highlighted the need to bring together the key stakeholders in the Energy Sector, with a stronger sect oral approach to planning, coordination, research and development, implementation and management – a transformation of the sector to achieve the country’s renewable energy targets by implementing Cook Islands Renewable Energy Chart (CIREC) and instill a greater degree of environmental integrity, while placing the country in a better position to realize its economic and sustainable livelihoods goals.

4.1 Experience with Net Metering

To encourage renewable energy development from the commercial and residential customers, TAU introduced a Net-Metering Policy in November 2009. The Net-Metering policy provided economic incentives to customers interested in grid-tied renewable energy installations under 10kW capacity, allowing for credits to accumulate over a period of 12months from the excess energy fed back into the grid.

The Net-Metering policy has been a great success. The response to the Net-Metering policy from the public has been overwhelming. By the end of January 2012, 59 projects were installed with the total capacity of 288kW. The projection of the installed renewable energy capacity will exceed 600kW by 2012. Noticeably, most installations are PV projects.

Due to network safety and power quality concerns, TAU issued an amended Net-Metering policy on 1st October 2011 to limit the individual installed capacity under 2kW. A process of assessment and approval by TAU is mandatory before any grid-tie project can proceed.

The new Net-Metering policy has restricted net-metered PV installations greater than 2kW. However, the high cost of electricity is driving the high demand of PV installations, particularly for businesses where energy costs are significant. Even without “Net-Metering” benefits many projects, providing it is grid-tied, are still considered viable. For example,

5 ADB TA 6485-REG:Promoting Energy Efficiency in the Pacific


CITC has installed a number of grid-tied projects and the biggest project has the capacity of 85kW. These new installations will have reverse power relay installed preventing power export to the grid. Some of these projects have some level of battery storage as “counter-cloud measure”, i.e., to draw power from batteries for up to 30 minutes to local loads in the case of cloud caused power down instead of drawing power from the grid.

Under current electricity tariff the simple payback of net-metered PV projects is under 6 years. With the cost-down trend of PV systems, the viability of net-metered PV installations will further improve over the years. Therefore it is expected the organic growth of PV installations will continue for the foreseeable future. The growth rate is expected in the range of ~500kW per year.

4.2 Renewable resources to date

4.2.1 Solar resource

The Meteorological Office routinely measures solar radiation (insolation) in Rarotonga. In addition the Pacific Islands Forum Secretariat has independently recorded radiation in Rarotonga in 1995/96.

From the Forum Secretariat monitoring results, insolation on a horizontal surface in Rarotonga during the recording period varied between 2.7 kWh/m2/day in June and 5.6 kWh/m2/day in December. The monthly average insolation on a tilted surface (which receives more insolation than the horizontal surface of the radiation meter), is between 4.32 kWh/m2/day in June and 6.50kWh/m2/day in December. The annual average is 5.36 kW/m2/day. These results are for Avarua, on the northern coast of Rarotonga.

The table below shows the horizontal surface radiation recorded by the South Pacific Wind and Solar Monitoring Project.

Year Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Year 1995 4.99 5.93 4.79 3.06 2.64 2.86 3.17 3.55 4.27 5.05 4.59 5.51 4.20 1996 4.54 4.73 4.70 3.80 2.93 2.73 3.25 3.93 4.60 4.68 6.05 5.72 4.30

Average 4.76 5.33 4.75 3.43 2.78 2.79 3.21 3.74 4.43 4.86 5.32 5.61 4.25 Source - South Pacific and Solar Monitoring Project, Forum Secretariat 1996

Table 4-1 Solar horizontal surface radiation record

Currently there are over 500 KW of solar installed on the TAU system. It is anticipated TAU will have over 1 MW of solar on the system by year end 2012.


4.2.2 Wind resource

Other than the Meteorological Office’s records at the Raratonga Met Station, wind data collection and assessments have been performed for Ngatangiia (1995/96) and Kiikii (2007/08) on Rarotonga. The wind assessments demonstrate Rarotonga has an economically exploitable wind regime of with average wind speeds at typical generator hub heights of 40 - 50 meters of approximately 7 m/sec. Of particular interest are the measurements at the Kiikii site in northeastern Rarotonga which recorded 10 minute averages at 10, 20, and 30 meters. In addition, wind direction (10 m), barometric pressure, solar radiation and ambient temperature were recorded by the data logger. The location at Kiikii has been identified as a potential project site by Risø National Laboratory, Denmark in 1998. The data have been assessed for quality by Risø National Laboratory and evaluated for the wind resource by an independent specialist. With a measured annual average wind speed of 6.7 m/s at 30 m above ground the site has a good wind resource with wind speeds exceeding in the September to January period 7 m/s at 30 m above ground. For the measuring period 2007/2008 the correlation with available meteorological data suggests that the measurement period does not fall into a time frame with above-average wind speeds at Rarotonga. The measuring period from May 2007 to April 2008 has approx. 1.8% less average wind speeds than the long-term average. The results are consistent with the measurements undertaken in Aitutaki and Mangaia which showed similar results. The table below summarized the measured and processed wind data at Kiikii.

Month Possible Valid Recovery Mean Median Min Max Std. Dev Weibull k Weibull c

Records Records Rate (%) (m/s) (m/s) (m/s) (m/s) (m/s) (m/s) Jan 4,464 4,464 100.00 6.864 6.4 0.4 24.2 3.401 2.143 7.764 Feb 4,176 4,176 100.00 5.258 5.2 0.4 14.3 2.131 2.660 5.912 Mar 4,464 4,464 100.00 5.575 5.6 0.4 13.2 2.780 2.093 6.281 Apr 4,320 4,320 100.00 4.550 3.9 0.4 15.9 3.046 1.551 5.070 May 4,464 4,464 100.00 3.522 2.9 0.4 14.0 2.361 1.596 3.949 Jun 4,320 4,320 100.00 5.337 5.3 0.4 12.7 2.752 1.993 6.001 Jul 4,464 4,464 100.00 5.611 5.3 0.4 15.4 3.221 1.777 6.294 Aug 4,464 4,464 100.00 6.650 6.1 0.4 16.5 3.846 1.748 7.448 Sep 4,320 4,320 100.00 7.314 6.7 0.4 17.2 3.795 1.971 8.216 Oct 4,464 4,464 100.00 7.951 8.9 0.4 14.5 3.329 2.579 8.898 Nov 4,320 4,320 100.00 6.895 7.0 0.4 15.9 3.238 2.210 7.744 Dec 4,464 4,464 100.00 8.648 8.8 0.4 18.6 3.844 2.365 9.705 All data 52,704 52,704 100.00 6.188 5.8 0.4 24.2 3.492 1.807 6.945 Mean of monthly means 6.190

Table 4-2 Wind data at Kiikii


Currently there are 5 installations, totaling 13 KW of wind on the system.

4.3 Planned Utility Scale projects

Up to now there have been no utility scale projects planned and implemented. In the past a number of renewable energy studies have been undertaken. In 2008 a study by ADB (TA7022-COO) identified some potential utility scale wind projects at the range of ~2MW. The report also mentioned that some wind farm developers were interested in Rarotonga wind projects6

The solar resource is good at Rarotonga. It is possible to develop utility scale PV projects if suitable sites identified. There are some interested parties in the private sector. There is activity even without net-metering.

.

It is expected that potential utility scale renewable energy projects will be developed by the private sector and facilitated by TAU and/or` the Government. Alternatively TAU could develop utility scale projects.

6 ADB 7022-COO: Cook Islands Preparing Infrastructure Development Projects


5. Existing situation

The previous section presents the current planned upgrades to the Power System and the Prime Minister’s Office that “has taken an audacious step towards transforming its country from dependency to fossil fuel as an energy source to a future of Renewable Energy means as its source of electrical power generation.”7

In this section we present a high level overview of the Energy System including: recent sales, a peak demand forecast, an energy forecast and a look at load factor.

5.1 Recent Sales

Recent Energy and Demand figures are presented below. TAU’s energy usage is growing. The time of the peak between 2010 and 2011 has shifted from 13:30 to 16:00.

Table 5-1 Energy and Demand

5.2 Load and Energy Forecast

For this storage analysis we forecast a modest growth in sales and peak load growth for this analysis. We forecast a modest growth in sales and peak load growth for this analysis. We projected that sales would increase at 2.5 percent per year and demand at 2.5 percent per year for this analysis. These projections are presented below:

7 Cook Islands Renewable Energy Implementation Plan

FY 2010 FY201127763794 2886989127267853 28303970

991 10324258 43075249 53395195 5301

4879 483013:30 16:00

-1.00%KW time

2.05%

CommercialDomestictotal Usage/ customer

Total customers-year end 4.14%1.15%1.71%

TAU Usage and Generation Figures %change

Total annual generationTotal annual sent out

3.98%3.80%


Figure 5-1 Projected KWh, kWh with energy efficiency and KW.

Economic Drivers Tourism is the main industry in the Cook Islands. Approximately 100,000 people visit the Cook Islands each year, spending their time mostly on Rarotonga and Aitutaki. This increased the population by around 3,000 each day on average and 4,000 per day during the peak tourist period which is usually between July and September.8

8 The Cook Islands Renewable Electricity Implementation Plan (Draft) ; Renewable Energy Development Division; Office of the Prime Minister; Government of the Cook Islands

4,400

4,600

4,800

5,000

5,200

5,400

5,600

27,000,000

28,000,000

29,000,000

30,000,000

31,000,000

32,000,000

33,000,000

34,000,000

35,000,000

2012 2013 2014 2015 2016 2017 2018 2019 2020

kW

kWh

kWh energy


Figure 5-2: Visitors per month to Rarotonga

Overall GDP is approximately $250,000M per year. Real gross domestic product (GDP) per capita is now around NZ$15,000 (US$12,000). Electricity and water supply account for 2% of GDP, with the dominant components of GDP being; Wholesale and Retail Trade 20%, Restaurants and Accommodation 16%, Transport and Communication 18%, and Finance and Business Services 13%. Public Administration is 9% of GDP.9

The key drivers of growth are expanding tourism and rising household spending, these are contributing factors to unemployment being at low levels on Rarotonga. Rising numbers of foreign workers are required to meet the needs of the island’s expanding private sector. Tourism will likely remain as the driver of economic growth, but will remain concentrated in Rarotonga and Aitutaki. 10

5.3 Load Shape

The load shape is relatively flat; with the highest loads occurring wet summer days. The load shape has a typically AC peak driven by commercial and residential loads and then a second peak around 8 pm driven by residential AC and other nighttime loads. The nighttime loads show that 2.5-3 MW are needed throughout the night.11

9 The Cook Islands Renewable Electricity Implementation Plan (Draft) ; Renewable Energy Development Division; Office of the Prime Minister; Government of the Cook Islands

10 The Cook Islands Renewable Electricity Implementation Plan (Draft) ; Renewable Energy Development Division; Office of the Prime Minister; Government of the Cook Islands 11 Source:HTC 2008, TeApongaUira Cook Islands Power System Review and Expansion Options. Hydro Tasmania Consulting, January 2008

- 2,000 4,000 6,000 8,000

10,000 12,000 14,000 16,000

Visitors per Month

2009

2010

2011


The figure presented below is from January of this year is based on the output of the generations and shows a similar pattern:

Figure 5-2 Load Shapes from January 2012 Load data

Observations from most recent data:

1. The blue line is the average over all days by hour- its low is about 2.6 MW and the peak on average is about 3.5 MW.

2. The red line is the actual January peak day where it appears there was a storm late

in the day.

3. The green line is the second highest day where clearly there was no weather relief- the load stays higher longer- that load shape is probably a better more realistic peak load shape.

The solar hours for some of the islands are shown below for the twelve months.


Figure 5-4: Sunshine Hours for Cook Islands Locations

There is strong coincidence between the sunlight hours and the load between 7am and 6 pm. Generally the secondary peak is not during sunlight hours. The above data suggest that a key challenge for having very high percentage energy from renewable generation will be the night time hours. This will require renewable production that occurs during all hours or a very large amount of storage for load shifting.

5.4 Need for base load capacity

Currently wind and PV are considered mature and practical renewable technologies for Rarotonga. However, the intermittent nature of wind and PV is a great challenge - with high RE penetrations, system integration and load firming can be problematic and costly. It is highly desirable that renewable energy powered base load capacity can be developed. Waste to energy technology, with sufficient resource, is capable of providing base load capacity as well as other environmental benefits. Waste to energy can provide energy 24/7 throughout the years and is limited by the amount of feedstock. As shown above the load shape for TAU is relatively flat.

-

1.00

2.00

3.00

4.00

5.00

6.00

7.00

8.00

9.00

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

Sunshine Hours Courtesy Cook Islands Telecom January 2012

Penrhyn

Rakahanga

Manihiki

Pukapuka

Nassau

Suwarrow

Palmerston

Aitutaki

Mauke


6. Storage Technologies

6.1 Overview

Traditional electricity network has little need for energy storage. Electricity production is controlled to meet the load instantaneously.

Energy storage is needed for intermittent renewable energy systems such as PV panels and wind turbines. In Cook Islands, the 50%/2015 and 100%/2020 renewable energy targets mean that renewable energy will eventually replace most of the diesel generation. The intermittent and non-controllable renewable energy based electricity generation requires energy storage capacity as a critical means of integrating renewable energy into the network. Depending on the level of renewable energy penetration, the required energy storage capacity could be significant.

The main functions of energy storage for renewable energy could be the following:

o Grid frequency support: support the frequency in case of sudden power drops from renewable sources; (limited to day time only and still rely heavily on grid, so not long term solution)

o Fluctuation suppression: stabilize power output. (limited to day time only and still rely heavily on grid, so not long term solution)

o Transmission curtailment: mitigate power delivery constraints; (limited to day time only and still rely heavily on grid, so not long term solution)

o Time-shifting: store the off-peak energy and deliver for peak demands; (desired option in order to achieve the Government goal of diesel independence)

Energy storage technologies can be classified in terms of functions into two categories. Table 6.1 showed the two categories and technologies suitable for each group.

The first group is for network power quality and reliability. It can also be referred to as short-term technologies because the discharge duration is in seconds or minutes.

The other group is for energy shifting and also can be referred as long-term storage technologies. The discharge duration for this group can be hours even days.


Energy Storage Technologies for power quality and reliability

Energy Storage Technologies for energy shifting (desired – off grid)

• Capacitors

• Super-capacitors

• Superconducting Magnetic Energy Storage (SMES)

• Flywheels

• Batteries

• Pumped Hydro Storage (PHS)

• Compressed Air Energy Storage (CAES)

• Large scale batteries

• Fuel cell

• Thermal Energy Storage (TES)

Table 6-1 Energy storage technology categories

The grid of Rarotonga is small and the rapid PV growth brought about challenge on network stability and operation for TAU. In the near term, there is an urgent need to consider energy storage measures for network stability. Bulk energy storage and shifting are desirable however the cost is prohibitive for current technology. Considering TAU’s situation, we have excluded capacitors/super-capacitors, super-conducting magnetic energy storage (SMES), fuel cells and compressed air energy storage (CAES).

Energy Storage technologies can also be categorized by forms of storage. Technologies considered for TAU application are listed below and described in the next section.

o flywheels

o pumped hydro storage

o batteries

o Thermal energy storage: cold/hot storage

6.2 Technologies considered

6.2.1 Flywheels

Flywheels store rotational kinetic energy in the angular momentum of a spinning mass. When charging, a motor/generator drives the flywheel to increase the rotating speed. Energy is discharged by driving the motor/generator to generate electricity and as a result the rotating speed of the flywheel will decrease.


Flywheels are typically for high power, short duration applications.

A flywheel example is shown in the picture below.

Figure 6-1 A flywheel system (Source: Beacon Power)

6.2.2 Pumped hydro storage

Pumped hydro storage (PHS) is a mature technology and has been implemented in over 200 locations around the world since the 1890’s.

A PHS system consists of an upper reservoir and a lower reservoir with a hydro turbine/generator station and a pump station. The turbine/generator can be similar to normal hydroelectric plants. There are also integrated pump/turbines available on the market.

Water is pumped to the upper reservoir and discharged later for power generation. The water can be kept in a closed loop so that water loss can be minimal. A PHS is able to turn intermittent renewable power into high quality base load when properly integrated.

Construction of dams/reservoirs can be costly therefore locations where one of the two reservoirs exists would be preferred. Japan built a sea water PHS in Okinawa in 1999 in which the ocean is used as the lower reservoir.

Pumped storage is generally viewed as the most promising technology to increase renewable energy source penetration levels in power systems and particularly in small


autonomous island grids, where technical limitations are imposed by the conventional generating units. Introduction of pumped storage for facilitating increased wind energy penetration levels has been the subject of several publications. There are currently two projects in existence: El-Hierro station in the Canary Islands and Ikaria Island, Greece. Therefore, in spite of the great potential promised by pumped storage, both field experience and detailed feasibility studies of mature projects are still missing, to provide realistic data or reliable and concrete study results.

Figure 6.2 shows the PHS concept.

Figure 6-2 Pumped energy storage system

There are non – traditional types of pumped storage being developed- this includes using tanks and pipes instead of reservoirs. Over time (post 2015) this may be appropriate to consider for Rarotonga if it becomes commercially available. It is very attractive from an economic point of view.

6.2.3 Batteries

Batteries store energy in the form of electrochemical energy. Although batteries have been used widely in everyday life and battery technologies have been improved rapidly in the past decade, it is still a challenge to store energy in batteries cheaply.

Batteries use chemical reactions to create a flow of electrons to generate electric current. The primary elements of a battery cell include the container, two electrodes (anode and cathode), and electrolyte. Electric current is created by the oxidation-reduction process involving chemical reactions between the electrolyte and electrodes.


In the discharge process, charged ions in the electrolyte that are near one of the cell’s electrodes supply electrons (oxidation) while ions near the cell’s other electrode accept electrons (reduction). The process is reversed to charge the battery, which involves ionizing of the electrolyte.

Lead-acid batteries are the most traditional and mature battery technology. Other technologies and materials include nickel-cadmium (NiCad), lithium-ion (Li-ion), sodium/sulfur (Na/S), zinc/bromine (Zn/Br), vanadium-redox, and nickel-metal hydride (Ni-MH). While traditional batteries contain electrolyte in the same container as the cells, flow batteries use separate containers to store electrolytes.

Figure 6-3 NaS battery

Figure 6-4 Zinc Bromide Battery


6.2.4 Thermal energy storage

Thermal energy storage (TES) is to store energy in cold or hot mass and to use it at a different time. Since there is no major heating load in Rarotonga so that cold or ice storage is more appropriate for this study.

The common use of TES is to store energy (i.e., making ice) during off-peak time when energy is cheap and discharge the stored energy (i.e., using the store ice for air-conditioning, cold storage etc) during peak time when energy is expensive. It is also a way to reduce peak demand. Another benefit of ice storage is the potential to reduce chiller sizes therefore reduce the initial and operating costs of the chiller plant. This technology is typically used where on peak energy is significantly more costly than off peak energy.

Often renewable energy in particular wind generation at night can be used for making ice. It is within the realm of possibility that with Rarotonga’s load profiles that solar or wind energy could be used to make ice during the day to use at night. This will be explored more in the Economic Viability Study.

Figure 6.5 showed a TES example.

Figure 6-5 Ice storage unit for a food processing facility (source: BAC)

6.2.5 Compressed Air Energy Storage

Compressed air energy storage (CAES) uses inexpensive electricity (e.g. off-peak electricity) to compress air and store the compressed air. In the discharge, compressed air is released


and often heated and mixed with natural gas to drive gas turbines/generators to generate power.

The first generation CAES systems have been commercially available. The limitations of the technology are the energy loss during the cooling/reheating process and CO2 emissions. Air cooling between compression stages, although necessary, results in a loss of heat energy. Compressed air energy storage systems also produce carbon dioxide (CO2) emissions from the reheating process, usually performed by direct combustion with natural gas.

Figure 6.6 is the CAES concept.

CAES has been used for very large applications with capacities over 100MW. Underground rock caverns have been used to store compressed air for large applications. It is possible to store compressed air in tanks for small sites. There are also proposed technologies to improve the CAES efficiency such as the advanced adiabatic CAES and the isobaric (constant pressure) storage system.

Figure 6-6 CAES Concept

Technologies other than the first generation of CAES have not been commercially available. There is no commercially available small-scale CAES reported at this time. However CAES


does have the potential along with pumped storage of being able to be used to longer term duration storage and load shifting. There are some forms of CAES being explore in ocean environments. We do not believe, however these technologies will be available until post 2020. Emerging technologies are discussed in more detail in the Economic Viability Study.

6.3 Costs Energy storage is evolving and the costs of many of these technologies are not representative of mature technologies. In addition there are losses during the charge-store-discharge cycle and there are limits on the number of cycles which is particularly challenging for batteries. As this section will illustrate, the costs of storage are significantly different from source to source and by application.

6.3.1 Indicative costs

Costs of energy storage can be measured in terms of power ($/kW) and/or capacity ($/kWh). The costs will also be highly dependent on applications, locations and geographical features in case of CAES and PHS. Nevertheless Table 6.2 provided indicative costs for energy storage technologies and round-trip efficiency and life cycle information. It also should be noted that there are rapid technology developments in the field of energy storage and increasing deployment of energy storage, along with the increasing demand from renewable energy, electric vehicles and smart grid. Therefore costs of energy storage technologies may change (be reduced) quickly in the near future.

Technology Power Subsystem Cost $/kW

Energy Storage

Subsystem Cost $/kWh

Round-trip

Efficiency %

Cycles

Advanced Lead-acid Batteries (2000 cycle life)

400 330 80 2,000

Sodium/sulfur Batteries 350 350 75 3,000

Lead-acid Batteries with Carbon-enhanced Electrodes

400 330 75 20,000

Zinc/bromine Batteries 400 400 70 3,000

Vanadium Redox Batteries 400 600 65 5,000

Lithium-ion Batteries (large) 400 600 85 4,000

CAES 700 5 N/A (70) 25,000


Pumped hydro 1,200 75 85 25,000

Flywheels (high speed composite) 600 1600 95 25,000

Super capacitors 500 10000 95 25,000

Table 6-2 Energy Storage Technology Costs12

It is noted from the table above that costs for batteries are similar. New batteries such as flow and Li-ion batteries are more about 90% more expensive than traditional batteries but with more life cycles. Costs for new batteries might be reduced with technology development and mass production in the near future.

Also the power (kW) cost for PHS is much higher but the energy cost is significantly lower. And the life cycle is far greater than batteries. Flywheels have great life cycles however the costs are high for both power and capacity. The energy sub storage indicative costs shown here for CEAS and PHS are the lowest ($5/ Kwh) and ($75/ Kwh). However these costs may not be at a size scale appropriate for TAU.

6.3.2 Costs specific to application

This section provides some summary data on the usage of storage technologies in selected applications. Frequency Regulation In a recent report for the California Energy Commission,13

Energy Storage Options for Frequency Regulation

Technology

the below technologies were identifies as possible options for frequency regulation. As this table illustrates all of these are still in the demonstration mode.

Maturity Duration (hrs)

Efficiency (%)

Total Cost ($/kW)

Cost

($/kWh)

Flywheel Demo 0.25 85 – 87 1950‐2200 7800‐8800

Li‐Ion Demo 0.25 ‐ 1 87 – 92 1085‐1550 4340‐6200

Advanced Lead Acid Demo 0.25 ‐ 1 75 – 90 950‐1590 2770‐3800

Table 6-3 Storage Costs for Frequency Regulation

12 SANDIA Report 2011-2730: Energy Storage Systems Cost Update 13 2020 Strategic Analysis of Energy Storage in California, Prepared for the California Energy Commission; Prepared by the University of California


Renewable Integration The mostly likely Storage candidates for renewable integration applications and some of their characteristics are shown below:

Table 6.4 Costs for Renewable Integration

The above costs are viewed as the most appropriate costs to use to estimate costs of grid support. Both Pumped Hydro and CAES show the potential capability to store energy for more than 10 hours. Time Shifting Some key characteristics of storage that could be used for time shifting are show below. 14

This is not all inclusive.

14 2020 Strategic Analysis of Energy Storage in California, Prepared for the California Energy Commission; Prepared by the University of California

Technology Maturity Capacity (MWh) Power (MW)

Duration (hrs)

Efficiency (%)

Total Cost

($/kW)

Cost

($/kWh)

Pumped Hydro Mature 1,680‐5,300

5,400‐14,000

280‐530

900‐1,400

6 ‐ 10 80 ‐ 82 2,500‐4,300

1,500‐2,700

420‐430

250‐270

CAES ‐CT

Underground

Demo 1,440‐3,600 180 8

20

68 ‐ 75 960

1,150

120

60

CAES

Underground

Pre- Commercial

l

1,080

2,700

135 8

20

68 ‐ 75 1,000

1,250

125

60

Sodium‐Sulfur Commercial 300 50 6 75 3,100‐3,300

520‐550

Advanced Lead‐Acid

Commercial

Commercial

Demo

200

250

400

50

20‐50

100

4

5

4

85‐90

85‐90

85‐90

1,700‐1,900

4,600‐4,900

2,700

425‐475

920‐980

675

Vanadium Redox

Demo 250 50 5 65‐75 3,100‐3,700

620‐740

Zn/Br Redox Demo 250 50 5 60 1,450‐1,750

290‐350

Fe/Cr Redox R&D 250 50 5 75 1,800‐1,900

360‐380


Technology Maturity Capacity (kWh)

Power (kW)

Dura‐tion (hrs)

Efficiency (%)

Total Cost ($/kW)

Cost ($/kWh)

Advanced Lead Acid

Demo‐ Commercial

100‐250 25‐50 2 ‐ 5 85‐90 1600‐3,725 400‐950

Zn/Br Flow Demo 100 50 2 60 1450‐3,900 725‐1,950

Li‐ ion Demo 25‐ 50 25‐ 50 1 ‐ 4 80‐ 93 2,800 950‐ 3,600

Storage Cooling Mature Varies Varies 4-8 NA 2400 NA

Table 6-5 Potential Costs of Time Shifting

6.4 Risks

Considering challenges of Rarotonga, such as the transitional population, geographical isolation, skill shortage and the size of the island and network, we understand that that TAU prefers commercially proven, mature technologies for energy storage options but also opens to other options such as being a partner of funded technology development. In reality, few technologies can be classified as “mature”; among those are PHS, Lead-Acid batteries, flywheels and CAES. Other technologies are at different stages of development. While some (battery) technologies have been claimed “commercially available”, they are still in the early stage as commercial products. Figure 5.6 shows the “maturity” of energy storage technologies.

With the exception of pumped storage; none of these possible storage technologies is economically feasible for storing large amounts of energy – such as trying to use solar to produce energy during the day and then use mostly storage to provide energy during the nighttime hours.


Figure 6-7 Energy Storage Technology Maturities15

Risk analysis of energy storage technologies has been summarized in the table below. Batteries are treated as one category since there are many similarities although technologies are different.

Risks are assessed based on costs, maintenance, modularity, environmental impact and siting issues.

15 Progress in electrical energy storage system: A critical review ELSEVIER Progress in Natural Science 19 (2009) 291–312


Technology Costs Maintenance Modularity Environmental Impact Siting Batteries Moderate,

may decrease over the time

High – cycle management, cooling management

Yes Electrolyte toxic, risk of leaking; proper disposal and handling required

Minimal issues

Flywheels High High Yes Minimal Minimal issues

Pumped Hydro

Likely high initial costs and low on-going cost and highly site dependent

Low Possible Major impact for large systems but might be less for smaller sized sites.

Need to identify suitable sites and clear EIA

Thermal Storage

Likely low cost

Moderate Yes Minimal Need to be implemented for new buildings with central HVAC plant

Table 6-6 Risk Matrix for Storage Technologies

6.4.1 Batteries

It is understood that batteries are in various development stage except for Lead-Acid technology. Costs for large-scale energy storage using batteries are still high, although they can be considered moderate comparing with flywheels and PHS.

All batteries are very sensitive to the number of discharge cycles, especially with deep discharges. Operators need to be very careful with discharge management because the lives can be significantly shortened if not managed properly. Manufacturers have developed battery management systems (BMS). Some of those BMS limit the discharge at low levels. While the life of batteries can be better managed, it also limits the capacity of batteries as energy storage (shifting). Most batteries generate heat in the process of charge/discharge so that cooling of battery space is needed.

Due to good modularity there should be little issues with siting with small installations. However, most electrolytes used for batteries are toxic therefore leaking should be managed carefully. There is significant experience in handling, disposing and recycling of batteries.


6.4.2 Flywheels

Flywheels have minimal environmental issues but they are costly and high maintenance. The other major limit for flywheels is that they are designed for high power, short time discharge operation so that it is not suitable for energy shifting.

6.4.3 Pumped hydro storage

Pumped hydro storage can have high initial construction cost. The technology also requires a suitable site to build a PHS system. Although PHS has been a mature technology, small-sized projects have not been reported. The environmental impact of PHS is highly site specific as are the environmental impacts. If a possible site is found this could be a possible opportunity for RaroTonga.

6.4.4 Thermal energy storage

Ice storage for HVAC (and potentially refrigeration) can be cost-effective, providing benefits for both the network and the end users. They are able to use renewable energy to charge and reduce peak demand during peak times. They are, however, not cost-effective for retrofitting projects. Ice storage cooling is best if implemented in new constructions with central HVAC plants. As mentioned previously it could be that solar energy could be used to make ice during the day to cool at night given the Load Profile. This resource is modular.

6.5 Emerging Technologies

This study focused on commercial or close to commercial technologies. There are also a number of emerging storage technologies. These include:

o Ocean based CAES

o Underground pumped hydro

o Hybrid technologies such as wind/hydrogen/combined

o Aquifer PHS

o Archimedes’ screw

These are discussed in additional detail in Appendix E of the Economic Viability Study ---. Over time some of these may become closer to commercial and possibly be applicable for Rarotonga.


6.6 Examples of All Renewable Islands

To reach the Prime Minister’s objective, Rarotonga would be a 100 percent renewable island by 2020. There are a few examples of such islands. We include them here for reference in summary here and in more detail in Appendix A. 6.6.1 El Hierro, Canary Islands

The first of these is the El Hierro project in the Canary Islands. This project uses wind, solar and hydro pumped storage. Scale & Technology This project includes:

o 11.5 MW wind o 11.3 MW hydroelectric pumped storage o distributed control system (DCS) o interconnection substation & automatic generation control (AGC) o Serves 11,000 residents

• 80% electricity needs served by pumped hydro-storage system • 20% from solar thermal collectors & grid-connected PV systems

Overview By communicating with the wind farm, the control solution will automatically start releasing water from the upper reservoir to generate power at the hydroelectric plant whenever the wind power generated is insufficient to meet demand. Conversely, excess wind power will be used to pump water to the upper reservoir, for use when wind power is low. Cost: $87 million 6.6.2 Icaria, Greece – Hybrid Power Station16

The Hybrid Power Station (HPS) of Ikaria Island, Greece, is currently in the construction stage. The project will be one of the first wind-hydro-pumped-storage hybrid stations in the world.

The Ikaria HPS includes:

o 3 water reservoirs at sufficient altitude separation. 16 http://users.ntua.gr/stpapath/Paper_1.32.pdf

http://users.ntua.gr/stpapath/Paper_1.32.pdf�


o 2 small hydroelectric plants (SHP), both equipped with Pelton turbines, one at Proespera (1 1.05 MW), to exploit excess water from Pezi dam and another at Kato Proespera (2 1.55 MW), which exploits excess water from Pezi and also participates in pumped storage operation

o Combines two forms of renewable energy (wind via pumped storage and hydroelectric, via exploitation of excess water from the upper reservoir) using the same hydraulic infrastructure. This calls for an operating policy which will permit efficient exploitation of both sources, without disturbing the operation of the conventional generation system and other WFs in the island.

The operation of the SHPs is subject to restrictions imposed by the environmental terms of the station. While the pumped-storage mode of operation, cycling water between the two lower reservoirs, is permitted throughout the year, hydroelectric operation is only possible from October 1 to April 30 (in the so-called “winter period”). During this period, a specified minimum water level must be ensured at the Pezi reservoir, while all excess water can be used for energy generation (hydro operation). In the “summer period” (May 1 to September 30) the SHP at Proespera is not operating.

Figure 6-8: Figure of Hybrid System


6.6.3 Bonaire- Dutch ABCs in the Caribbean

After Bonaire's only power plant burned down in 2004, the island's government wanted not only to restore energy generation to the island, but also to generate that energy from 100% renewable sources. While temporary diesel generators provided power for the short term, the government began working with the local energy company to devise a plan to reach the 100% renewable energy goal. Eventually a consortium, EcoPower Bonaire BV, won the contract to develop the plan, which includes investment in research, wind turbines, and a facility that will produce biodiesel from algae. Island Background The island of Bonaire is 250 square kilometers (km) and is located 80 km north of the Venezuelan coast. During its long history, it has been used as a prison, a plantation island, and a salt production center. Today the island's outstanding marine environment also attracts a modest number of tourists. With a population of 14,500, Bonaire's peak electricity demand is approximately 11 megawatts (MW). The island's power needs are currently served by a set of rented container (light-fuel) diesel generator systems that have a rated capacity of 12 MW. In a typical year, Bonaire consumes 75,000 megawatt hours (MWh) of diesel-generated electricity.

Project Partners

EcoPower Bonaire BV consortium:

o Econcern: Project developers for the Bonaire project and the majority shareholder (90%); responsible for project development, contracting, financing and operation.

o Enercon: A German wind turbine and system supplier that is responsible for the

wind-diesel load balancing system and that will supply wind turbines (5% shareholder)

o MAN: A German truck and engine manufacturer that will supply diesel generators

(5% shareholder)

Water and Energy Company of Bonaire: Government-owned Company, which produces and distributes water and electricity on the island. The company signed an agreement with Ecopower Bonaire BV to purchase all electricity produced by the project. System Specifications

o Wind-diesel power plant


• 11 MW wind capacity:

The initial turbine is an Enercon E-33 wind turbine (330-kW unit). The wind farm will consist of twelve 900-kW E-44 turbines (rotor

diameter 44 meters). Each wind turbine is expected to operate at a high capacity, resulting

in around 3,500 full load hours annually. • 14 MW biodiesel power plant • 3 MW of battery storage backup

Power management system: 10 km of cable from wind farm to power station; 30-kilovolt transformer station.

Figure 6-9: Bonaire Resources17

Financing The cost of Bonaire's new wind-diesel system is approximately US$60 million, with an expected return of around $15 million per year from power. Part of this investment will be

17 Courtesy of Ecofys Netherlands BV


recovered through Econcern's selling of carbon dioxide credits (that will likely be Gold Standard). Rabobank (Netherlands) provided nonrecourse financing with a 20% equity/80% debt ratio. Shareholders include Ecofys (90%), MAN (5%), and Enercon (5%).

Current Status:

o The new power plant has been in operation since August 2010 and is performing well.

o The wind farm has been phased in gradually, but the highest instantaneous wind share has already been more than 80%.

o The targeted average wind share of 40%–45% will most likely be met. A more accurate estimate will be available over time.

o The power management system and the battery have been performing above expectations. Power quality and grid stability are good.

o The turbine supplier has guaranteed the fuel savings, and the system is reducing Bonaire's electricity costs. Moreover, the island now has a strong hedge against future fossil energy price hikes and is on track to achieving 100% sustainability through its algae/biofuel option.

The following resources provided information about this project.18

6.6.4 Key findings

None of the above islands are directly comparable to Rarotonga in all aspects of the possible resources. The Greek and Canaries Island projects are both using significant amounts of conventional pumped storage as well as wind. There is a solar resource as well but it is a small percentage that we suspect will be the case in Rarotonga. Bonaire has had periods of time where wind has been as much as 80 % of the system with 3 MW of battery storage and 3 MW of diesel. The battery has been mostly used for Grid quality and stability. Bonaire’s progress on the bio-diesel may be very informative for Rarotonga.

18 Ecofys Group; Joris Benninga, Real New Energy

http://www.ecofys.com/com.htm�

mailto:[email protected]�

http://www.realnewenergy.com/index.html�


7. Possible Future Renewable Scenarios

Typically in an Energy Storage feasibility study there are planned renewable resources. Those planned resources will have detailed production estimates based on measured estimates of solar and or wind or other resources. The need and actual size and type of storage are closely tied to the type of planed renewable energy projects. As there are no large planned renewable energy projects planned by outside developers that DNVKEMA was aware of, we assumed different future scenarios described in the next section. Our analysis here focused on identifying possible renewable energy futures based on data from Rarotonga where possible.

7.1 Key Assumptions:

To date Rarotonga has been seeing increasing solar penetration in the last few years. This all either from customer side solar or net metered solar but all are grid-tied and totally dependent on the grid for its operation. None of it has come from standalone or what we will describe as utility scale renewable energy – (1-5) MW projects. We used existing TAU estimates and projections in our solar projections. We assumed a different mix of customer side and utility scale storage for each scenario. We used waste to energy productions based on the waste to energy feasibility study DNV KEMA is also performing. We limited possible production at 210 kW as we do not believe there is enough trash to have a larger plant. We assumed a different mix of customer side and utility scale storage for each scenario. We do in several of these scenarios run the waste to energy facility only at night at 420 kW to shift nighttime load. We modeled storage for grid support and storage for load shifting separately. We assumed based on the situation that the storage would be a mix of distributed and utility scale storage. The technologies uses for grid support were batteries. The technologies used for modeling load shifting were batteries and storage cooling with an inverted cycle – i.e. to produce ice during the day and use it for AC at night.

7.2 Scenarios

The scenarios we assumed for this storage study and the economic viability study are: o 50 % renewable energy by 2020 o 100 % Renewable by 2020 with Biodiesel o 100 % Renewable by 2020 using storage for load shifting o 50 % Renewable by 2015; 100% Renewable by 2020; High solar case with biodiesel o 50 % Renewable by 2015; 100% Renewable with a mix of resources for generation

and storage


o Recommended Case 50 Renewable by 2015, 100% Renewable by 2020, High wind case; On and offshore wind, solar, community wind

These scenarios are the ones KEMA developed for the Economic Viability Project as well as this project. The cost for both storage for Grid support as well as storage for load shifting do not include network enhancement (subs, cabling, etc.), if required. With exception of the 50 percent renewable by 2020 all scenarios do achieve 100 percent by 2020. Three of the scenarios also achieve the Prime Minister’s goal of 50 percent by 2015 as well. All of those scenarios require significant investment between now (September 2012) and the end of 2015. All of these scenarios include the waste to energy plant. They all include significant amounts of solar, storage for grid control and wind. Some include biodiesel and those that do not require more storage be used for load shifting. All of these scenarios are cost effective from a societal point of view (though one is barely cost effective). Key Parameters of these scenarios are shown below:

Table 7-1 Comparison of Scenarios

Each of the scenarios is briefly described below. All scenarios are described in significant detail in the Economic Viability Study. 7.2.1 50 % by 2020

This case gradually adds renewable resources over time. By 2020 over 50 percent of the energy produced is renewables. This scenario was cost effective with a benefit/ cost ratio of 2.65. Total costs are $62 M. This assumes 2 MW of utility scale wind, 1 MW of utility scale solar and slowly increasing customer side solar presuming there are still limits to net metering. 7.2.2 100% by 2020 Renewable with Biodiesel

In this case we made the assumption that it was feasible to generate biodiesel with algae or some other medium on the island and or elsewhere and that was used to increase the

17.30% 22.50% 0.00% $294M

$161M

53.30% 10.55% 0.00% $149 M

$186 M

17.30% 7.66% 11.40% $171M

28.00% 14.65% 0.00%50 % by 2014; 100 % by 2020,High Wind 2.11 0.54 50.20% 100.00% 27.70%

50 % by 2015, 100 % by 2020, Renewable 1.69 0.61 51.60% 100.00% 41.70%

100 % in 2020 with biodiesel 1.51 0.59 26.80% 100.00% 47.90%

50 % by 2015, 100% by 2020; High Solar with Biodiesel 1.67 0.58 51.60% 100.00% 49.60%

100% in 2020 with battery load shifting 1.02 0.84 26.60% 100.00% 48.20%

50 % by 2020 2.65 0.66 17.00% 50.00% 23.90%

Scenario Benefit/ Cost avg Price% renewablein 2015

% renewablein 2020 % solar %wind %storage

% biodiesel total costs

17.60% 9.00% 0.00% $62.3 M

17.80% 0.02% 22.00%


percentage of renewable energy to 100 percent. It provides a 100 percent renewable energy scenario without having to have a cost-prohibitive amount of storage. This scenario was cost effective with a benefit / cost ratio of 1.51 and a total spend of $161M. This scenario also includes 2 MW of utility scale wind and 1 MW of utility scale solar. Customer side solar grows to over 7 MW by 2020 as it is assumed the restrictions to net metering are lifted. This scenario includes 850 kW of biodiesel.

7.2.3 100 % by 2020, Load shifting with batteries

We developed a scenario where we used storage not only for grid support but also for load shifting. This requires a significantly larger investment in storage. This scenario was barely cost effective having a benefit / cost ratio of .1.02. The load shifting technology in this scenario was batteries. We did not include any biodiesel in this scenario. The total spending for this scenario is the highest of all the scenarios at $294 M. This scenario includes 2.2 MW of utility scale solar, 2 MW of utility scale wind, and over 5.7 MW of storage for load shifting. 7.2.4 High Solar – 50 % by 2015 100 Percent renewable by 2020 with

biodiesel

This case has the most solar of any of the scenarios (49.6 %) and also uses biodiesel. This case has a benefit cost of 1.67 and a total spend of $171 M. This case uses batteries, pumped storage and storage cooling to load shift. This case meets the Prime Minister’s goal of 50 % by 2015 and 100 % by 2020. This scenario has 2 MW of utility scale wind; 2MW of utility scale solar; 450 KW of biodiesel; 1400 kW of storage for load shifting including 800 KW of batteries; 300 KW of small scale pumped storage and 300 KW of storage cooling where ice is made during the day to be used for cooing at night. This scenario also has over 8.6 MW of customer side solar. 7.2.5 50 % by 2015, 100% Renewable by 2020 using a mix of resource

for renewables and storage.

This case has a benefit cost (1.69) very similar to the previous scenario and a total spend of $186 M. This case also uses batteries, pumped storage and storage cooling to load shift. This case also meets the Prime Minister’s goals. It has a total spend of $186 M .This case includes 2 MW of offshore wind, 1 MW of onshore wind, 1 MW of utility scale solar and over 7.9 MW of customer side solar. This includes 3 MW of storage for load shifting including 2.2 MW of batteries, 500 kW of small scale pumped hydro and 300 KW of storage cooling. This scenario is similar to the last one but uses load shifting more to cover the nighttime load.


7.2.6 Recommended Scenario – 50 % Renewable by 2015; 100% Renewable by 2020; High Wind Case.

This case is the most cost effective case that meets the Prime Minister’s goals. It contains community wind, offshore wind and on shore wind. It has an overall benefit cost of 2.11 and a total spend or $141 M. It is significantly less expensive and more cost effective than the other scenarios. It also uses batteries, pumped hydro and storage cooling to shift load. The more significant use of wind in this scenario both on and offshore are the primary reason it is more cost effective. Less storage for load shifting is requires.

The renewable mix is shown below:

Figure 7.2: Renewable mix of Recommended Scenario

7.3 Analysis of the scenarios

All of the above scenarios require a significant amount of storage for grid stability even without being used to significantly shift load. In all cases we assumed that storage was needed and in the scenarios where there was a larger solar project we assumed larger scale storage was required in tandem with the larger projects. In the scenarios where we used storage for load shifting we used storage to replace all of the nighttime energy. Ultimately the key drivers for the timing and amount of storage over time will be the amount of customer side renewable energy and the size and timing of utility scale projects. The more TAU can manage the queue for renewable projects the easier it will be to project the need for storage. It would make sense for TAU to develop a process to manage a queue of customers who are ready to deploy net metering if the restriction is lifted. That way TAU could plan more effective to install grid storage as the additional customer side renewable come on line. This will be critical for grid stability. Also adding storage as a requirement in interconnection would provide more certainty as well. Cost and economic analysis must include the cost of reinforcing, upgrading and operating not only the distribution network but the diesel (or biofuel) based systems. These scenarios are meant to be representative of possible scenarios. The 50 % renewable scenario is the least costly from all aspects and the most cost effective. The scenario where we attempted to shift load using batteries was barely cost effective. The recommended scenario as it

Generation <2012 2012 2013 2014 2015 2016 2017 2018 2019 2020 Cum.Solar behind the meter 877 275 200 200 200 200 200 2,152 Net metered solar 200 500 550 550 400 400 300 300 200 3,400 Utility Scale Solar 500 500 Off-shore wind 2,500 2,500 Small Scale/ Community Wind 13 300 300 100 713 Utility (Onshore) Wind 3,000 3,000 Wave 50 50 Waste-to-Energy/ Biomass 420 420 Small Hydro - Empty - Empty - Sum Renewables 890 475 1,120 1,050 4,050 600 600 300 3,400 250 12,735


includes a lot of win requires less storage for load shifting due to the fact that less load shifting is needed to cover the night. The total annual costs of storage are presented below for all of the scenarios:

Figure 7-3 Storage Expenditures by Scenario

As the figure illustrates the 50% renewable scenario has the least storage costs. The

biodiesel scenario is the next least expensive. Both of these scenarios have costs on

average of about 2-2.5M per year for storage. The scenario in red represents recommended

scenario that includes batteries, storage cooling (in reverse) and pumped hydro.

The overall cumulative costs for the recommended scenario are shown below:

-

5,000,000

10,000,000

15,000,000

20,000,000

25,000,000

2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027

NZ$

Annual Storage Expenditures by Scenario

50% renewables: Total Storage Expenditures 100% renew w/ storage LS: Total Storage Expenditures

100% renew w/ biodiesel: Total Storage Expenditures High solar Total Storage Expenditures

Renewable and storage mix Recommended- Wind, Solar, PS


Figure 7-4 Cumulative Costs Over time- Recommended Scenario

As there is no biodiesel in this scenario all of the costs are either for renewables or for storage. In 2019 the pumped storage is added and from 2018-2027 batteries is replaced over time. Annual costs are shown below:

-

20,000,000

40,000,000

60,000,000

80,000,000

100,000,000

120,000,000

140,000,000

160,000,000

2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027

$NZ

total cumulative expenditures by fuel

Storage

Biodiesel

Renewables

Recommended-Wind, Solar, PS


Figure 7-5 Annual Expenditures – Recommended Scenario

7.4 First installations and Representative Costs Today

The economic modeling suggests slightly different amounts of grid storage by scenario. The initial increments of storage required are similar for the first years of all scenarios, namely 120 KW in 2012 and 240 KW in 2013. A summary of the storage required for recommended scenario is shown below:

Figure 7-6 Storage Over Time – Recommended Scenario

The scenarios with larger amounts of renewables clearly have larger amounts of storage for grid stability over time.We asked for representative costs from several battery manufacturers/ system integrators. We received actual costs from two companies. The first was a 120 kW/ 360kWh zinc bromide system. The representative costs we received from

-

5,000,000

10,000,000

15,000,000

20,000,000

25,000,000

30,000,000

2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027

$NZ

total annual expenditures by fuel

Biodiesel

Storage

Renewables

Recommended-Wind, Solar, PS

Sorage <2012 2012 2013 2014 2015 2016 2017 2018 2019 2020 Cum.1S Storage GS: Batteries developed 400 550 650 400 900 2,900 2S Storage GS: Batteries under development 120 240 360 720 3S Storage GS: empty - 4S Storage GS: empty - 5S Storage GS: empty - 6S Storage LS: empty - 7S Storage LS: Pump Storage Hydro 500 500 8S Storage LS: Batteries 600 500 1,100 9S Storage LS: Reverse Thermal Storage (Cold) 100 100 100 300

100% Loadshifting storage (MWh)/Amount of Biodiesel - - - - - - - - - - Sum Cum. - 120 360 720 1,120 1,670 2,320 3,420 4,920 5,520 5,520

Storage Capacity: Recommended Case Scenario Information

Added Storage Capacity in kW

Sto

rage

Cap

acity


the first in early July were: current cost is $700K complete and ready to install. To cover cost going forward for the next couple of years factor in about they estimate 5% per year to bed the system down and cover any short term issues. We used these cost for 2012- 2014 in our estimates in the economic viability study and here. We assumed by 2015 the costs would decline after that. The second was received on July 31, 2012.

This bid was for a single-system price for a turn-key installation in Rarotonga would be for a Zinc Bromide Flow battery and power electronics

o US $876,000 250kW inverter

• 500kWh of Flow battery modules • ECM (Comm Module) • 2x DC PCU structures (can hold up to 8 buckets total) • 300kVa transformer • Freight to Rarotonga, Foundation and weatherproof enclosure, Assembly,

connection and commissioning

o Optional PV DCv “buckets”; 25kW name plate rating at min voltage of MPPT (150-300VDC)

• US$7,800 each

The second bid as it is larger is significantly lower.

7.5 Costs of Storage for the Recommended Plan

The figure below presents the estimate costs of storage for both grid stability and load shifting for the recommended scenario. The cost we used were:

1) For batteries in the short term we used the prices we received from vendors for 2012-2015

2) For batteries beyond 2015 we used cost from the ES Select model

3) For Storage Cooling we used costs from the ES Select model

4) For pumped hydro we used the costs from Il Hierro as being representative of possible costs on Rarotonga.


Recommended Scenario – Storage Costs by Type

Figure 7-7: Cost of Storage Over Time – Recommended Scenario

7.6 Recommended Options for Rarotonga

There are tradeoffs between distributed storage and utility scale storage. The figure below illustrates the tradeoffs.

Figure 7-8 Trade- off between Central Storage and Distributed Storage

$0

$2,000,000

$4,000,000

$6,000,000

$8,000,000

$10,000,000

$12,000,000

$14,000,000

Total Storage Expenditures

Storage Load Shifting

Storage Grid Stability


Our recommendation for TAU is that the best mix of storage will include both distributed as well as utility scale. Absent a planned large scale renewable project and the fact that the storage technologies are changing rapidly we suggest TAU or private investors adds storage based on the renewable energy projects as they are built. We also suggest that TAU consider owning the storage for grid stability for non –utility scale projects and that for any utility scale storage that the grid stability storage is built in as part of the interconnection standards. This is being considered in other jurisdictions such as Hawaii and Puerto Rico who are experiencing high saturation of renewable energy.


8. Applications

We propose at this point that TAU’s initial storage installations be predominately for grid support only in the early years- 2012-2017Unless a Storage cooling sites or a pumped storage site were identified.

The scenarios we explored here suggest that a combination of storage cooling, battery storage and pumped for load shifting are cost effective for load shifting in the later years in some combination..

The model runs we did clearly suggested it is cost effective to replace some of the storage used for load shifting with biodiesel in any of these scenarios. These also suggest that using battery storage alone for load shifting is borderline cost effective.

We are not aware of any situation at a utility where storage is being used to shift load to cover load of many hours every day with the exception of conventional pump hydro systems. At present there are not identified pumped hydro sites for Rarotonga but it is attractive in this situation if a site can be found. Storage cooling does have a long discharge cycle as well, and is best used in a new building.

The use of storage for load shifting is very expensive from a societal perspective unless a pumped hydro site is feasible. The reason for doing that is to achieve the 100 percent renewable goal. This may become more economic over time. We suggest TAU and REDD monitor the relative cost effectiveness of both using storage for load shifting and biodiesel over time.


9. Siting

Our recommendations provide for both distributed storage as well as utility or larger scale storage. Distributed We anticipate most of the distributed storage will be on customer sites and will be mostly batteries. The below picture presents a Redflow residential unit.

There are few if any siting issues associated with residential storage. Another option is Community Storage. An example is shown below:

Figure 9-1: Overview of Community Storage


The most likely location for community storage would be at a transformer as shown above. Given placement at an existing utility site we do not anticipate any significant issues. Storage Cooling will be placed at the site as part of the cooling plant. There may be size limitations depending on the project but no siting issues are anticipated.

9.1 Larger scale

Larger Scale storage will most likely either be place near a utility scale project or potentially at a utility substation. A sample of a 1 Mw storage unit is shown below.

As discussed in the funding plan we anticipate that TAU may be the most likely candidate to invest in utility scale storage. One possible location is the proposed new power plant where modular storage could be easily placed much like the packaged engines. Given placement at an existing utility site we do not anticipate any significant issues with siting. The next most likely investor in larger scale storage would be a renewable developer. In that case it would be most likely located at the site of the renewable project. It is unlikely this would result in siting issues.

9.2 Suggested Initial Installations

We suggest the initial installation of 120 KW in late 2012 or first quarter 2013 and additional 240 KW installations by the end of 2013. Either of the zinc bromide options could be installed. The recommended site options would be the power station and or a substation.


10. Environmental Impacts

Each of the potential storage options have some impacts that were discussed in section 6. The recommended scenario contemplates a combination of battery storage, storage cooling in a reverse cycle, and a modest pumped storage plant. Biodiesel could be used to replace or supplement these options. A summary of the environmental impacts are shown below: Option Possible Environmental impacts Degree Batteries Spill of battery Acid

Landfill issues if not properly disposed of

Minor

Storage Cooling None Minor Small Pumped Storage Site specific impacts of

construction of the plant Very site specific – minor to major


11. Overall Funding Plan

Ownership Options At present the most likely owner of any small to mid size scale storage facilities for grid stability related to customer sided storage is TAU, given their role to ensure grid stability. This role is consistent with that of a distribution utility. TAU will need donor funding to invest in storage. It is possible a renewable project developer may chose to install storage as part of a larger utility scale project or a hybrid project where for example solar is used to charge batteries during the day and the batteries are discharged at night when needed. A developer also may install modest solar in a distributed manner along with numerous small projects. We do not anticipate anyone in the private sector will choose to build storage facilities without investment in a renewable project. Alternatively as part of the interconnection requirements of projects over 500kw (or another threshold) that storage for grid support we included as part of the project. This would be a requirement of building the project. As noted earlier this is being considered in a few jurisdictions. The most likely candidates for ownership of storage used specifically for load shifting is TAU. Funding Options In the course of our interview on Rarotonga we heard that:

o To meet goals significant private investment required o It was desired that the private sector be involved o Funding for Proven technologies only o A Practical approach is required o Long term plan and strategy important o Cooperation between REDD and other parties was critical o Information sharing will be critical o Value for the money spent was important o The possible Funding sources include:

• Global donor • Private investment • Solar or wind developer / with donor • Development of a revolving investment fund for renewable projects


Specifically some of the possible funders are more and less likely to be involved:

o Aus Aid – renewable supposedly not a major focus o EU focus- focus on water and waste o Asian Development Bank

• New energy efficiency activities starting • Possible funding for some projects as well as studies

o New Zealand Aid –focus: • waste sanitation • revitalising the pearl industry • Renewable energy support. • Tourism

Our assessment it that the best sources of either funding or low interest financing for TAU to invest in storage would be New Zealand Aid, the Asian Development Bank, and or private donors. A possible alternative would be to impose a “storage fee” on all renewable projects of a certain size – to collect the funding required to provide the storage related to grid support. As part of our interviews we did interview a number of the large resorts and retailers. We found that many of them are exploring or have installed some solar already. They not surprisingly would be very interested in the resumption of net metering. Some of them are willing to invest now and have the resources to invest. Others might need lower interest financing. None as of yet had invested to any large degree in storage. Some had mentioned they were considering it .


12. Action Plan

The suggested action plan for storage is presented below:

o Add storage for grid support in concert with the addition of renewable energy as percentage increases. We suggest that 20 -25 kW of storage be added for every 100 kW of renewable energy after reaching 1 MW.

o Use the interconnection process to manage and plan for the storage.

o Pilot initial battery storage kW of 120 kW in late 2012 / early 2013 at power house PV site or another location; followed by an a installation of 240-250 KW in 2013.

o For any large buildings (total load above 250 kW) explore whether ice storage is feasible for the HVAC system.

o Identify and manage a queue for net metering to be able to predict what solar in going in and where. Use this as a key indicator of future storage needs for grid stability.

o Identify an appropriate site for a community storage pilot of 50 kW possibly as part of any micro gird study.

o Monitor other storage technologies as they continue to evolve over time.

o Continue to look for additional base load renewable options to reduce storage needs – such as wave.

o Use storage cooling at non –traditional hours such as creating ice during the day to use at night.

o Follow developments in “non traditional pumped storage”; if feasible find a site for a pilot or installation.

o Perform a detailed siting study for pumped storage.

o Conduct a grid stability study.

o Use new base load technologies to increase renewable percentage over time along with wind and solar.

o Share information and results with REDD and other Stakeholders.

o We suggest TAU and REDD monitor the relative cost effectiveness of both using storage for load shifting and biodiesel over time.


o Have TAU invest in storage for grid stability associated with customer side renewable energy. Alternatively some type of “storage fee” could be paid to TAU by developers of smaller scale renewables.

o Make storage for grid stability required for utility scale projects be included as part of the interconnection requirements.

o Work with REDD and other parties to develop to develop a model for cost recovery of load shifting storage, where it is cost effective.


Appendix A - All renewable islands

Examples of all renewable islands To reach the Prime Minister’s objective, Rarotonga would be a 100 percent renewable island by 2020. We present details here about each of these projects. El Hierro There are a few examples of such islands El Hierro, Canary Islands The first of these is the El Hierro project in the Canary Islands. This project uses wind, solar and hydro pumped storage. Scale & Technology

• 11.5 MW wind – this project includes:

• 11.3 MW hydroelectric pumped storage • distributed control system (DCS) • interconnection substation & automatic generation control (AGC) • Serves 11,000 residents

o 80% electricity needs served by pumped hydro-storage system o 20% from solar thermal collectors & grid-connected PV systems

FunctionBy communicating with the wind farm, the control solution will automatically start releasing water from the upper reservoir to generate power at the hydroelectric plant whenever the wind power generated is insufficient to meet demand. Conversely, excess wind power will be used to pump water to the upper reservoir, for use when wind power is low.

:

Cost

: $87 million

Icaria, Greece – Hybrid Power Station19

The Hybrid Power Station (HPS) of Ikaria Island, Greece, is currently in the construction stage. The project will be one of the first wind-hydro-pumped-storage hybrid stations in the world.

The Ikaria HPS includes:

• 3 water reservoirs at sufficient altitude separation. • 2 small hydroelectric plants (SHP), both equipped with Pelton turbines, one at

Proespera (1 1.05 MW), to exploit excess water from Pezi dam and another at Kato 19 http://users.ntua.gr/stpapath/Paper_1.32.pdf



Proespera (2 1.55 MW), which exploits excess water from Pezi and also participates in pumped storage operation

• Combines two forms of renewable energy (wind via pumped storage and hydroelectric, via exploitation of excess water from the upper reservoir) using the same hydraulic infrastructure. This calls for an operating policy which will permit efficient exploitation of both sources, without disturbing the operation of the conventional generation system and other WFs in the island.

The operation of the SHPs is subject to restrictions imposed by the environmental terms of the station. While the pumped-storage mode of operation, cycling water between the two lower reservoirs, is permitted throughout the year, hydroelectric operation is only possible from October 1 to April 30 (in the so-called “winter period”). During this period, a specified minimum water level must be ensured at the Pezi reservoir, while all excess water can be used for energy generation (hydro operation). In the “summer period” (May 1 to September 30) the SHP at Proespera is not operating.


Figure 0-1 Icaria, Greece – Hybrid Power Station Schematic20

Bonaire- Dutch ABCs in the Caribbean After Bonaire's only power plant burned down in 2004, the island's government wanted not only to restore energy generation to the island, but also to generate that energy from 100% renewable sources. While temporary diesel generators provided power for the short term, the government began working with the local energy company to devise a plan to reach the 100% renewable energy goal. Eventually a consortium, EcoPower Bonaire BV, won the contract to develop the plan, which includes investment in research, wind turbines, and a facility that will produce biodiesel from algae. Island Background The island of Bonaire is 250 square kilometers (km) and is located 80 km north of the Venezuelan coast. During its long history, it has been used as a prison, a plantation island, and a salt production center. Today the island's outstanding marine environment also attracts a modest number of tourists.

20 http://users.ntua.gr/stpapath/Paper_1.32.pdf



With a population of 14,500, Bonaire's peak electricity demand is approximately 11 megawatts (MW). The island's power needs are currently served by a set of rented container (light-fuel) diesel generator systems that have a rated capacity of 12 MW. In a typical year, Bonaire consumes 75,000 megawatt hours (MWh) of diesel-generated electricity.

Project Partners

EcoPower Bonaire BV consortium: o Econcern: Project developers for the Bonaire project and the majority shareholder

(90%); responsible for project development, contracting, financing and operation (view an Econcern graphic depicting a fictional island with several renewable energy activities that work together in a sustainable-energy system)

o Enercon: A German wind turbine and system supplier that is responsible for the wind-diesel load balancing system and that will supply wind turbines (5% shareholder)

o MAN: A German truck and engine manufacturer that will supply diesel generators (5% shareholder)

Water and Energy Company of Bonaire: Government-owned Company, which produces and distributes water and electricity on the island. The company signed an agreement with Ecopower Bonaire BV to purchase all electricity produced by the project. Project Motivation

With the new system, it is expected that power consumers on Bonaire can expect a 10%–20% reduction in their electricity bills. This rate reduction will go into effect the first day the project goes online. This will also substantially reduce the island's dependence on oil, with its fluctuating and steadily rising prices, and increase the reliability of electricity. The combination of algae production, the wind turbine facilities, and the biodiesel plant are expected to create jobs and boost the island's employment. This project's island setting will act as a working, small-scale model of wind energy providing a significant portion of the energy in an overall electricity grid, and can later be scaled up for larger applications.

http://edinenergydev.nrel.gov/pdfs/bonaire_sustainable_island.pdf�

http://edinenergydev.nrel.gov/pdfs/bonaire_sustainable_island.pdf�


Project Timeline

Courtesy of Ecofys Netherlands BV


Timeframe

September 2006: The Memorandum of Understanding (MOU) was signed between EcoPower Bonaire BV and the Water and Energy Company of Bonaire (locally known as Water en Energie Bedrijf Bonaire or WEB).

November 2007: EcoPower Bonaire BV signed a power purchase agreement (PPA) with WEB for the whole system.

The project's implementation was scheduled to take place in two phases spread over 2007 and 2009.

o Phase I: In 2007, EcoPower installed a 330-kilowatt (kW) Enercon E-33 wind turbine at Sorobon. This area is on the southeast coast of Bonaire, where the average wind speed is about 9.1 meters per second (m/s). The existing grid cable connection provided sufficient capacity to accommodate one medium-size wind turbine.

o Phase II: This phase involved the construction of a wind-diesel plant consisting of an 11 MW wind farm and a 14 MW diesel power plant. This plant


was also designed to have 3 MW of battery storage backup to optimize the wind contribution and to improve the grid quality.

Project Strategy

The first project phase's main objective was to gain experience with wind power on Bonaire and reduce short-term electricity generation costs. At the site where the turbine was installed, there was already good wind data, and the first year's data indicated how much power the turbine could deliver. Under the proposed plan, wind energy turbines are intended to provide 40% to 45% of Bonaire's total electricity requirements. Over the long term, local staff will be trained to maintain the Enercon direct drive (gearless) turbines. The project deliberately concentrates on turbines of sub megawatt size for transport logistics and maintenance reasons. All installation and maintenance activities can be performed with a 500-metric-ton crane. The project developers may later reconsider applying additional "booster" technologies, such as flywheels and other short-term energy storage systems. In the next several years, the project will start producing biodiesel from algae to run the diesel generators. The consortium needs at least 3 to 5 years of research and development for this technology to be viable in the island's energy plant. Currently, the plant can produce algae in industrial-scale quantities, but the consortium needs to figure out optimal biofuel-producing configurations. The consortium will eventually need 10,000 metric tons of algae each year to run the power plant. Another part of the project will focus on training local people to perform corrective and preventative maintenance on the system, along with some hard engineering. The consortium

hopes to start educational programs in local schools so that Bonaire can build a "green" island culture. System Specifications

o Wind-diesel power plant

• 11 MW wind capacity: The initial turbine is an Enercon E-33 wind turbine (330-kW unit). The wind farm will consist of twelve 900-kW E-44 turbines (rotor

diameter 44 meters). Each wind turbine is expected to operate at a high capacity, resulting

in around 3,500 full load hours annually. • 14 MW biodiesel power plant • 3 MW of battery storage backup


Power management system: 10 km of cable from wind farm to power station; 30-kilovolt transformer station


Financing The cost of Bonaire's new wind-diesel system is approximately US$60 million, with an expected return of around $15 million per year from power. Part of this investment will be recovered through Econcern's selling of carbon dioxide credits (that will likely be Gold Standard). Rabobank (Netherlands) provided nonrecourse financing with a 20% equity/80% debt ratio. Shareholders include Ecofys (90%), MAN (5%), and Enercon (5%).

Major Hurdles and Lessons Learned

Since implementation, there has been good political support from the government of Bonaire. The most difficult parts of the project were the contracting phase and securing financing. Contracting took place in 2007 and 2008 when contracting prices were at an all-time high.


In 2009, due to the credit crunch, Econcern—the main shareholder—went bankrupt. Rabobank decided to take over the project and made sure it was completed. In addition, local permit procedures were inadequate to support such a complex project. Despite these hurdles, however, the project was completed, proving that the concept is strong.

Current Status:

o The new power plant has been in operation since August 2010 and is performing well.

o The wind farm has been phased in gradually, but the highest instantaneous wind share has already been more than 80%.

o The targeted average wind share of 40%–45% will most likely be met. A more accurate estimate will be available.

o The power management system and the battery have been performing above expectations. Power quality and grid stability are good.

o The reliability of the single (test) Enercon turbine at Sorobon has been more than 99% since 2007, without any significant maintenance. This is a strong indication that the choice for the slightly more expensive (than some competitors) Enercon turbines pay for themselves in lower maintenance costs and superior power quality.

o The turbine supplier has guaranteed the fuel savings, and the system is reducing Bonaire's electricity costs. Moreover, the island now has a strong hedge against future fossil energy price hikes and is on track to achieving 100% sustainability through its algae/biofuel option.

References

The following resources provided information about this project.

Ecofys Group

Joris Benninga, Real New Energy

http://www.ecofys.com/com.htm�

mailto:[email protected]�

http://www.realnewenergy.com/index.html�


Appendix B - Findings from KEMA’s interviews

As part of the assignment, KEMA has conducted a series of interviews and consultations with stakeholders in Rarotonga from January to May 2012. Findings from the interviews are summarised below by topic area. Waste to Energy

This summarises the information we received regarding the possibility of a waste to energy plant. We collected most of our data through interviews- little was from actually records.

There are no credible waste source records. Data have been collected from refuse collecting businesses; recycle businesses and the Ministry of Planning & Infrastructure.

There is a high level of waste separation practice in businesses and the community. It is estimated that 70% of waste to the landfill are recyclables. Plastic bottles and cans are packed and sent back to New Zealand. Cardboards are also packed and sent back to New Zealand. It is noticed that sending recyclables to New Zealand doesn’t make economic sense. Specifically:

o Landfill receives 11-12 tons per day or 66-72 tons per week – this included recycling

o Much of the combustible trash (yard waste, wood waste, and paper, cardboard) is not going to the landfill)

This will change the heat content of the trash going to the landfill

It is a common practice that yard wastes – could be significant – is burnt at homes.

There is some small amount of wastes from flights at the airport.

The yard waste and commercial wood waste could be significant but the numbers cannot be confirmed.

Interviews the week of 4-23 with both T&M indicate that they produce significant waste wood which is currently being land filled in the quarry. This could be as much as 20 trucks per month. They are willing to sell their waste.

There is an incinerator at the hospital and one at the airport burning bio-wastes.

The Grower’s Association is planning for a small bio-digester plant. They are currently focussed on composting but expect to apply for grants to develop a small scale bio digester plant. They are also exploring growing algae for biodiesel. The Grower’s association has


been educating the community about the harm of burning waste and is encouraging residents to give their waste to the growers.

Renewable Energy development in Rarotonga and infrastructure

Net-metering

TAU introduced a Net-Metering Policy in November 2009. The Net-Metering policy provided economic incentives to customers interested in grid-tied renewable energy installations under 10kW capacity, allowing for credits to accumulate over time from the excess energy fed back into the grid.

The response to the Net-Metering policy from the public has been overwhelming. By the end of January 2012, 59 projects were installed with the total capacity of 288kW. The projection of the installed renewable energy capacity will exceed 600kW by 2012. Noticeably, most installations are PV projects.

Due to network safety and power quality concerns, TAU issued an amended Net-Metering policy on 1st October 2011 to limit the individual installed capacity under 2kW.

The new Net-Metering policy has restricted direct grid connection for PV installations greater than 2kW. However, the high cost of electricity is driving the high demand of PV installations, particularly for businesses where energy costs are significant. Even without “Net-Metering” benefits many projects are still considered viable. Some of these projects have some level of battery storage as “counter-cloud measure”, i.e., to draw power from batteries for up to 30 minutes to local loads in the case of cloud caused power down instead of drawing power from the grid.

Under current electricity tariff the simple payback of PV projects is under 6 years. With the cost-down trend of PV systems, the viability of PV installations will further improve over the years. Therefore it is expected the organic growth of PV installations will continue for the foreseeable future. The growth rate is expected in the range of ~500kW per year.

There are strong interests in PV in the community. Resume of Net-Metering or other similar policies will drive further PV installations in Rarotonga. RE investment from private sector There is also interest from the private sector in PV/RE investment as IPP. When the government and/or TAU set the right policy framework, investors can contribute to larger (utility) scale RE project development.


A concern has also been raised to help disadvantaged families to cope with the challenge of high energy costs. While it was clear that some end use customers have already invested in solar or plan; not all have the resources to do so. There is interest in subsidized loans schemes. Infrastructure Up to now TAU has not invested in energy storage or control upgrade to cope with RE penetration. It is expected to stop PV/RE grid connection when the capacity excess 1MW which might happen by the end of 2012. It is understood that grid-connected-not-for-export installations will continue. These may impose risks to network stability. Land Where land is a scare resource in Rarotonga, some land owners have expressed interest in using their land for RE development. Large End Users

Large businesses expressed their concerns on high electricity costs. Most of them have implemented energy efficiency measures and are interested in RE/PV development for off-set their electricity bills. Some of them are interested in develop greater RE capacity to be IPPs. Most of businesses expressed confusions in regard to the uncertainty and inconsistency of government/TAU policies. In regard to barriers to RE/PV development, land/roof space is an issue. Others expect help from the Government/Aid to provide lower interest loans for RE projects. Aid Management

The 50/2015 and 100/2020 targets require significant investment into renewable energy development in Rarotonga. REDD’s estimate is $208m. Aid Management is supportive for renewable energy development. However their view is that funding from Aids is limited and can only be used to leverage investment from private sectors. Aid Management has certain criteria for project selection. Key requirements include:

o Proven technologies


o Practical approach o Long term plan and strategic o Value for money

The EU will be mostly focussed on waste and water infrastructure over renewable energy. ADB is funding some larger energy efficiency projects and may be a source of funding for studies related to renewable energy and for pilots. NZ Committed to assisting renewable energy development. Energy Storage

Currently there is no energy storage installed by TAU.

There are some battery storages installed in recent customer projects. These are mostly “anti-cloud” measures, allowing 30min power exported from batteries to local load.

TAU has no data on installed customer storage capacity.

Some large customers expressed interest to use their site for TAU’s energy storage installations.

The new government building could be a potential site for energy storage (ice storage and/or battery).

Possible Steam Loads for Co-generation The hospital has a substantial hot water load. They are mostly interested in pursuing solar hot water. There are energy efficiency opportunities at the hospital as well. The hospital could be a suitable site for a co-generation plant using waste Pellets as fuel. Snowbird Laundry also has a significant hot water load. They actually buy TAU’s waste oil for one of their boilers and at the moment Co-gen does not make sense because of that.


Appendix C - Stakeholder interviewed/consulted January – May 2012

Organization Name

Te Aponga Uira (TAU) Apii Timoti, Charles Koronui, Teiti Paio, Tama Heather, Rangi Nooana, Chris Manu, Trevor Pitt, Alex Napa

Renewable Energy Development Division (REDD) Tangi Tereapii, Repeta, Puna T&M Heathers Joe Heather, Rob Heather Ministry of Planning & Infrastructure Tai Nooapii Cook Islands Investment Corporation Tamarii Pierre Environment Service Vaitoti Tupa Aid Management Division Jim Armstead Crown Beach Resort & Spa Rohan Ellis Pacific Resort & Spa Greg Stanaway Rarotongan Beach Resort & Spa Tata Crocombe Muri Beach Club Liana Scott Edgewater Resort Rarotonga Hospital Dr Henry Tikaka Andersons Electrical Steve Anderson CITC Trevor Clarke, Gaye Whitta Land owner Iaveta Short, Rebecca Short Growers association Robert Matapo & Teava Iro Sunbird Laundry Solar Installer/ Supplier John Koteka EU Representative George Turia Solar Bob

Manea Foods James Beer New Zealand High Commission John Carter


Appendix D - Product Specifications Zinc Bromide Batteries:

Information on Zinc Bromide batteries can be found at:

ZBB – www.zbbenergy.com

Redflow- www.redflow.com.au

http://www.zbbenergy.com/�

http://www.redflow.com.au/�








RedFlow M120 - Solar

Addressing the challenges of unreliable and intermittent solar generation.

The RedFlow M120, due for commercial release in late 2011, is a 120 kVA, 240 kWh containerised energy storage system designed to maximise the value of large-scale PV generation by reducing intermittency, time shifting off peak generation and improving base load equivalence. The system is a scalable, turnkey storage solution, which significantly improves solar asset utilisation. The RedFlow M120 unit is relocatable, transportable and modular. Its power electronics ensure scalability, voltage control and phase shifting, achieved through full four-quadrant power management and real time grid monitoring. Control can be autonomous or via integration with utility SCADA systems. The RedFlow M120 can be deployed as a single unit or multiple units to create flexible, ready-to-run megawatt scale storage systems capable of storing more than 2,000kVA.


Appendix E - Costs of Storage used in Economic Viability model:

CAPEX OPEX (var) OPEX (fixed)Storage In/Out NZD/kW NZD/MWh NZD/kW Life Discount RateStorage GS: Batteries developed 2,750$ -$ 27.00$ 15 12.50%Storage GS: Batteries under development 7,500$ -$ 27.00$ 15 12.50%Storage GS: empty -$ -$ -$ 0 0.00%Storage GS: empty -$ -$ -$ 0 0.00%Storage GS: empty -$ -$ -$ 0 0.00%Storage LS: empty -$ -$ -$ 0 0.00%Storage LS: Pump Storage Hydro 5,200$ -$ 47.00$ 15 12.50%Storage LS: Batteries 2,750$ -$ 27.00$ 15 12.50%Storage LS: Reverse Thermal Storage (Cold) 2,400$ -$ 12.00$ 15 12.50%

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