ECONOMICS FOR SMALL SCALE COGENERATION IN INDUSTRY ABSTRACT Peter Nyvlt 1 1 Author affiliation: Beca Pty Ltd Level 3, 9 George Street, Parramatta, NSW. 2150 peter.nyvlt@beca.com There is a great deal of interest by industry and other sectors in reducing the energy requirements of their operations with the overall aim of reducing their organisations carbon footprint. Common techniques for reducing energy consumption include utilisation of high efficiency equipment, smart control systems, improved thermal insulation as well as others. Another approach for reducing the carbon footprint of an operation is to generate electricity on site using a low carbon fuel such as natural gas and to utilise waste heat from the generator within the facility (commonly known as cogeneration). Cogeneration is becoming increasingly popular with the light industry, commercial buildings and government sectors as a method which can make a significant reduction to the CO 2 footprint of a facility. However, can a cogeneration system provide a reasonable return on investment in the current energy price environment? This paper reviews typical system capital and operating costs and highlights key decision parameters that influence the economic evaluation of a typical cogeneration system. The information is sourced from a number of recent feasibility studies performed by Beca for Australian industry for systems in the 400 to 1,000 kw electrical generation capacity range and larger. COGENERATION IN INDUSTRY Cogeneration systems have significant potential to reduce CO 2 emissions from industry by both the recovery and utilisation of waste heat from the gas engine/turbine generator and by the utilisation of a low carbon fuel source. Operation of a cogeneration system reduces the quantity of electrical energy supplied to the site from the external grid. Electrical energy may even be exported to the grid. A typical cogeneration scheme is shown in Fig. 1. Calculation of the potential CO 2 emission reduction for a cogeneration system is reasonably straightforward. Evaluation of the economics (i.e. return on investment or payback period) however is much more complex. There are a number of factors which influence i) the capital cost of the cogeneration system and associated equipment, ii) the operating cost of the system and iii) overall energy cost savings. This paper presents a number of common factors, easily overlooked, which influence the economic evaluation of small scale cogeneration systems that would commonly be used in industrial or commercial sites. Cost figures presented are based on the use of natural gas for operation of the generator with waste heat recovered to a combination of low pressure steam and/or hot water.
Key Factors Affecting Cogeneration Economics Energy audits of industrial site are becoming more common in recent times. High level energy audits often include a review of the site electrical and heat loads and an initial analysis of the payback period for a cogeneration system. The observation from a number of feasibility studies is that the initial estimate for the payback period is often optimistic and that a number of issues need to be looked at in some detail to get a good understanding of the real costs of integrating and operating a cogeneration system on a particular site. A number of the key issues are presented below. There are two main proven types of gas powered generators which can be used in a gas fuelled cogeneration scheme; a reciprocating engine and a gas fired turbine. Both of these types are considered in the following sections. Gas and Electricity Prices Two key factors affecting the economics of cogeneration are the prices of natural gas and electricity supplied to site or, more specifically, the difference between these prices. The price of these energy sources varies from state to state and can vary from site to site and even company to company due to a range of factors. Due to this, the economics of two similar cogeneration systems is likely to be different on different sites. Apart from natural gas, cogeneration systems can utilise a variety of fuels including biogas, landfill gas and excess fuel gas. These fuel sources can be available at relatively low cost and can enhance the economics of a cogeneration system compared to a natural gas fuel source. A typical gas cost of $4.78/GJ has been considered in the figures presented in table Tab. 1. The cost of electricity sourced from the grid is typically more complex than gas, consisting of energy peak, shoulder and off-peak charges, network charges as well as other miscellaneous charges. An average electricity price of 6.5 /kwh (excluding demand charges) has been considered in the figures presented in table Tab. 1. This is based on the typical price for an industrial facility operating 24 hours and 7 days per week with a steady load profile. Annual Operating Hours The number of operating hours varies between sites. A site may operate 1 or 2 shifts per day and it may operate 5 to 7 days per week. Continuous operation of cogeneration equipment leads to higher reductions in electrical power import from the external grid and typically higher reductions in potential CO 2 emissions. However, operation of cogeneration in off-peak electricity periods when electricity prices are a fraction of peak prices typically causes an increase in operating cost during the electrical off-peak period due to the cost of natural gas required to run the system exceeding the cost of the offpeak electrical power. It is common for continuous operations to stop operation of their cogeneration equipment during off-peak periods. For systems operating with waste fuels such as biogas or landfill gas with negligible cost, this situation is normally not applicable. Maintenance The cost of maintaining a cogeneration system is significant, with significant maintenance expenditure every 3 to 4 years. Typical gas engine generator maintenance includes minor services for filter and oil changes at about 2,000 h intervals and major services at about 10,000 operating hour intervals. After about 60,000 hours operation, a 2
major overhaul of the engine is required which would require the generator out of action for up to 7 days. Typical lifecycle maintenance costs have been assessed to be in the range of 1.3 to 1.8 per kwh generated electrical power, with gas engine generators at the higher end and gas turbines at the lower end of this range. These figures are based on the gas engine/turbine generator operating close to full load and are incorporated into the generated electricity prices in table Tab.1. If the cogeneration system operates at partial load, the maintenance cost per kwh would be correspondingly higher. Generator Utilisation and Turndown Gas engine/turbine generators generally have an operating range of approximately 50 to 100% of maximum capacity. When the site electrical load fall below 50% capacity, the generator is stopped and not restarted again until prolonged operation at greater than 50% load is expected. Repeated stop/starting is not recommended for the engine/turbine generators. Due to the minimum load constraint, it is important that the cogeneration system is correctly sized so that it will operate highly loaded and not stop frequently and remain idle due to low loading. A cogeneration system running at full load continuously provides the most favourable economic return. In case of reduced site thermal load, gas engine/turbine waste heat bypasses the heat recovery systems and the cogeneration system overall energy recovery reduces. In order to maximise overall efficiency, the cogeneration system should be sized so that waste heat recovery does not exceed site requirements. Cogeneration Availability and Supplementary Systems Due to the need for stoppages to perform periodic maintenance and unplanned stoppages, the availability of gas engine/turbine generators can be in the range 95 to 98%. Gas turbines are typically towards the upper end of this range. When the cogeneration system is stopped, as well as no electrical energy being produced waste heat is no longer available for recovery. Unless site operating loads can be significantly reduced during these periods, the electrical supply system needs to be sized considering full supply from the external grid and supplementary utility systems need to be sized considering full operating duties. This leads to a high degree of redundancy and increased capital costs. Network Demand Charge Electrical network demand charges are typically based on the highest 30 minute peak period demand for the previous 12 month period. When a cogeneration system is in operation, the site electricity demand would be expected to reduce significantly and as a consequence network peak demand charges would also be expected to reduce. Due to cogeneration availability being less than 100%, there is likely a need to supply the full power demand from the grid for some periods, even if only infrequent and relatively brief. Consequently, it is likely that peak demand may not reduce significantly as a result of installing a cogeneration system unless site electricity requirements can be reduced significantly when the cogeneration system stops during peak electricity periods. Network peak demand charges depend on the site electricity demand profile and are a significant proportion of total electricity cost. Typical network demand charges would 3
be about 15% of the site total electrical costs (without cogeneration). Unless the maximum electricity demand can be reduced significantly for every 30 minute period of all peak periods over at least a 12 month period, little or no reduction in demand charges would be achieved. Through commercial discussions with electricity retailers and distributers, it may be possible to agree an alternative demand tariff for sites with cogeneration systems where network peak demand charging is less onerous in case of rare high peak demands. However, it is unlikely that a cogeneration system would reduce peak demand charges completely. Cogeneration System Electricity Consumption The total ancillary power required by a cogeneration system can be significant compared to its production, particularly for smaller systems. The cost of ancillary power should be considered when evaluating the system economics. Some examples where ancillary power is required are outlined below. Depending on the fuel and choice of gas engine or turbine, the fuel for the system may require pre-treatment, drying and compression. These systems not only increase the cost of the system, they also consume electrical power. Waste heat recovered from a gas engine/turbine to a hot water system requires a pump to recirculate the hot water. A significant quantity of electrical power can be required to maintain the circulation. Cogeneration engines/turbines are normally installed within an acoustically insulated container or plant room to limit noise. Electric fans provide positive air ventilation within the enclosure to limit the build-up of heat and an explosive atmosphere in case of a fuel leak. Site Motor Sizes The sudden stoppage of large motors causes the site electrical demand to drop almost instantaneously and can cause problems for power generation control. For a cogeneration system that does not export power and controls generated power in a manner to minimise import of electrical power from the external grid, a sudden large reduction in power demand due to the stoppage of a large motor can cause power import to reduce quickly and potentially become zero or power export. Unless the system has been specifically designed to export power, the power control system will positively prevent power export by tripping the generation system if power import falls below a set limit. To prevent potential tripping of the generation system as described above, power import to site must be sufficiently greater than the largest motor(s) on site which start/stop during operation. This issue effectively limits/reduces the generation capacity of the cogeneration system. Alternatively, key electric motors can be stopped more gradually (i.e. over a few seconds) by equipping them with variable speed drives. This however, increases the cost of the cogeneration project and affects the system payback. 4
Summary There are a significant number of issues that affect the cost of installing and operating a cogeneration system. These issues typically vary for each installation depending on the specifics of the site. A detailed review of a number of issues is required to determine the integration requirements for a cogeneration system on a site and the associated economics of the cogeneration system. Table Tab. 1 provides an indication of some of the typical costs that may be expected for cogeneration systems with different capacities. Diagrams: Fig. 1: Typical Cogeneration System Scheme 5
Tab.1: Power Generation Matrix Exhaust Cooled to 250 C Exhaust Cooled to 180 C Generation Capacity kwe Generated Elect Price excluding heat recovery /kweh Steam Generation Capacity, kg/h Exhaust Recovered Energy, /kweh Electricity Price (with heat recovery), /kweh Annual Operating Cost Savings Steam Generation Capacity, kg/h Exhaust Recovered Energy, /kweh Electricity Price (with heat recovery), /kweh Annual Operating Cost Reduction Cogen CO2-e Reduction tonnes/yr Equipment Budget Pricing * $AUS Gas Engines 400 6.6 210 0.6 6.0 $16,300 280 0.7 5.8 $22,900 1,200 $1,022,000 800 6.6 440 0.6 6.0 $35,600 600 0.8 5.8 $48,700 2,400 $1,349,000 1,560 6.6 740 0.5 6.1 $58,000 1,030 0.7 5.9 $83,800 4,500 $1,762,000 Gas Turbines 1,200 9.1 3,090 2.8 6.4 $12,300 3,930 3.5 5.7 $84,000 3,500 $4,500,000 3,500 8.1 6,690 2.0 6.1 $120,500 9,090 2.8 5.4 $328,800 11,000 $5,900,000 6,300 7.4 10,460 1.8 5.6 $481,300 13,250 2.2 5.2 $719,500 21,300 $8,100,000 * Equipment prices include gas engine/turbine and HRSG REFERENCES Information included in this paper is based on personal experience, communications and correspondence. BRIEF BIOGRAPHY OF PRESENTER Peter Nyvlt graduated from the University of Sydney with a Bachelor of Engineering (1 st class honours) in Chemical Engineering in 1983. Since graduation he has worked for a number of companies in Europe and Asia as well as Australia and has gained a broad range of experience in process control, process design, plant commissioning, operation management and safety engineering in the oil, gas, chemical, petrochemical, steel, utilities and other industries. Peter s current position is Specialist Process Engineer with Beca based in their Sydney office. He provides process engineering services and technical leadership to the Sydney process engineering team. In recent years, he has led a number of studies for a range of clients investigating the potential for implementing cogeneration systems. 6