A Baseline for PV Hybrid System Performance and Potential …€¦ · essentiellement un système groupe électrogène/batterie auquel l’on a ajouté une matrice PV. Le rendement

DEVON . OTTAWA . VARENNES

(I A BASELINE FOR PV HYBRID SYSTEMi PERFORMANCE AND POTENTIAL

AVENUES FOR IMPROVEMENT

-- ....

CLEAN ENERGY TECHNOLOGIESTECHNIQUES D'ÉNERGIE ÉCOLOGIQUE

------- - -- - - ----C TEe CENTRE DE LA TECHNOLOGIE DE L'ÉNERGIE DE CANMET

1+1 Natural ResourcesCanada Ressources naturellesCanada Canadã

Report – CETC-Varennes 2006-058 (TR) October 2005

A BASELINE FOR PV HYBRID SYSTEM PERFORMANCE AND POTENTIAL

AVENUES FOR IMPROVEMENT

Prepared by:

Michael M. D. Ross RER Renewable Energy Research

2180 av Valois, Montréal (Qc)

H1W 3M5 [email protected]

Presented to:

Marc-André Fry & Dave Turcotte CANMET Energy Technology Centre - Varennes

http://cetc-varennes.nrcan.gc.ca

Under contract #5-1289MF

October 18, 2005

Report – CETC-Varennes 2006-058 (TR) October 2005

DISCLAIMER

This report, prepared on the behalf of the Government of Canada, is distributed for informational purposes and does not necessarily reflect the views of the Government of Canada nor constitute an endorsement of any commercial product or person. The Government of Canada and its ministers, officers, employees and agents make no warranty with respect to this report nor do they assume any liability arising from this report.

CITATION

Ross, Michael, A Baseline for PV Hybrid System Performance and Potential Avenues for Improvement, report # CETC-Varennes 2006-058 (TR) CANMET Energy Technology Centre – Varennes, Natural Resources Canada, June 2005, 48 pp.

ACKNOWLEDGEMENT

Partial finding for this study was provided by the Panel on Energy Research and Development (PERD).

Report – CETC-Varennes 2006-058 (TR) i October 2005

SUMMARY

In order to gage the potential improvements associated with proposed changes to photovoltaic hybrid system design and operation, a “baseline”, or characterisation of the typical hybrid system design and operation at the outset of the research program, is required. This report presents such a baseline, along with a description of the methodology used to prepare it.

The baseline establishes a point of comparison for systems providing electricity to small off-grid loads. Four options are considered: a prime power system, consisting of a genset and, for DC loads, a rectifier; a genset-battery system, consisting of a genset, battery, charge controller, inverter and rectifier; a photovoltaic-battery system, composed of photovoltaic array, battery, and inverter; and a PV hybrid system, essentially a genset-battery system with a photovoltaic array added. The performance of these systems at various Canadian sites is simulated, and a suite of benchmarks, such as genset fuel consumption and run time, are calculated. These benchmarks are used to determine the annual operating costs, overall cost of electricity, and greenhouse gas emissions of the four systems. The findings are summarized in the table below, assuming the climate of Toronto (for the photovoltaic systems), a delivered diesel fuel cost of $2.00/l, and an application requiring relatively high reliability.

Prime Power Genset-Battery

PV Battery PV Hybrid

Cost of Electricity $13.55/kWh $3.38/kWh $3.08/kWh $2.26/kWh

Operating Costs (Fuel +Genset Maintenance)

$9.25/kWh $2.04/kWh 0 $0.71/kWh

GHG Emissions per MWh 9.0 tCO2 2.62 tCO2 0.82 tCO2 1.14 tCO2

A number of variations on the baseline PV-hybrid system are also considered, to see what impact these deviations may have on the benchmarks. Two of these are weaknesses prevalent among current Canadian PV-hybrid systems, namely undersized rectifiers and batteries that fail prematurely. Other variations investigate several potential avenues for improving hybrid system performance, including larger arrays, reduced part load operation, and better utilisation of solar energy. It is found that compared to the baseline PV hybrid system, systems with improved component sizing and control may be able to reduce annual operating costs by 60%, the cost of electricity by 11% and the greenhouse gas emissions by 38%. Compared to some existing PV hybrid systems that perform poorly but may nevertheless be considered typical, an improved PV hybrid system may reduce annual operating costs by 67%, the cost of electricity by 21% and the greenhouse gas emissions by 51%.

Report – CETC-Varennes 2006-058 (TR) ii October 2005

In the PV hybrid systems examined here, a solar fraction of 65% could be achieved without much solar energy being wasted; higher solar fractions resulted in increasingly higher levels of waste. Nevertheless, when fuel prices are high, overall cost of electricity is lowest with arrays roughly 25 to 45% larger than that achieving the 65% solar fraction; these arrays achieve solar fractions in the neighbourhood of 75 to 85%.

The current practice of using rectifiers with capacity far below the nominal output of the genset should be investigated, as it significantly increases annual operating costs, the cost of electricity and greenhouse gas emissions. In particular, it should be determined whether the maximum battery charging currents recommended by many manufacturers need be so low (often they do not exceed the four or five hour rate); whether genset dispatch strategy can allow high charging currents without the absorb charging voltage threshold being reached at a low state-of-charge; and whether currently available chargers cause part load operation due to practical considerations such as power factor.

Report – CETC-Varennes 2006-058 (TR) iii October 2005

RÉSUMÉ

Afin d’évaluer les éventuelles améliorations liées aux changements qu’il est proposé d’apporter à la conception et au fonctionnement des systèmes hybrides photovoltaïques (PV), une « base de référence », ou une caractérisation de la conception et du fonctionnement du système hybride typique au début du programme de recherche, est nécessaire. Ce rapport présente cette base de référence ainsi qu’une description de la méthode utilisée pour la produire.

La base de référence établit un point de comparaison pour les systèmes alimentant de petites charges hors réseau. Quatre options sont prises en considération : un système de production d’énergie primaire qui consiste en un groupe électrogène et, pour les charges en courant continu, en un redresseur; un système groupe électrogène/batterie qui consiste en une génératrice, une batterie, un contrôleur de charge, un onduleur et un redresseur; un système PV/batterie qui se compose d’une matrice PV, d’une batterie et d’un onduleur; et un système hybride PV qui est essentiellement un système groupe électrogène/batterie auquel l’on a ajouté une matrice PV. Le rendement de ces systèmes à divers sites canadiens est simulé et une série de points de repère, comme la consommation de carburant et la durée de fonctionnement du groupe électrogène, sont calculés. Ces points de repère sont utilisés pour déterminer les coûts d’exploitation annuels, le coût global de l’électricité et les émissions de gaz à effet de serre (GES) des quatre systèmes. Les constatations sont résumées dans le tableau ci-dessous, pour le climat de Toronto (pour les systèmes PV), un coût à la livraison du carburant diesel de 2,00 $/l et une application nécessitant une fiabilité relativement élevée.

Énergie primaire

Groupe électrogène

/batterie

Système PV/batterie

Système hybride PV

Coût de l’électricité 13,55 $/kWh 3,38 $/kWh 3,08 $/kWh 2,26 $/kWh

Coûts d’exploitation (carburant + entretien du groupe

électrogène)

9,25 $/kWh 2,04 $/kWh 0 0,71 $/kWh

Émissions de GES par MWh

9,0 t CO2 2,62 t CO2 0,82 t CO2 1,14 t CO2

En outre, diverses variations pour le système hybride PV de référence sont prises en considération pour voir quel impact ces écarts peuvent avoir sur les points de repère. Deux de ces variations sont des lacunes des actuels systèmes hybrides PV canadiens, à savoir des redresseurs trop petits et des batteries qui tombent en panne prématurément. D’autres variations permettent d’étudier d’éventuelles avenues pour améliorer le rendement des systèmes hybrides, notamment

Report – CETC-Varennes 2006-058 (TR) iv October 2005

des matrices plus grosses, un fonctionnement à charge partielle réduit et une meilleure utilisation de l’énergie solaire. Il a été constaté que, par rapport au système hybride PV de référence, les systèmes dont les dispositifs de contrôle et les dimensions des composants ont été améliorés pourrait réduire les coûts d’exploitation annuels de 60 %, le coût de l’électricité de 11 % et les émissions de GES de 38 %. Comparativement à certains systèmes hybrides PV existants qui ont un piètre rendement mais qui peuvent néanmoins être jugés représentatifs, un système hybride PV amélioré pourrait diminuer les coûts d’exploitation annuels de 67 %, le coût de l’électricité de 21 % et les émissions de GES de 51 %.

Dans les systèmes hybrides PV examinés ici, une fraction solaire de 65 % pourrait être réalisée sans que beaucoup d’énergie solaire soit perdue; les fractions solaires plus importantes se traduisent par des niveaux de perte de plus en plus élevés. Néanmoins, lorsque les prix du carburant sont élevés, le coût global de l’électricité est le plus bas avec des matrices qui sont de 25 à 45 % plus grosses que celles qui permettent la fraction solaire de 65 %; ces matrices permettent des fractions solaires de l’ordre de 75 à 85 %.

La pratique courante qui consiste à utiliser des redresseurs ayant une capacité de beaucoup inférieure à la capacité nominale du groupe électrogène devrait être examinée, parce qu’elle accroît de façon notable les coûts d’exploitation annuels, le coût de l’électricité et les émissions de GES. Plus particulièrement, il devrait être déterminé si les courants de charge maximaux des batteries recommandés par de nombreux fabricants doivent vraiment être si peu élevés (souvent, ils ne dépassent pas la marque des quatre ou cinq heures); si une stratégie de mise en service des groupes électrogènes peut permettre des courants de charge plus élevés sans que le seuil de tension de la charge d’absorption soit atteint à un faible état de charge; et si les chargeurs actuellement disponibles entraînent un fonctionnement à charge partielle en raison de considérations d’ordre pratique comme le facteur de puissance.

Report – CETC-Varennes 2006-058 (TR) v October 2005

CONTENTS

1 INTRODUCTION.................................................................................................................................. 1 2 METHODOLOGY................................................................................................................................. 3

2.1 Simulation Details ........................................................................................................................ 3 2.2 Benchmarks of System Performance............................................................................................ 9

3 BASELINE........................................................................................................................................... 11 3.1 Operational Benchmarks ............................................................................................................ 11 3.2 Cost of Electricity ....................................................................................................................... 14 3.3 Residential PV Hybrid System ................................................................................................... 18 3.4 Production Energy and Greenhouse Gas Emissions................................................................... 19

4 AVENUES FOR HYBRID SYSTEM IMPROVEMENT ................................................................... 24 4.1 Rectifier Sizing ........................................................................................................................... 24 4.2 Battery Lifetime.......................................................................................................................... 27 4.3 Larger Arrays.............................................................................................................................. 28 4.4 Reduced Part Load Operation..................................................................................................... 30 4.5 Improved Utilisation of Solar Energy......................................................................................... 33 4.6 Comparison of Options............................................................................................................... 36

CONCLUSIONS......................................................................................................................................... 38 RECOMMENDATIONS............................................................................................................................ 39 REFERENCES ........................................................................................................................................... 40

Report – CETC-Varennes 2006-058 (TR) vi October 2005

1 INTRODUCTION

Within the context of photovoltaic technology, the term “hybrid systems” refers to power sources combining a photovoltaic generator with one or more generators drawing on non-solar energy resources. Often these systems are used off-grid, that is, to supply electricity to sites not serviced by an electrical network, such as remote homes, monitoring equipment, and telecommunication repeater stations. In Canada, hybrid systems typically combine a photovoltaic array with a fossil-fuel driven generator (a “genset”); systems also include lead-acid batteries for energy storage over the period of a day to several days, controllers to manage charging of the battery, controllers to effect genset dispatch (starting and stopping), and circuitry to convert between AC and DC, as required.

Since 1998, the Photovoltaics and Hybrid Systems group of the CANMET Energy Technology Centre—Varennes (CETC-V), with the assistance of the NRCan Program on Energy Research and Development (PERD), has researched the optimal utilisation of hybrid systems in Canada. The overall goal of this effort has been to enlarge the market for photovoltaic technology by assisting the Canadian PV industry build better hybrid systems and by disseminating information about the capabilities and operation of hybrid systems to consumers and potential consumers. A number of activities aimed at this goal are presently underway: a half-dozen hybrid systems in various parts of Canada are monitored to determine the operational behaviour of existing systems; a regular newsletter is published and widely distributed (e.g., [Roussin and Turcotte, 2004]); and a flexible PV simulation package (“PV Toolbox”, developed by CETC-V [Sheriff et al., 2003]) and a configurable physical hybrid system test bench (also built under the auspices of the hybrid system program) are being used in a cycle of simulation and verification to improve understanding of how hybrid systems function—and how they may be improved.

In order to gage the potential improvements associated with proposed changes to hybrid system design and operation, a “baseline”, or characterisation of the typical hybrid system design and operation at the outset of the research program, is required. This report presents such a baseline, along with a description of the methodology used to prepare it.

The baseline establishes a point of comparison for systems providing electricity off-grid. The baseline assumes an average power load of 300 W. Four options for meeting such a load are considered: a prime power system, consisting of a genset and, for DC loads, a rectifier; a genset-battery system, consisting of a genset, battery, charge controller, inverter and rectifier; a photovoltaic-battery system, composed of photovoltaic array, battery, and inverter; and a PV hybrid system, essentially a genset-battery system with a photovoltaic array added. The performance of these systems at various Canadian sites is measured according to a suite of benchmarks, such as genset fuel consumption, that give an indication of their relative operation and maintenance costs as well as greenhouse gas emissions.

Report – CETC-Varennes 2006-058 (TR) 1 July 2005

So that the baseline can better serve to evaluate future proposed improvements to hybrid power systems, this study includes a financial analysis of the overall life-cycle cost of providing power. This is necessary since the benchmarks relate to operational and maintenance costs, but in actuality the total cost is of interest. For example, genset fuel consumption, a critical operational cost, can be minimized simply by using a larger array and battery, but since this will increase capital costs, this is not necessarily an improvement.

The baseline also includes an analysis of the total energy used for each of the systems, including both the energy required in production of the equipment and the energy in the fuel consumed, and an estimate of the greenhouse gas emissions of each of the options. This allows the different options, and potential future improvements to hybrid systems, to be evaluated not simply on cost, but also on environmental impact.

Preparation of the baseline involved a survey of the operation of existing systems. This survey was also useful for providing some guidance on areas where optimization may be most fruitful. These are also touched upon in this report.


2 METHODOLOGY

The most accurate way to establish a baseline would be to survey the entire Canadian stock of hybrid systems, select a handful of systems that were representative—regionally and by application—and then monitor their performance. This is not a feasible approach, however, since costs would be prohibitive. Moreover, it runs up against the shortcoming of any baseline derived from measurements on a real system: one of the drivers of system operation, the weather, is completely outside of the analyst’s control, and can not be reproduced for testing of future systems.

A more workable approach, and one that permits testing of future systems under the same meteorological conditions, is to use simulation. This is the approach that has been taken here: the PVToolbox, a simulation tool developed at CETC-Varennes, has been used to simulate prime power, genset-battery, PV-battery and PV hybrid power systems for five locations across Canada. The output of these simulations has been a series of benchmarks of system performance.

2.1 Simulation Details

The PVToolbox is a library of component models implemented in the Matlab/Simulink environment [Sheriff et al., 2003]. The components, which correspond to the components in a real hybrid system, can be interconnected according to the topology of the system to be simulated. Then the Simulink simulation engine simulates the system; in this study, an ODE45 variable time step solver, with a minimum time step of one hour was used.

For simulation of major energy flows within hybrid systems, the PVToolbox has generally demonstrated accuracy of within 5 to 8% [Ross et al., 2005]. Given that the variation in many of the benchmarks examined in this study is around 15%, this may seem inadequate. It is important to recognize, however, that if the simulation has a bias, and this is applied equally to two different systems, then comparative differences of smaller than the expected level of accuracy of the tool can be identified. In other words, this study proceeds under the assumption that the PVToolbox will be able to, for example, accurately identify a system as being, say, 2% better than another similar system, even though its estimate of the performance of both systems is out by 5 to 8%.

In contrast, the models used by PVToolbox to estimate component aging have not been validated against monitored data, and are likely to be less accurate. In particular, the battery model can offer only a crude estimate of the battery aging, and will not record the impact of abusive cycling, such as occurs when the battery is consistently undercharged.

An average load of 300 W was assumed. In one series of simulations, a constant, 300 W DC load was used; in a second series, a 50 W DC load and a varying AC load were used. The diurnal


pattern of variation in the AC load is shown in Figure 1. With integration error, the average AC load is around 253 W, so the total load in the AC case is 303 W.

Figure 1 Diurnal Variation in AC Load (in watts) over Two Day Period

For the hybrid power systems, five sites across Canada were chosen: Vancouver, Edmonton, Inuvik, Toronto, and St. John’s. For each of these five sites, monitored hourly weather data for the five year period of 1980 through 1984 were used. These data were taken from the CWEEDS data set [Meteorological Service of Canada, 2003]. The benchmarks were calculated on an annual basis for this period, and then the values for the five years averaged.

The prime power system consists of a 5 kW diesel genset and a 300 WDC rectifier. The genset runs throughout the year. While a smaller genset would make more sense for such a load, in reality, few diesel gensets of less than 5 kW are available, and gensets running on gas or gasoline would not be suitable for such an application.

The genset battery system consists of a 5 kW diesel genset, a rectifier, a battery and a control system, responsible for turning the genset on when the battery has drained down to a 40% state-of-charge and turning it off when charging is considered complete. In the case of AC/DC loads, a 1500 W inverter is also included. A nominally 24 V system is assumed.

Various implementations of the genset-battery system were investigated, as detailed in Table 1. Two different battery sizings were used: a 24 kWh battery (which, if fully charged would be able


to satisfy the load for two days before discharge was terminated by the 40% state-of-charge criterion), and a 12 kWh battery (providing one day of storage). Most battery manufacturers recommend charging currents no higher than the 5 hour rate; with a 24 kWh battery, the maximum current produced by the genset corresponds to the 5 hour rate, but with the 12 kWh battery it is equal to the 2.5 hour rate. A 5 kW rectifier was used, except in one case, where it was replaced by a 2.5 kW rectifier. In reality, the rectifier capacity is often smaller than the genset capacity, either because it is included as part of a bidirectional converter selected on the basis of the AC load, or because the battery charge rate must be limited; a system with a 2.5 kW rectifier gives some indication of how such systems will function.

Table 1 DC Genset-Battery Systems Investigated

System Battery Rectifier End of charge Equalisation

No equalisation 24 kWh 5 kW Absorb starts Never

2 hrs absorb 24 kWh 5 kW 2 hrs absorb Never

3 hrs Eq every 2 weeks 24 kWh 5 kW Absorb starts 3 hrs every 14 days

No Eq, small rectifier 24 kWh 1.5 kW Absorb starts Never

No equalisation 12 kWh 5 kW Absorb starts Never

2 hrs absorb 12 kWh 5 kW 2 hrs absorb Never

3 hrs Eq every 2 weeks 12 kWh 5 kW Absorb starts 3 hrs every 14 days

The various implementations of the genset-battery system also test several control strategies. The point of reference is a system which never performs equalisation, and terminates genset charging once the battery voltage reaches 28.5 V, the threshold at which the current is tapered to achieve constant voltage “absorb” charging. Since such a system never reduces its demand from the genset, this strategy establishes a floor for fuel consumption in a genset battery system (given a particular battery and rectifier size). While this is instructive, such a system would not be recommended in reality, because the battery is never fully charged, and as a result, would age prematurely. Unfortunately, this is not captured by the battery model.

Two other control strategies are implemented, as well. The first does not perform equalisation, but does run the genset for two hours of constant voltage absorb charging at 28.5 V before shutting it off. This will achieve more complete charging than the reference strategy, at the cost of increased fuel consumption. Xantrex SW series converters, commonly used in hybrid and genset-battery power systems, by default perform two hours of absorb charging before turning off the genset. Thus, this strategy is probably quite representative of current practices.


The third control strategy generally shuts of the genset when the 28.5 V threshold is reached, but starts the genset every 14 days in order to run an equalisation charge, during which the battery is held at 28.8 V for three hours. This regular equalisation charge should go some way towards keeping the battery in a good state of health, but will result in additional genset part load operation.

The hybrid power system resembles the genset-battery system, but with the addition of a photovoltaic array, connected to the battery and load via an ideal (lossless) maximum power point converter. A 24 V system with a 24 kWh battery, 5 kW rectifier, 1.5 kW inverter, and 5 kW genset are assumed. The same three control strategies implemented for the genset-battery systems are considered here. The photovoltaic array is sized in order to achieve an annual solar fraction of 65%—a typical rule of thumb. The solar fraction is calculated as the total array output minus array output rejected at the charge controller, all divided by the sum of the DC load, the AC load, the losses in the inverter, and the losses in the battery. The array faces due south, and is tilted at an angle equal to the latitude, rounded up to the nearest integer evenly divisible by five (e.g., for Toronto, at 43.7º N, the array is tilted at 45º to the horizontal).

The PV-battery system is essentially the same as the PV-hybrid system, but with a resized array and battery and the genset, rectifier, and associated controls eliminated. The battery and PV array were chosen to achieve a loss-of-load probability of 1%. That is, the system will be able to, on average, supply the load for all but 3.7 days of the year. This is a relatively low level of reliability, especially for industrial loads, but it already requires a very large array and battery: for Toronto’s climate, a 6.5 kWp array and 40.8 kWh battery are necessary. The battery is permitted to discharge to 20% state-of-charge before it is disconnected from the load. The array is tilted at 60º to the horizontal for the Toronto site examined, favouring winter generation.

The genset for all simulations (excepting the PV-battery system) is 5 kWAC diesel machine with a fuel consumption of 0.60 l/kWh at full load. Thus, its full load consumption is 3 l/h. At no load, it consumes 0.75 l/h; its fuel consumption varies linearly between these two points. The genset is assumed to be at an altitude of 100 m for all sites (which would be impossible, for example, at Edmonton, but is useful for comparison purposes nevertheless). The air provided to the genset is assumed to be at the outside air temperature. The nominal lifetime of the genset is assumed to be 10,000 hours. The frequency of overhauls is determined by the genset loading. When the genset is loaded between 50 and 100% of its nominal power, it is assumed to wear at a rate of one overhaul for every half lifetime. Below 50% rated power, the rate of deterioration rises linearly, such that at 0% of its nominal power, the rate of deterioration is equivalent to one overhaul every quarter lifetime.

The 300 W rectifier used in the prime power system has an efficiency of 93.3% at 300 WDC and 92.5% at 50 WDC (these are the only two loading levels it will see). The 2500 W rectifier in the genset-battery system with undersized rectifier has an efficiency of 93.4% at 2500 WDC (the only


loading level it will see). Since the 5 kW rectifier used in the genset-battery and hybrid power systems must perform constant voltage charging, it will operate over a range of power levels; its efficiency curve is shown in Figure 2. The efficiency curve reflects the assumption that the “rectifier” will be, in fact, a high-quality switch-mode battery charger, not a transformer and diode bridge.

The inverter, a 1500 W device, has the efficiency curve shown in Figure 3. The shape of the curve is based on the Xantrex SW series.

Figure 2 Efficiency of 5 kW Rectifier


Figure 3 Efficiency of 1.5 kW Inverter

The current-voltage-SOC behaviour of the battery is modelled based on data collected from a GNB Absolyte IIP absorbent glass mat battery. It is assumed that the battery is always held at 25ºC. At this temperature, self discharge is 2% per month. It is further assumed that the battery’s cycle life, rather than its float life, will be limiting, except for the PV-battery system. The cycle life is assumed to be a linear function of the cycling depth-of-discharge, with 800 cycles achieved at 80% depth-of-discharge ant 1500 cycles achieved at 50% depth-of-discharge. This is not necessarily the aging behaviour of a GNB Absolyte, but can be considered representative of an industrial-quality battery built for cycle purposes, not subjected to abuse.

For the battery used in the PV-battery system, a calendar lifetime of 15 years is assumed; based on its cycle lifetime, it would survive much longer.

The photovoltaic array is composed of parallel groups of two modules in series. To permit the solar fraction of 65% and the loss-of-load probability of 1% to be achieved as nearly as possible, fractions of groups were permitted. The modules have the characteristics described in Figure 4. It is assumed that no energy is lost in wiring, diodes, or connections.


Figure 4 Module Characteristics

2.2 Benchmarks of System Performance

Seven benchmarks of system performance, relating to operation and maintenance, were computed in this study. These were:

• Genset Fuel Consumption: The average annual fuel consumption of the genset, in litres of diesel. This is both an operational cost and a strong indication of the greenhouse gas emissions of the system—the consumption of 500 l of diesel fuel generates approximately one tonne of carbon dioxide equivalent.

• Genset Run Time: The average number of hours per year that the genset is operating. This is one indication of genset wear.


• Genset Overhauls: The number of genset overhauls necessary in an average year (normally a fraction considerably less than one). This is a second indication of genset wear.

• Genset Starts: The average number of times, per year, that the genset must be started. Starting the genset contributes to wear, over and above the run time, although there are indications that the additional wear may not be more than that occurring during several minutes of operation. On the other hand, more frequent genset starts may be an annoyance in systems where there are people nearby.

• Battery lives used: The wear on the battery in an average year, expressed as certain amount of capacity “used up”. This estimate should be treated with some caution; for one thing, it does not take into account the effects of abusive cycling. Thus, it suggests that the battery wear in the genset-battery system that does not perform equalisation or absorb charging will not be especially high. In reality, a battery would soon fail given such a regime of incomplete charging. The benchmark is useful, nevertheless, for comparing the use of the battery in different systems, as well as whether this use is at a low or high states-of-charge, on average.

• Fraction of solar energy rejected: If, at a point in time, the photovoltaic array produces current in excess of the load and the maximum current that the battery is able to accept, this excess will be wasted. Evidently, this increases the cost per unit of energy provided by the photovoltaic system. On the other hand, a system that rejects no solar energy would likely be more cost-effective if a larger photovoltaic array was used.

• Fraction of rejected solar energy that could be avoided with non-seasonal storage: A larger battery reduces the rejected solar energy. In fact, the rejected solar energy can be reduced to arbitrarily low levels by increasing the battery size, e.g., to permit seasonal storage. Extremely large batteries are not practical, however. In a month when the total array output exceeds the load and system losses, any PV output rejected in excess of the difference between the total array output and the total load and system losses is here considered avoidable with non-seasonal storage. Summing this over all months and dividing by the total annual rejected solar energy results in the fraction of rejected solar energy that could be avoided with non-seasonal storage. This is a useful benchmark because it gives an upper limit on improvements possible through dispatch strategies designed to avoid running the genset prior to a period of strong sunshine.



3 BASELINE

3.1 Operational Benchmarks

The benchmarks computed in the various simulations are contained in Table 2, for DC loads, and Table 3, for AC&DC loads. Evidently, these tables contain too much data to be useful as a baseline; it needs to be condensed by the extraction of certain representative configurations. Nevertheless, the tables still serve to confirm that the selected systems are indeed representative, and point to some interesting differences among the systems.

The tables reveal that the DC load systems and the AC/DC load systems perform very similarly; the AC/DC systems tend to require more energy from the genset since they suffer inverter losses. Thus, for the benchmark, only the AC/DC systems will be considered. Furthermore, by selecting the hybrid photovoltaic array size so that the same solar fraction is achieved at all sites, the values of the benchmarks for genset operation and battery deterioration change little from one site to the next, other factors being held constant. Thus, one site can be chosen as representative for all sites. Here Toronto is chosen as the representative site. Note that at northern sites, such as Inuvik, much larger arrays are required to achieve the 65% solar fraction, and, due to the greater seasonal variation in the solar radiation, a significant proportion of the array’s output is wasted.

While the genset-battery and hybrid systems with no equalisation are interesting, in that they give some indication of fuel consumption with an ideal system, they are not practical systems, since most types of batteries would fail prematurely if consistently undercharged. For this baseline, the systems performing two hours of absorb charging prior to shutting down the genset will be considered representative; they perform relatively similarly to the systems that have three hours of equalisation every two weeks, and likely better reflect the actual situation of many Canadian hybrid power systems.

Given that the performance of the 12 kWh and 24 kWh battery genset-battery systems are quite similar, the baseline will focus exclusively on the 24 kWh battery systems.

The benchmarks for the reduced set of systems—a prime power system, a genset-battery system with dispatch strategy resulting in two hours of absorb charging every time the genset is run, a PV hybrid system in with the same dispatch strategy, and a PV-battery system—are shown in Table 5; the characteristics of the systems are summarized in Table 4. The genset-battery system greatly reduces run time, fuel consumption, and genset wear compared with the prime power system, and the hybrid power system performs better yet.

System Description Genset Rectifier Battery PV Array BenchmarksRun Time FuelGenset

OverhaulGensetStarts

BatteryLifetime

Used

FractionSolar

FractionPV outputWasted

Fractionof WasteAvoidable

(kW) (kW) (kWh) (kW) (h) (l) - - (Wh) (%) (%) (%)

Prime Power 5 0.3 8760 7837 3.279 1Genset-battery, 2hrs absorb 5 5 24 795 2000 0.171 190 1732Genset-battery, 3hrs eq every 2 weeks 5 5 24 642 1873 0.133 259 2009Genset-battery, small rectifier 5 2.5 24 1128 2232 0.460 207 1762Genset-battery, no eq, no absorb 5 5 24 597 1836 0.119 273 2070

Genset-battery, 2hrs absorb 5 5 12 1069 2222 0.257 383 1712Genset-battery, 3hrs eq every 2 weeks 5 5 12 661 1910 0.139 733 2294Genset-battery, no eq, no absorb 5 5 12 607 1869 0.121 766 2354

Hybrid: no equalisationToronto 5 5 24 1.4 202 622 0.040 94 1260 65.6 1.0 100.0Edmonton 5 5 24 1.2 202 623 0.040 94 1289 65.4 0.2 100.0Inuvik 5 5 24 1.9 205 631 0.041 95 1198 65.6 18.3 18.1Vancouver 5 5 24 1.6 206 633 0.041 95 1219 65.3 5.6 71.7St. John's 5 5 24 1.4 209 644 0.042 97 1287 64.4 2.7 100.0

Hybrid: 2 hours of absorb charging every time genset runsToronto 5 5 24 1.5 277 690 0.060 67 1101 65 4.2 99.6Edmonton 5 5 24 1.3 269 670 0.059 65 1113 65.9 2.3 100.0Inuvik 5 5 24 2.0 278 693 0.060 67 1055 65.2 22.3 22.4Vancouver 5 5 24 1.7 283 706 0.062 68 1083 64.4 8.8 73.7St. John's 5 5 24 1.5 277 691 0.060 67 1119 65 7.3 99.9

Hybrid: 3 hours of equalisation at 28.8 V every 2 weeksToronto 5 5 24 1.5 256 666 0.058 100 1152 65.6 3.5 100.0Edmonton 5 5 24 1.2 261 687 0.058 99 1187 64.2 1.2 100.0Inuvik 5 5 24 2.0 264 685 0.060 105 1130 65.1 22.6 23.2Vancouver 5 5 24 1.6 270 707 0.060 105 1158 63.6 7.4 84.6St. John's 5 5 24 1.5 264 691 0.059 103 1187 64.3 5.5 100.0

Table 2 Benchmarks for Systems Supplying DC Loads


CETC-Varennes 2006-058 (TR) 13 July 2005

System Description Genset Rectifier Battery PV Array BenchmarksRun Time FuelGenset

OverhaulGensetStarts

BatteryLifetime

Used

FractionSolar

FractionPV outputWasted

Fractionof WasteAvoidable

(kW) (kW) (kWh) (kW) (h) (l) - - (Wh) (%) (%) (%)

Prime Power 5 0.3 8760 7769 3.291 1Genset-battery, 2hrs absorb 5 5 24 884 2245 0.189 212 1933Genset-battery, 3hrs eq every 2 weeks 5 5 24 723 2117 0.149 291 2264Genset-battery, small rectifier 5 2.5 24 1785 2859 0.449 195 1734Genset-battery, no eq, no absorb 5 5 24 677 2083 0.135 377 2358

Genset-battery, 2hrs absorb 5 5 12 1026 2294 0.221 365 1649Genset-battery, 3hrs eq every 2 weeks 5 5 12 743 2162 0.155 800 2525Genset-battery, no eq, no absorb 5 5 12 692 2132 0.138 837 2608

Hybrid: no equalisationToronto 5 5 24 1.6 227 700 0.045 105 1363 65.2 0.9 100.0Edmonton 5 5 24 1.4 222 684 0.044 105 1393 65.9 0.4 100.0Inuvik 5 5 24 2.15 238 734 0.048 111 1346 64.4 18.4 20.5Vancouver 5 5 24 1.8 235 725 0.047 109 1332 64.3 5.1 73.3St. John's 5 5 24 1.65 229 204 0.046 106 1372 65.3 3.6 100.0

Hybrid: 2 hours of absorb charging every time genset runsToronto 5 5 24 1.65 314 781 0.069 76 1189 64.6 3.7 99.5Edmonton 5 5 24 1.4 313 777 0.069 76 1213 64.6 1.7 100.0Inuvik 5 5 24 2.35 322 800 0.071 78 1158 64.3 25.1 25.2Vancouver 5 5 24 1.95 310 773 0.067 74 1130 65.2 10.1 69.1St. John's 5 5 24 1.72 316 784 0.069 76 1209 64.6 7.6 99.9

Hybrid: 3 hours of equalisation at 28.8 V every 2 weeksToronto 5 5 24 1.65 283 749 0.630 114 1258 65.1 3.4 100.0Edmonton 5 5 24 1.4 281 748 0.063 111 1283 64.9 1.3 100.0Inuvik 5 5 24 2.35 294 779 0.066 119 1255 64.5 24.8 25.0Vancouver 5 5 24 1.9 291 769 0.065 116 1211 64.5 9.2 75.0St. John's 5 5 24 1.7 284 750 0.063 114 1280 65.2 5.9 99.9

PV-Battery SystemToronto 40.8 6.5 446 98.9 59.1 0.8

Table 3 Benchmarks for Systems Supplying AC&DC Loads

Report –

Table 4 Characteristics of Systems Selected for Baseline

Prime Power Genset-Battery

PV-Battery PV Hybrid

PV Array Capacity NA NA 6.50 kW 1.65 kW

Battery Capacity NA 24.0 kWh 40.8 kWh 24.0 kWh

Genset Capacity 5 kW 5 kW NA 5 kW

Rectifier Size 0.3 kW 5 kW NA 5 kW

Inverter Size 1.5 kW 1.5 kW 1.5 kW 1.5 kW

Table 5 Operational Benchmarks of 300 Watt AC/DC Power Supplies in Toronto (Per Annum)

Prime Power

Genset-Battery

PV-Battery PV Hybrid

Genset Fuel Consumption 7769 l 2245 l NA 781 l

Genset Run Time 8760 h 884 h NA 314 h

Genset Overhauls 3.29 0.19 NA 0.07

Genset Starts 1 212 NA 76

Battery Capacity Deterioration NA 1933 Wh 446 Wh 1189 Wh

Fraction Solar NA NA 98.9% 64.6%

Fraction of Solar Energy Wasted NA NA 59.1% 3.7%

Fraction of Wasted Energy that can be Avoided with Nonseasonal

Storage

NA NA 0.8% 99.5%

3.2 Cost of Electricity

The operational benchmarks discussed in the previous section are an incomplete account of the performance of an off-grid power system. One problem is the difficulty of comparing systems that improve one benchmark at the expense of another: for example, is it better to reduce genset run time by 10% or battery capacity deterioration by 10%? Another problem is that, as


mentioned earlier, investment in equipment can improve the operational benchmarks, but how to weigh operational costs against investment costs?

In order to incorporate all aspects of system performance into a single analysis, the overall cost of generating electricity was calculated, using a set of assumptions about costs, described in Table 6. These assumptions reflect the case of a fairly remote industrial site, where transportation of equipment, fuel, and expertise to the system is a major cost, and the necessity of reliable power justifies the purchase of more expensive batteries, genset, and other equipment. A 10% discount rate and a project life of 25 years are assumed. The analysis calculates an equivalent annual cost for all expenditures, sums these, and divides by the electrical energy required by the load over the course of the year, to find the cost of electricity.

The simulation estimates the number of overhauls needed per year; this number is greater than one for the prime power system, which is operated at a low fraction of its capacity all the time, and therefore wears rapidly. The simulation assumes that the genset has a nominal lifetime of 10,000 h, and can be overhauled once. Thus, if the simulation predicts that x overhauls are required per year, then every period of 2/x years one genset purchase and one genset overhaul will be required. Thus the equivalent annual cost of genset purchase is found using the discount rate of 10%, the number of annual periods spanning one purchase and one overhaul (i.e., 2/x years), and the purchase cost of $5000; the equivalent annual cost of overhauling is found in the same way, but with a cost of $2000.

Table 6 Assumptions in Cost of Electricity Calculation

Cost Assumption

Genset Fuel $2.00 per litre (high transportation costs)

Genset Purchase $5000 for 5 kW installed, 10,000 h nominal life

Genset Overhaul $2000 per overhaul, assume genset can be overhauled once

Genset Maintenance $1.00 per hour operation time

Battery $400/kWh, lasts 50% as long as suggested by simulation

Photovoltaic Array $8.00/Wp installed, lasts 25 years

Inverter $1.00/W installed, lasts 12.5 years

Rectifier $0.30/W installed, lasts 12.5 years


Genset maintenance costs other than overhaul are estimated at $1.00 per hour of operating time. This is argued based on the need for oil, oil filter, and air filter changes every 300 to 500 hours; a technician’s visit costs, in the CETC-Varennes’s experience, roughly $300 to $500, when travel time is included.

The battery is assumed to cost $400/kWh of capacity. This reflects the purchase price of a high-quality industrial battery, possibly of the valve regulated type, and the cost of transporting the battery to the site, which can be expensive, and installing it. The simulation’s predictions for battery lifetime are used only as a guide: the simulation predicts a 20 year life for the battery in the hybrid system, when experience in the field suggests that this should be more like 10 years, if that. The capacity of the battery, 24 kWh, is divided by the simulation’s predictions of battery deterioration per year to find an estimate of lifetime; this is then halved. While this is a very approximate approach, better approaches are simply not available to this investigation. It may also be that the lifetime estimate, while not accurate in absolute terms, gives a reasonable indication in the relative differences in wear inflicted by the different configurations. The purchase cost is converted into an annual equivalent cost based on the halved lifetime.

The photovoltaic array is assumed to cost $8.00 per Wp, with about one quarter of that being for transportation and installation. This is converted to an equivalent annual cost based on an assumed 25 year lifetime.

The rectifier and inverter are both assumed to need one replacement during the course of the 25 year project. Thus, their purchase costs are converted to equivalent annual costs based on 12.5 year lifetimes. The inverter is assumed to cost $1.00/W installed and the rectifier, $0.30/W installed.

On the basis of these assumptions, the equivalent annual costs and cost of electricity for the baseline prime power, genset-battery, and PV hybrid systems are calculated as indicated in Table 7.


Table 7 Annual Costs of 300 Watt AC/DC Power Supplies in Toronto Area (Per Annum)

Prime Power Genset-Battery PV Battery PV Hybrid

Genset Fuel $15,538 $4,490 $1,562

Genset Purchase $8,075 $716 $485

Genset Overhaul $3,230 $286 $194

Genset Maintenance $8,760 $884 $314

Battery Purchase $2,150 $2,146 $1,554

PV Purchase $5,729 $1,454

Inverter Purchase $215 $215 $215

Rectifier Purchase $13 $151 $151

Total Annual Cost $35,615 $8,892 $8,090 $5,930

Cost of Electricity $13.55/kWh $3.38/kWh $3.08/kWh $2.26/kWh

The prime power system is clearly unsuited to this task, as reflected by its extremely high cost of electricity. The genset operates at a fraction of its load, and consequently consumes large amounts of fuel and wears out quickly. Perhaps if 1.5 kW diesel gensets were readily available, the option would not be so unattractive; diesel gensets of that size are rare, however.

The genset-battery, the PV-battery and the PV hybrid systems are much more attractive, although the cost of electricity, in the range of $2.00 to $3.50 per kWh, is still high in absolute terms. These estimates of the cost of electricity are higher than typically suggested; this probably reflects the inclusion of transport to the remote site. Electricity from the PV hybrid system costs fully one-third less than electricity from the genset-battery system.

The PV-battery system proposed here is probably smaller, in terms of battery and array, than would be required in reality. A loss-of-load probability of 1% is unacceptably high for many industrial applications; to achieve a significantly lower loss-of-load probability, a much larger array and battery, and therefore, a much more expensive system, would be necessary.

Fuel purchase is the costliest part of the genset-battery system, accounting for 50% of costs. Battery purchase and replacement account for a further 25%.


The equivalent annual cost of the PV hybrid system can be broken down into four nearly equal components: fuel purchase, battery purchase, array purchase, and everything else (genset purchase, maintenance and overhaul; inverter and rectifier purchase). Note that the cost of the genset is not particularly important in the overall cost of electricity. Even if the genset were free, and no maintenance required, the cost of electricity would fall by only around 17%; practically realisable reductions in genset costs will clearly be more modest than this.

3.3 Residential PV Hybrid System

The simulation and cost assumptions of the preceding sections are for a moderately remote industrial power system. The choice of equipment, and the costs of purchasing and operating it, would be quite different for a more accessible residential PV hybrid system. The PV hybrid system baseline can be recalculated under these changed assumptions.

The same size and fuel consumption is used for the genset, but a cheaper, less durable machine is assumed. Probably this would be a propane or gasoline fired genset, which could not be overhauled, and would have a shorter lifetime. Here a cost of $0.40/W of genset capacity and a nominal lifetime of 1000 h is assumed, with aging due to part load operation following the same tendency as in the previous study. The fuel cost is reduced to $1.00/l, and maintenance costs are reduced to $0.30 per hour of genset operation, reflecting the assumption that the operator may do much of the maintenance him or herself.

A less expensive deep cycle battery is also assumed; at $200/kWh of capacity, it would likely be a low-cost, flooded traction battery. The lifetime is assumed to be 60% of the battery used in the industrial system.

The photovoltaic array is assumed to cost $7.00/Wp, suggesting that installation costs have been halved compared with the industrial system (assuming an underlying retail cost of PV capacity of $6.00/ Wp). Inverter and rectifier costs remain unchanged.


Table 8 Annual Costs of 300 Watt AC/DC Residential PV Hybrid System in Toronto Area (Per Annum)

PV Hybrid

Genset Fuel $781

Genset Purchase $829

Genset Maintenance $94

Battery Purchase $1,095

PV Purchase $1,272

Inverter Purchase $215

Rectifier Purchase $151

Total Annual Cost $4,437

Cost of Electricity $1.69/kWh

The cost of electricity is lower in this scenario, mainly due to the reduced cost of fuel. Interestingly, on an equivalent annual cost basis, genset purchase and overhaul for the industrial system costs roughly the same as genset purchase for this residential system: that is, the use of an inexpensive genset is not advantageous in a system with a solar fraction of only 65%. Were the genset to be used for a much shorter fraction of the year, in a “backup” role only, a low cost genset might be more attractive; of course, this would require a larger photovoltaic array.

Note that this residential PV hybrid system has a lower cost of electricity than the previously studied PV-battery system, and this would remain the case even after reducing the cost of the array and the battery to reflect the assumptions of the residential system.

3.4 Production Energy and Greenhouse Gas Emissions

The combustion of diesel fuel by the genset in all systems discussed here has obvious environmental impacts. But these systems have other environmental costs, as well. Some are associated with the manufacture of the equipment, others with accidents and oversights, such as diesel spills and lead pollution from batteries that are not recycled.

It is difficult to quantify all these environmental impact. Here the focus is limited to a rough estimation of the energy consumption and greenhouse gas emissions of the principal components of the system (genset, battery, and photovoltaic array) over the lifetime of the project. Fuel


consumption and energy required in manufacture are both considered. Energy used in transportation and maintenance; the energy in equipment enclosures, the inverter, and the rectifier; and other considerations are excluded.

Assumptions concerning the energy content of the major system components are indicated in Table 9. For interest, the total energy content is broken down into the energy required in the manufacture of the constituent materials and the energy required for assembly or fabrication; only the total (i.e., the rightmost column) is used in subsequent calculations.

Table 9 Assumptions Concerning Energy Content of PV Array, Diesel Genset, and Lead-Acid Batteries

Component Materials Fabrication Total Energy Content

Mono-Si PV Array 18 MJ/Wp 23 MJ/Wp 41 MJ/Wp

Diesel Genset 1500 MJ/kW 400 MJ/kW 1900 MJ/kW

Lead-Acid Batteries 880 MJ/kWh 190 MJ/kWh 1070 MJ/kWh

For each component, the lifetime energy content is found by determining the fraction of a component lifetime used up in one year, and multiplying this by the total energy content figure from the rightmost column in

Table 9. For example, the PV array has a lifetime of 25 years, so 1/25th of the array is “used” in a one year period; dividing the array size (1650 Wp) by 25 and multiplying by 41 MJ per Wp, the PV hybrid system’s array can be considered to “require” 2,700 MJ of energy per year.

This is shown in Table 10. The energy content, on an annualized basis, is shown for the three major components in the system. The last row is for the fuel energy content. The array and the batteries account for the majority of the system’s energy content.


Table 10 Energy Content of System and Fuel, Considered on Annualized Basis

Prime Power Genset-Battery PV-Battery PV Hybrid

Mono-Si PV Array 0 0 10,700 MJ 2,700 MJ

Diesel Genset 15,600 MJ 898 MJ 0 326 MJ

Lead-Acid Batteries

0 4,140 MJ 2,910 MJ 2,540 MJ

System Energy Content

15,600 MJ 5,030 MJ 13,600 MJ 5,580 MJ

Fuel Energy Content

303,000 MJ 87,600 MJ 0 30,500 MJ

The diesel fuel consumed by the power systems has a heating value of around 39 MJ/l. It must be cautioned, however, that the energy content of the fuel can not be directly compared to the energy content of the equipment, because the energy content of the former is prior to conversion to the desired form (i.e., electricity), but the energy content of the latter is from energy consumed in its final desired form. For example, if electricity is needed in the production of the photovoltaic array, and this electricity was to be provided by a diesel genset, then for every unit of electrical energy consumed in the process, diesel fuel with a heating value of 1/η units would be required, where η is the efficiency of the diesel genset.

As a note of interest, the energy content of the combination of PV array and batteries in the hybrid system is 5,250 MJ; these supply 65% of the load, or 6,150 MJ, per year. Thus the array and battery generate more useful electricity than is embodied in them, although not significantly so.

Of more interest than the energy content are the greenhouse gas emissions, in tonnes of CO2 equivalent, shown on an annualized basis in Table 11. The first four rows of the table indicate the greenhouse gas emissions associated with the energy content of the equipment in the system; the energy content is translated to greenhouse gas emissions by a conversion factor of 0.57 kg CO2 equivalent per kWh of energy content, a figure recommended by Turcotte (2005) and roughly equal to the GHG emissions per kWh of electricity produced in the USA. The diesel fuel consumed in a year is converted to an annual amount of CO2 equivalent by the factor of 2.72 kg/l of fuel combusted. From the sum of the equipment energy content emissions and the fuel emissions, the total annual GHG emissions are calculated. Dividing by the annual electric load yields the emissions per unit of electricity.


Table 11 Greenhouse Gas Emissions, Considered on Annualized Basis, in tonnes of CO2 Equivalent

Prime Power

Genset-Battery

PV-Battery

PV Hybrid

Mono-Si PV Array 0 0 1.69 0.43

Diesel Genset 2.5 0.14 0 0.05

Lead-Acid Batteries 0 0.65 0.46 0.40

Annualized Equipment GHG Emissions 2.5 0.80 2.15 0.88

Annual GHG Emissions from Fuel 21 6.1 0 2.1

Total Annual GHG Emissions 23.6 6.9 2.2 3.0

Emissions per unit of Electricity 9.0 tCO2-/MWh

2.62 tCO2-/MWh

0.82 tCO2-/MWh

1.14 tCO2-/MWh

In terms of greenhouse gas emissions, the prime power system is very unattractive, both because of its high fuel consumption and the rapid wear of the genset from part load operation necessitating frequent genset replacement. This is another demonstration that prime power systems are not suited to these small loads. The genset-battery system and the PV hybrid system have similar GHG emissions levels from the embodied energy in their constituent equipment, with increased wear on the lead-acid batteries and genset in the genset-battery system largely compensating for the emissions associated with the hybrid system’s array. The higher fuel consumption of the genset-battery system means that its overall emissions are 130% higher than those of the hybrid system. The PV-battery system has the lowest overall emissions level, nearly 30% lower than the PV hybrid system, due to the absence of emissions from fuel. It must be noted, however, that the 1% loss-of-load probability that the system attains is probably too low for many industrial applications; a 50% larger array, which would achieve only a slightly higher loss-of-load probability (0.5%), would have the same annualized greenhouse gas emissions level as the PV-hybrid system.

The PV hybrid system generates 1.14 tonnes of CO2 equivalent per MWh of electricity produced. This compares unfavourably with electricity available from most large grid systems: for example, in Canada as a whole, emissions are only 0.211 tonnes of CO2 equivalent per MWh of electricity generated. This misses the point, of course: PV hybrid systems are off-grid, which by definition means that low emissions sources of electricity are unavailable or very costly. As shown in Table 11, the PV hybrid system’s emissions are less than half those of cost-effective alternatives. To achieve lower emissions, a PV-battery system could be used, but a larger array


and battery would be required. This would result in higher system energy content and associated emissions. The energy content of the PV hybrid system components accounts for 30% of the systems GHG emissions, as it is.


4 AVENUES FOR HYBRID SYSTEM IMPROVEMENT

As a basis for comparison of various systems, the baseline is useful for the estimation of the extent to which PV hybrid systems can be improved, and the potential gains from certain avenues of improvement. In particular, it is interesting to see how changes in design, sizing, and control could affect the cost of electricity and the greenhouse gas emissions per unit of electricity provided. Since improvements to individual components—e.g., lowering the purchase cost of PV by 20%—are outside the scope of the CETC-Varennes hybrid system program, they are not considered here.

4.1 Rectifier Sizing

The baseline PV hybrid system probably performs better, at least in terms of fuel consumption and genset run time, than a large number of real PV hybrid systems. This stems, in large part, from the baseline’s utilisation of a rectifier that is large enough to use the full genset power output; many real systems use a rectifier sized much smaller than the genset output. As a result, in these real systems the genset must run at part load for extended periods of time, unless high AC loads coincide with the times of genset operation.

The principal reason that small rectifiers are often used is the widespread belief that batteries are damaged by high charge rates. A majority of battery manufacturers contacted by the CETC-Varennes indicated that charge rates should not exceed the four or five hour rate. At least two Canadian PV system vendors recommend charge rates not exceeding the 10 hour rate. Such low charge rates generally translate into rectifiers being considerably smaller than gensets, since there are few small gensets available, and hybrid system batteries rarely have much more than two days of autonomy.

This conventional wisdom may or may not be well-founded. Early research on lead-acid batteries found that there was no upper limit on the charge current, as long as battery temperature and voltage stayed within reasonable limits [Vinal, 1955]. For flooded batteries, this was the case as long as the charge current, in amperes, did not exceed the capacity remaining to be recharged, in ampere·hours. Thus, over the range of state-of-charge that the genset of a hybrid system usually charges a battery (i.e., assuming the genset turns off at a state-of-charge of 70% except for periodic complete charging), the two hour or three hour rate should be acceptable. Moreover, certain battery manufacturers (including those providing AGM batteries) do not restrict the maximum charge current, as long as the voltage is limited, and their batteries do not appear to be very different in design from batteries with limited charge rates. Extremely rapid charging systems for lead-acid batteries also exist. It may be that most battery manufacturers and vendors make a conservative recommendation, not taking into account the inefficiencies this introduces at the system level. And it may be that vendors may expect the user to attempt to fully charge the


battery with the genset, so a large battery charger is mostly wasted: the battery will accept only a limited current at higher state-of-charge levels.

A secondary reason for undersizing of the rectifier may be the approach that “there are really only two sizes of genset—adequate and too small” [Perez, 1995]. This reluctance to contemplate the possibility that a genset may be too large stems from the attention given to the problems that arise when buyers “cut corners” on their genset purchase. When transformers coupled to diode bridges are used as battery chargers, large gensets are necessary, since the diode bridge conducts current only for the part of the AC waveform near the peaks. Furthermore, when both 120 Vac and 240 Vac loads have to be run off the same genset, only half the genset’s rated power is available to 120 Vac loads on one side of the split phase. Many gensets (though not the genset assumed in this study) should not be operated at more than 75 to 80% of their rated power, or fuel efficiency and genset lifetime will suffer. And loads requiring reactive power, such as battery chargers without power factor compensation, will require excess genset capacity, if compensating loads are not run simultaneously: for example, a battery charger with a 0.65 power factor and an efficiency of 85% would require 1 kVA of genset capacity to produce 0.55 kW of charging power.

Some of these concerns have been addressed over the past fifteen years through advances in power electronics. Switchmode battery chargers, now common, make use of the entire AC waveform, not just the peaks. Some battery chargers, such as those incorporated into Xantrex inverter/chargers, have power factor compensation, and operate at a power factor of nearly unity. Other issues remain unchanged.

It seems, therefore, that a number of existing PV hybrid systems are operating with undersized rectifiers, and that a certain fraction of these could benefit from the use of a larger rectifier, as permitted by a different type of battery, a different type of battery charger, or a less conservative attitude towards maximum battery charging currents. To investigate what impact this could have on overall system operation, the simulation of the PV hybrid system was rerun assuming a 2.5 kW (rather than 5 kW) rectifier; all other components remained unchanged, and the solar fraction was still 65%.

The results are shown, in terms of the annual costs, in Table 12, and, in terms of the annualized greenhouse gas emissions, in Table 13. The equivalent annual cost of the system and its operation—and therefore the cost of electricity—rises about 6%. Annual operating costs (i.e., fuel and maintenance) rise from $1876 to $2282—an increase of 22%; annualized equipment costs fall slightly, due to the reduced cost of the battery charger. Total greenhouse gas emissions rise by 12%. Thus, the impact of using an undersized inverter, as is currently done in many systems, is not insignificant.


Table 12 Annual Costs of PV Hybrid Systems: Baseline System versus System with 2.5 kW Rectifier

Baseline (5 kW Rectifier) System with 2.5 kW Rectifier

Genset Fuel $1,562 $1,804

Genset Purchase $485 $545

Genset Overhaul $194 $218

Genset Maintenance $314 $478

Battery Purchase $1,554 $1,531


Inverter Purchase $215 $215

Rectifier Purchase $151 $43

Total Annual Cost $5,930 $6,288

Cost of Electricity $2.26/kWh $2.39/kWh


Baseline PV-Hybrid (5 kW Rectifier)

PV-Hybrid System with 2.5 kW Rectifier

Mono-Si PV Array 0.43 0.43

Diesel Genset 0.05 0.08

Lead-Acid Batteries 0.40 0.39

Annualized Equipment GHG Emissions 0.88 0.90

Annual GHG Emissions from Fuel 2.1 2.5

Total Annual GHG Emissions 3.0 3.4

Emissions per unit of Electricity 1.14 tCO2/MWh 1.28 tCO2/MWh


4.2 Battery Lifetime

In the simulations for the baseline, the cycle lifetime of the battery in the PV hybrid system was found to be around 20 years; recognizing that this is much longer than is generally observed in the field, all cycle lifetime estimates were halved. But 10 years is still quite a long lifetime for hybrid system batteries: 6 or 7 years is more common.

This is much shorter than would be expected based on an industrial battery’s float lifetime and cycling lifetime, as measured under controlled conditions. The partial state-of-charge cycling that occurs in hybrid systems appears to cause accelerated aging in many batteries.

Data from the CETC-Varennes hybrid test bench show that even with an absorbent glass mat battery, which should be little affected by stratification, partial state-of-charge cycling produces remarkable changes in the voltage-current-SOC characteristics of the battery from cycle to cycle. It is readily conceivable that these changes, which result in shorter and shorter cycles between genset runs when voltage thresholds are used to determine the start and finish of genset operation, would aggravate battery wear if continued over a long period of time. One mechanism that can be posited for this wear would be that only a reduced portion of the plates is being cycled, and that this portion will therefore age more quickly than the rest of the plate; when this portion of the plate fails, so too, the battery as a whole.

In general, regular full charging of a battery is expected to have salutary effects; data from the hybrid test bench demonstrate that this “resets” the battery, such that immediately following the recharge, the charge withdrawn from the battery between genset runs is more-or-less as new, not the much curtailed sum that results after repeated cycles between partial states-of-charge. Of course, if the genset must operate at part load for extended periods of time to achieve this regular full charge, the benefit to the battery is paid for by the deterioration of the genset and increased fuel costs; for this reason most hybrid systems do not but occasionally fully charge the battery, unless this should occur under the influence of the PV array alone.

Part of the CETC-Varennes hybrid system programme’s work is focussed on achieving more regular full charging of the battery, and avoidance of abbreviated cycles between genset runs. What effect might this have on the financial viability and environmental impact of the system, were it to prolong battery lifetime, as speculated above?

To examine this question, the costs and greenhouse gas emissions were recalculated assuming that, in reality, a 10 year battery lifetime is achievable only with regular full charging, and 7 years is more realistic for the baseline. The annual battery cost increases by $405 when the lifetime is thus reduced, raising the total annual cost to $6335, or $2.41/kWh, an increase of 7%. The equivalent annual greenhouse gas emissions associated with the energy content of the battery—and therefore, the sum of the equipment—rise by 0.17 tonnes, and the total greenhouse gas emissions for the system, fuel included, rise to 1.21 tCO2/MWh, an increase of 6%.


4.3 Larger Arrays

The baseline PV hybrid system reflects one possible system sizing. Other choices of array and battery size are possible, and these might improve the financial viability of the system and reduce its greenhouse gas emissions. Reducing the array size is not of interest: the baseline sizing causes minimal solar energy to be wasted, so there is no advantage to smaller arrays. A larger array will cost more and cause more solar energy to be wasted, but at the same time reduce fuel, overhaul, maintenance, and battery costs, and reduce the greenhouse gas emissions associated with fuel combustion. Here the influence of the size of the battery will not be examined.

The baseline simulation was rerun with an array of 2.1 kWp and an array of 2.4 kWp; the other components were as in the standard baseline system, with two hours of absorb charging every time the genset was run. The resulting benchmarks are shown in Table 14. As expected, larger arrays reduce genset usage, but the solar energy that is wasted also increases. Furthermore, wasted solar energy is increasingly due to a surplus of solar energy during the summertime, which can not be reduced except with prohibitively large batteries.

Table 14 Operational Benchmarks of Baseline System with Three Different Sizes of Array (Per Annum)

Array: 1.65 kWp Array: 2.1 kWp Array: 2.4 kWp

Genset Fuel Consumption 781 l 547 l 468 l

Genset Run Time 314 h 219 h 188 h

Genset Overhauls 0.07 0.05 0.04

Genset Starts 76 53 45

Battery Capacity Deterioration 1189 Wh 1043 Wh 965 Wh

Fraction Solar 64.6% 75.3% 79.0%

Fraction of Solar Energy Wasted 3.7% 11.1% 18.3%

Fraction of Wasted Energy Avoidable with Nonseasonal Storage

99.5% 69.5% 46.4%

The impact of a larger array on system costs is shown in Table 15. Annual operating costs (i.e., fuel and overhaul) fall, compared to the baseline’s 1.65 kWp array, by 30% with the 2.1 kWp array and 40% with the 2.4 kWp array. The increased cost of the array results in more modest reductions in total annual costs—and cost of electricity: both systems achieve costs 5% lower


than the baseline, indicating that the sizing of the array is not critical within a wide range of sizes somewhat larger than 1.65 kWp.

Table 15 Annual Costs of PV Hybrid Systems with Three Different Sized Arrays


Genset Fuel $1,562 $1,094 $936

Genset Purchase $485 $463 $459

Genset Overhaul $194 $185 $184

Genset Maintenance $314 $219 $188

Battery Purchase $1,554 $1,441 $1,383

PV Purchase $1,454 $1,851 $2,115

Inverter Purchase $215 $215 $215

Rectifier Purchase $151 $151 $151

Total Annual Cost $5,930 $5,620 $5,630

Cost of Electricity $2.26/kWh $2.14/kWh $2.14/kWh

The impact of a larger array on greenhouse gas emissions is revealed in Table 16. The greenhouse gas emissions associated with the energy content of the equipment rise only slightly with a larger array, because the genset and battery wear more slowly. The fuel reduction is significant, however, and the overall emissions per unit of electricity fall, compared with the baseline and its 1.65 kWp array, by 20% with the 2.1 kWp array and 25% with the 2.4 kWp array. It should be noted that the emissions per unit of electricity produced for these hybrid systems with larger arrays are only slightly larger than that for a PV-battery system of lesser reliability (e.g., 0.86 to 0.92 tCO2/MWh for these hybrid systems versus 0.82 tCO2/MWh for the PV-battery system). Most industrial applications would demand higher reliability than the PV-battery system used in this comparison, and would therefore emit more greenhouse gasses than the PV-hybrid system. Thus, when high reliability is required, a PV hybrid system is, of the options considered here, probably the one emitting the least greenhouse gasses.




Mono-Si PV Array 0.43 0.55 0.62

Diesel Genset 0.05 0.04 0.03

Lead-Acid Batteries 0.40 0.35 0.33

Annualized Equipment GHG Emissions

0.88 0.93 0.98

Annual GHG Emissions from Fuel

2.1 1.5 1.3

Total Annual GHG Emissions 3.0 2.4 2.3

Emissions per unit of Electricity 1.14 tCO2/MWh 0.92 tCO2/MWh 0.86 tCO2/MWh

4.4 Reduced Part Load Operation

The genset in the hybrid system considered in the baseline operates for two hours of absorb charging every time it is run. This is typical of many existing hybrid systems. While this achieves fuller charging of the battery whenever the genset is run, it results in part load operation of the genset, with associated increases in fuel consumption and genset wear.

One of the areas being investigated by the CETC-Varennes hybrid system program is the possibility of reducing this part load operation while still regularly more fully charging the batteries. To establish an upper bound on the improvements in the system performance that might be achieved by reducing part load operation, the baseline simulation was rerun with the two hours of absorb charging eliminated from all genset runs. In reality, this would cause many batteries to age prematurely due to cycling between partial states-of-charge, but this has been ignored here.

The results of this simulation are shown in Table 17. Genset run time falls by around 31%, genset overhauls by around 37%, and fuel consumption by around 14%. On the other hand, the number of genset starts rises by 34%, and the battery is cycled more, causing the annual deterioration to rise by 12%. A slightly higher solar fraction is achieved, largely since less solar energy is wasted and the battery is more efficient when not being charged at a high state-of-charge (as is done during absorb charging).


Table 17 Operational Benchmarks of Baseline System when Genset Runs without Absorb (Per Annum)

Baseline (2 hr Absorb) No Absorb

Genset Fuel Consumption 781 l 672 l

Genset Run Time 314 h 218 h

Genset Overhauls 0.07 0.04

Genset Starts 76 101

Battery Capacity Deterioration 1189 Wh 1337 Wh

Fraction Solar 64.6% 66.7%

Fraction of Solar Energy Wasted 3.7% 1.4%


99.5% 100%

These results are translated into monetary terms in Table 18. With part load genset operation eliminated, genset fuel and maintenance costs decline substantially. But, somewhat surprisingly, the genset purchase and overhaul cost does not fall much. This reflects that in the hybrid system, the genset is used relatively infrequently, and thus genset overhaul or replacement occurs far in the future: the discount rate of 10% means that these expenditures are valued much less in the present. It is important to note that the increase in the battery purchase cost does not reflect increased wear due to the abusive partial state-of-charge cycling that arises when the battery is rarely fully charged, but simply the increased use of the battery when the genset is running for a smaller fraction of the year. Overall, the cost of electricity falls by 4%, and the annual operating costs (fuel plus maintenance) decline by 17%.


Table 18 Annual Costs of PV Hybrid Systems: Baseline System versus System with No Absorb

Baseline (2 hr Absorb Charge) System with No Genset Absorb

Genset Fuel $1,562 $1,344

Genset Purchase $485 $460

Genset Overhaul $194 $184

Genset Maintenance $314 $218

Battery Purchase $1,554 $1,670


Inverter Purchase $215 $215

Rectifier Purchase $151 $151

Total Annual Cost $5,930 $5,700

Cost of Electricity $2.26/kWh $2.17/kWh

Eliminating absorb charging reduces greenhouse gas emissions by around 9%, as shown in Table 19.



Baseline PV-Hybrid (2 hr genset absorb)

PV-Hybrid System (No Absorb)

Mono-Si PV Array 0.43 0.43

Diesel Genset 0.05 0.03

Lead-Acid Batteries 0.40 0.45

Annualized Equipment GHG Emissions 0.88 0.91

Annual GHG Emissions from Fuel 2.1 1.8

Total Annual GHG Emissions 3.0 2.7

Emissions per unit of Electricity 1.14 tCO2/MWh 1.04 tCO2/MWh

4.5 Improved Utilisation of Solar Energy

In the systems examined in the baseline, the genset dispatch strategy starts the genset when the state-of-charge falls to 40% and shuts it down when two hours of absorb charging has been completed. Such a dispatch strategy may cause solar energy to be wasted, due the battery, having been charged earlier by the genset, being unable to accept available photovoltaic current. The quantity of photovoltaic output thus wasted will tend to rise when solar fractions exceed roughly 65%. Eliminating the two hour absorb charge at the end of each genset run reduces this waste somewhat, as suggested by the decrease in the fraction of solar energy wasted seen in Table 17.Further reductions may be possible by avoiding genset operation at the beginning of a day that is likely to be sunny.

To establish an upper bound on the potential system improvements achievable by a genset dispatch strategy that avoids charging the battery prior to a sunny day, the baseline was rerun, using arrays of 1.65 kWp, 2.1 kWp, and 2.4 kWp, and a dispatch strategy that started the genset when the battery reached 40% state-of-charge and stopped it when the state-of-charge had risen to 45%. Such a strategy causes many genset starts, and does not ensure full battery charging, and would those be undesirable in reality; here the additional genset and battery wear that this strategy would cause are ignored.

The resulting benchmarks are shown in Table 20. The systems with two hours of absorb charging at the end of every genset run are compared with systems which terminate the genset run at the onset of absorb charging and systems that terminate the genset run when the state-of-charge has


risen by only 5%, to 45%. For all three array sizes, terminating the genset run sooner results in significant reductions in fuel consumption, run time, overhaul frequency, and fraction of solar energy wasted; as expected, the number of genset starts, the battery capacity deterioration, and the solar fraction all rise. The effect of avoiding solar waste by keeping battery capacity available for available solar energy appears to be at least as significant as the effect of avoiding part load operation of the genset. In relative terms, the effects are more pronounced with larger arrays. For example, the reduction in fuel consumption with the genset run being terminated by a 45% SOC criterion is 22% with a 1.65 kWp array but 31% with a 2.4 kWp array.

Table 20 Operational Benchmarks for Various Array Sizes and Criteria to End Genset Run (Per Annum)

1.65 kW Array 2.1 kW Array 2.4 kW Array

Criterion to End Genset Run

2 hr absorb

Absorb begins

45% SOC

2 hr absorb

Absorb begins

45% SOC

2 hr absorb

Absorb begins

45% SOC

Genset Fuel Consumption (l)

781 672 611 547 471 395 468 391 324

Genset Run Time (h) 314 218 198 219 153 128 188 127 105

Genset Overhauls 0.07 0.04 0.04 0.05 0.03 0.03 0.04 0.03 0.02

Genset Starts 76 101 592 53 71 382 45 59 312

Battery Capacity Deterioration (Wh)

1189 1337 1870 1043 1129 1451 965 1042 1300

Fraction Solar 64.6% 66.7% 68.8% 75.3% 76.9% 80.1% 79.0% 80.9% 83.8%

Fraction of Solar Energy Wasted

3.7% 1.4% 0.5% 11.1% 9.7% 7.4% 18.3% 16.7% 14.6%


99.5% 100% 100% 69.5% 64.4% 50.2% 46.4% 40.4% 29.9%

The performance of these systems is presented, in terms of costs, in Table 21. The cost of electricity generated by the systems with 2.1 kWp and 2.4 kWp is nearly identical, and with lower fuel costs for the latter system compensated by higher array costs. The 45% SOC genset termination strategy achieves reductions of 25% to 33% (the larger figure for the largest array) in the annual operating costs (fuel plus maintenance) compared with the two hour absorb strategy, and 9 to 17% compared with terminating the genset run at the beginning of absorb (with, once


again, the largest improvement seen in the largest array). For all three array sizes, the reduction in the cost of electricity with the 45% SOC termination strategy is 6 to 7% compared to the two hour absorb strategy and around 2.5% compared to the strategy of terminating the genset run at the beginning of absorb.

It should be noted that in this table, the cost of battery purchase is the same for systems ending the genset run at the beginning of absorb and for systems doing so at 45% SOC, despite the additional wear indicated in Table 20. The additional wear arises due to extended periods of cycling between 40 and 45% SOC during winter months and other times of low insolation. A smarter dispatch strategy would more fully charge the battery during these periods, knowing that the likelihood of sunshine in excess of that which the battery is able to accept would be low. Thus, increased battery wear is not an essential feature of efforts to increase solar utilisation. For this calculation, therefore, the battery wear for the system with 45% SOC termination was assumed to be the same as that for the system terminating genset charging at the beginning of absorb.

Table 21 Annual Costs for PV-Hybrid Systems with Various Array Sizes and Criteria to End Genset Run



2 hr absorb

Absorb begins

45% SOC

2 hr absorb

Absorb begins

45% SOC

2 hr absorb

Absorb begins

45% SOC

Genset Fuel $1,562 $1,344 $1,223 $1,094 $941 $789 $936 $781 $648

Genset Purchase $485 $460 $458 $463 $455 $455 $459 $455 $455

Genset Overhaul $194 $184 $183 $185 $182 $182 $184 $182 $182

Genset Maintenance $314 $218 $198 $219 $153 $128 $188 $127 $105

Battery Purchase $1,554 $1,670 $1,670 $1,441 $1,507 $1,507 $1,383 $1,441 $1,441

PV Purchase $1,454 $1,454 $1,454 $1,851 $1,851 $1,851 $2,115 $2,115 $2,115

Inverter Purchase $215 $215 $215 $215 $215 $215 $215 $215 $215

Rectifier Purchase $151 $151 $151 $151 $151 $151 $151 $151 $151

Total Annual Cost $5,930 $5,700 $5,553 $5,620 $5,456 $5,278 $5,630 $5,467 $5,312

Cost of Electricity ($/kWh)

$2.26 $2.17 $2.11 $2.14 $2.08 $2.01 $2.14 $2.08 $2.02


The impact of improved utilisation of solar energy on greenhouse gas emissions is seen in Table 22. With the genset run terminated at 45% SOC, the GHG emissions are reduced by 14 to 17% compared with having the genset run end after two hours of absorb charging, and 6 to 9% compared with having the genset run end at the onset of absorb charging. Reductions are particularly pronounced with larger array sizes. With the 45% SOC genset run termination strategy, emissions are only 0.77 and 0.71 tonnes of CO2 equivalent per MWh for the 2.1 and the 2.4 kWh arrays, respectively. These emission levels are significantly below the 0.82 tCO2/MWh achieved by the PV-battery system.




2 hr absorb

Absorb begins

45% SOC

2 hr absorb

Absorb begins

45% SOC

2 hr absorb

Absorb begins

45% SOC

Mono-Si PV Array 0.43 0.43 0.43 0.55 0.55 0.55 0.62 0.62 0.62

Diesel Genset 0.05 0.03 0.03 0.04 0.02 0.02 0.03 0.02 0.02

Lead-Acid Batteries 0.40 0.45 0.45 0.35 0.38 0.38 0.33 0.35 0.35

Annualized Equip. GHG Emissions

0.88 0.91 0.91 0.93 0.95 0.95 0.98 1.00 0.99

Annual GHG Emissions from Fuel

2.1 1.8 1.7 1.5 1.3 1.1 1.3 1.1 0.9

Total Annual GHG Emissions

3.0 2.7 2.6 2.4 2.2 2.0 2.3 2.1 1.9

Emissions per MWh of Electricity

1.14 1.04 0.98 0.92 0.85 0.77 0.86 0.78 0.71

4.6 Comparison of Options

The potential impacts of the various options are expressed in Table 23 in terms of the improvement they make to the annual operating costs, cost of electricity, and greenhouse gas emissions of the standard baseline PV hybrid system. When a 2.5 kW rectifier is used or the batteries last only seven years instead of ten, the impacts are negative. Using a larger array (up to around 2.4 kWp), avoiding part load operation, and avoiding genset charging of the battery just


prior to a sunny period have positive impacts. Some of these options can be implemented concurrently, and the impacts are, in some cases, approximately additive.

The system with 2.4 kWp array and genset run terminated at 45% SOC can be considered the “best” system: its cost of electricity is comparable to the system with 2.1 kWp array, but its greenhouse gas emissions and annual operating costs are considerable lower. Compared the baseline PV-hybrid system, the best system reduces annual operating costs by 60%, the cost of electricity

Documents

A Baseline for PV Hybrid System Performance and Potential …€¦ · essentiellement un système groupe électrogène/batterie auquel l’on a ajouté une matrice PV. Le rendement