Nội dung

GE Energy Cogeneration Application Considerations John A. Jacobs III Technical Leader Evaluation & Analysis Martin Schneider Senior Marketing Manager May 2009 Contents: Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Cogeneration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Net Heat to Process and Fuel Chargeable to Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Steam Turbines for Cogeneration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Steam Turbine Performance Flexibility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 Cogeneration and Reheat Steam Cycles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 Cogeneration with Gas Reciprocating Engines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 Gas Engines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 Cogeneration – Overall Efficiencies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Power and Heat Utilization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Fuel Flexibility and Gas Reciprocating Engines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 Gas Turbine and Combined Cycles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 Gas Turbine Power Enhancements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 Fuel Flexibility and Gas Turbines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 Gas Turbine Exhaust Heat Recovery. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22 Heat Recovery Steam Generators . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22 HRSG Steam Production Rates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24 Cycle Configurations. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 Combined Cycle Design Flexibility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 Cogeneration Opportunities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37 Conclusion. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40 Acknowledgement. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40 List of Figures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41 List of Tables. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42 GE Energy | GER-3430G (05/09) i Cogeneration Application Considerations Introduction Cogeneration or CHP (Combined Heat and Power). The terms cogeneration and CHP are used interchangeably in this paper and are defined as the combined simultaneous generation of heat and electrical energy with a common source of fuel. Common examples of cogeneration applications include pulp and paper mills, steel mills, food and chemical processing plants, and District Heating (DH) applications. Since the beginning of the 20th century, cogeneration technology has been utilized by many industrial companies as an eco-friendly means to economically meet a plant’s combined heat and power demands. The volatility of fuel costs and electricity prices in deregulated markets—coupled with the need to secure reliable heat and power supplies, along with new environmentally based financial incentives—are driving the evolution of this technology. These key factors are causing many industrial companies, municipalities, developers and utilities to give even more consideration to cogeneration as an eco-friendly, profitable, and reliable means of addressing their specific generation needs while also meeting local environmental regulations. In the past and certainly prior to 1960, most cogeneration applications were developed based on steam turbine cogeneration Universal sensitivity to our environment and environmental considerations have led to the development of projects that not only minimize GHG (Green House Gas) emissions, but also help to displace GHG emissions from existing plants as well as other emissions sources. Thus, one of the more significant advantages for gas turbine, combined cycles and gas reciprocating engines is the potential for GHG reductions as compared to less efficient systems. This monetization of GHG reductions serves as a significant driver/incentive for the development of gas-turbine and gas-engine-based cogeneration applications. Cogeneration applications range from industrial applications such as pulp and paper mills, steel mills, and chemical processing plants to commercial and civic-based applications like hospitals, universities and warehouses—thus encompassing a wide range of unique power-to-heat ratios. The variation of power-to-heat ratio combined with differences in grade/quality of heat (such as water, steam, and process heating/cooling) within the cogeneration application space are dictating both technology selection as well as system and product flexibility requirements. The primary objectives of this paper are to: • Review many of the technical considerations and alternative systems consisting of conventional fossil-fired boiler(s) in addition options associated with the development of cogeneration to an industrial type steam turbine and/or combinations of systems. industrial type steam turbines. More recent factors have made gas • Discuss some of the environmental benefits that are potentially turbine and engine based solutions highly desirable, including: available through cogeneration, and to introduce the concept of • Potential economic benefits resulting from higher monetization (primarily surrounding CO2). power-to-heat ratios • Rising fuel costs • Operational flexibility • Illustrate and provide the CHP performance characteristics associated with GE’s diverse gas turbine and reciprocating gas engine product portfolios that can ultimately be leveraged for project and technology screening purposes. • Emerging environmental policies and incentives The technical parameters provided include—but are not • Increased focus and need for power security limited to—power-to-heat ratio, equipment capacity • Availability of a wide range of system integration options coupled with attractive cogeneration system performance levels These technological advances in the area of fuel flexibility, as well as gas turbine and engine product diversification/adaptation, have served as enablers to make some cogeneration opportunities feasible, while making others even more attractive. GE Energy | GER-3430G (05/09) (thermal/electrical) and efficiency/FCP (Fuel Chargeable to Power), and/or SFC (Specific Fuel Consumption) in the case of reciprocating gas engines. This paper reviews many of the technical, economical and environmental considerations in the development of cogeneration projects. 1 Cogeneration Cogeneration is frequently defined as the sequential production • Power generation derived from exothermic process reactions, and heat recovery from kilns, process heaters and furnaces. of necessary heat and power (electrical or mechanical) or This paper focuses primarily on application considerations for the recovery of low-level energy for power production. This topping cogeneration cycles. sequential energy production yields fuel savings relative to separate energy production facilities because both the heat and power requirements are satisfied from a common/single fuel source. The heat that would otherwise be wasted in the power production process is recovered and leveraged to provide process heat requirements (which otherwise would have to be generated with a separate fuel source), thus providing significant fuel savings. For comparative purposes Figure 1 illustrates energy utilization effectiveness (the percent of total energy output from the cycle which is useful heat and/or power) for a typical non-reheat coalfired utility/industrial plant configuration (three-stage feed water heating with steam conditions of 1450 psig / 950°F [101 bar / 510°C] steam conditions vs. a cogeneration facility utilizing the same fired boiler but with a non-condensing steam turbine generator that supplies steam to process. This diagram suggests With the recent increases in gas and oil prices, advancements in that relative to the typical coal-fired power generation application gas-turbine and gas-reciprocating-engine fuel flexibility—combined (as previously defined) the energy utilization associated with an with a worldwide desire to reduce GHG (Green House Gas) equivalent cycle with cogeneration can be improved by as much as emissions, increase power security (through localization of power 35%. This improvement in energy utilization is made possible generation), and attractive cogeneration system efficiency levels— because the process demand becomes the heat sink for the have sparked renewed interest in cogeneration applications. cogeneration cycle, thus eliminating energy losses associated Power can be cogenerated in topping or bottoming cycles. In a primarily with the condenser. topping cycle, power is generated prior to the delivery of thermal energy to the process. Typical topping cycle examples include: • Non-condensing steam turbine cycles (commonly used in the Power Generation pulp and paper industry) • Heat recovery and combined cycles (applied in many chemical plants), where exhaust energy for a gas turbine or heat from gas reciprocating engines provide thermal energy that is ultimately used to satisfy the process requirements • Central heating/cooling applications that exist in urban locations where electric power stations also supply thermal energy (or similarly on a smaller scale, where heating/cooling 35% is Output as Power 2% 15% Other Boiler Assoc. 48% Losses Condenser Losses Cogeneration 15% Boiler Assoc. Losses 84% is Output as Power and Process Heat 1% Other Basis: 1) Typical industrial – coal-fired system 2) Effectiveness on higher heating value of coal Figure 1. Fuel utilization effectiveness (fossil-fired boiler) requirements are recovered from gas turbine or gas reciprocating engines to satisfy localized, civic or commercial This principal is further illustrated by Figure 2, which highlights the based CHP requirements) influence of decreasing the thermal energy to a process from a In bottoming cycles, power is produced from the recovery of process thermal energy that would normally be rejected to the heat sink. Typical bottoming cycle examples include: • Power generation resulting from recovery of excess thermal energy (combined cycle steam turbine output generation) 2 steam turbine cycle. As less steam is delivered to process, the electrical output ratio (relative to the electric output at 100% steam-to-process) increases, becoming a maximum of about 2.0 for the steam conditions noted if no steam is delivered to process. The overall efficiency decreases from 84% to 35% as process steam delivery is eliminated. Figure 1 and Figure 3 clearly illustrate that from a fuel utilization 100 1.75 75 1.50 50 1.25 25 1.00 0 20 40 60 Overall Efficiency % (HHV) Relative Electrical Output 2.00 0 100 80 perspective, cogeneration system performances are significantly better than typical steam turbine or gas turbine combined cycles that are designed to only produce power. Today, across the globe, many local governmental incentives have been established to help promote the development of new cogeneration applications with an objective of driving fuel utilization. One such example is the SPP (Small Power Plant) in % Steam to Process Thailand. While such incentives are not new (for example, PURPA in Basis: 1) Steam conditions 1450 psig, 950°F (101 bars, 510°C), 150 psig (11.4 bars) process, 2 1/2" (63.5mm) HgA condenser pressure 2) Three stages of feedwater heating 3) Boiler efficiency 85% HHV Figure 2. Steam turbine cycle performance at various process steam demands the US), the underlying motivations can be different. More often than not, current incentives are borne out of a want, desire and need to reduce green house gas emissions, whereas the motivations of the past may have focused more on fuel utilization from an energy market perspective (deregulation and market Similar performance benefits are also available in gas turbine and reciprocating gas engine cogeneration systems. For example, an Fclass technology gas turbine generator with feeding to an HRSG (which in turn provides process steam) can yield overall energy effectiveness levels between 80-85% depending upon process competition). In support of today’s market drivers GE not only maintains a position of industry leadership in the areas of gas turbine and gas engine fuel flexibility and emissions capability, but also continues to evolve world-class advanced technology with focused research and development efforts in these areas. steam conditions. In comparison, the same F-class gas turbine in combined cycle (and producing power only) yields an overall energy effectiveness of between 50-55% depending upon the cycle Coincidentally, in the case of the aforementioned regulations a STAG (STeam And Gas) cycle qualification is/was to provide about 6% of its steam generation to process. At this operating condition, design. This comparison is illustrated in Figure 3. the overall performance approaches that of a conventional STAG It is worthy to note that energy effectiveness as previously defined differs from efficiency/CHP efficiency in that CHP Efficiency is defined as the useful energy-out (combined heat and power) divided by energy-in (energy in the fuel), whereas energy power generation cycle. Later in this paper, tables are provided that define GE’s gas turbine and gas engine product characteristics, which in turn illustrate the wide application range and flexibility of these products to support cogeneration effectiveness also accounts for the energy in the air. By applications. comparison the efficiency/CHP efficiency for gas-turbine-based cogeneration plants are 90+% versus 80+% for a conventional For purposes of the following discussions, “thermally optimized” cogeneration systems are defined as those developed using non- steam plant based cogeneration system. condensing steam turbine generators or condensing units operated at minimum flow to the condenser for cooling purposes. Combined Cycle Power Only 50% Electrical Output 5% 20% Misc. Stack 25% Condenser Losses Combined Cycle Cogeneration 18% Stack 80% Electrical + Thermal Output 2% Misc. Net Heat to Process and Fuel Chargeable to Power In evaluating and comparing alternative cogeneration cycles, two concepts are key: Net Heat to Process (NHP) and Fuel Chargeable to Power (FCP). Both concepts are “Btu/kJ accounting methods” that can be leveraged to provide normalized performance comparisons between different sized cogeneration systems and different technologies. In turn, the products of these methodologies Figure 3. Fuel utilization effectiveness (combined cycle/gas turbine based) GE Energy | GER-3430G (05/09) 3 become the basis of the performance that is used in the economic Configurations 1, 3 and 4 (illustrated in Figure 6) provide steam at a modeling process. “controlled” pressure, consistent with the process header Net Heat to Process is defined as the net energy supplied by the cogeneration system to the process load, as depicted in Figure 4. It is necessary to maintain a constant NHP for all systems being considered, especially when different gas- and steam-turbine configurations export energy to process at different conditions. requirements. Configuration 5 includes two uncontrolled extraction openings in the steam turbine generator and provides steam that would be taken to a common line and pressure-reduced if necessary to meet the pressure requirements in the process. The higher uncontrolled opening would be used during lighter load operation of the turbine, when the pressure at the lower opening is Fuel Chargeable to Power (FCP) is a parameter used to define the too low for process use. Uncontrolled-extraction turbines of this thermal performance of a topping cogeneration system. The FCP is type are typically used when process extractions are small defined as the incremental fuel for the cogeneration system, compared to total turbine flow—or when process needs are fairly relative to the fuel needs of a heat-only system divided by the net constant except during start up, shut down or emergency incremental power produced by the cogeneration system. Simply situations. put, FCP is the incremental fuel divided by the incremental power (i.e., the incremental heat rate). For a plant generating electric power only (an industrial or a utility), the FCP and net plant heat rate are interchangeable terms commonly expressed in Btu/kWh Turbines represented in Configurations 1 and 3 will yield power dependent directly on process demands, since no condensing section capability exists. Their power production depends on the rise and fall of the steam demand. The addition of condensing or kJ/kWh. The FCP concept is illustrated in Figure 5. capability (Configurations 2, 4 and 5) provides added power- Steam Turbines for Cogeneration generating flexibility. When a condenser is used, power can be Figure 6 shows several steam turbine configurations that can be used to generate power while satisfying a process need for steam. generated independently from the process steam demand (assuming that the steam turbine is sized accordingly). Steam turbines generally can be designed to meet the specific In “thermally optimized” steam turbine cogeneration cycles, steam process heat needs. Unlike gas turbines that are sold in specific is expanded in non-condensing or automatic-extraction non- sizes or frame sizes, steam turbine generators have traditionally condensing steam turbine-generators that extract and/or exhaust been custom-designed machines and seldom have 100% identical into the process-steam header(s). The FCP for these systems is components or capabilities. However, it should be noted that many typically in the 4000 to 4500 Btu/kWh HHV (4220 to 4750 kJ/kWh) OEMs (including GE) continue to push more and more toward range. The influence of initial steam conditions and process steam product and as a minimum component/hardware standardization wherever possible. Plant Supplying Heat Only Fuel (2) Steam to Process Wp Hp Boilers DA Wr hr Wmu hmu P R O C E S S KW (2) Process Figure 4. Net Heat to Process (NHP) 4 Steam Steam Fuel (1) HRSG Aux Power (1) NHP = WpHp – WrHr – Wmuhmu Plant Supplying Power and Heat FCP = Aux Power (2) Fuel (2) – Fuel (1) KW (2) – Aux Power (2) + Aux Power (1) Figure 5. Fuel Chargeable to Power (FCP) pressure on the amount of cogenerated power per 100 million It should be noted, and it may even be obvious, that there is a Btu/h (105.5 GJ/h) NHP is illustrated in Figure 7. The increase in correlation between fuel price and/or energy prices and the initial cogenerated power through the use of higher initial steam steam condition selection for a given application. Specifically, this conditions, and lower process pressures, is readily apparent. illustrates that higher fuel prices and/or energy prices favor the upper portion of the bands shown in Figure 8. Studies have shown that higher steam conditions can be economically justified more easily in industrial plants with relatively Even when utilizing the most effective thermally optimized steam large process steam demands. Data given in Figure 8 provide turbine cogeneration systems, the amount of power that can be guidance with regard to the initial steam conditions that are cogenerated without a condensing section to the steam turbine, normally considered for industrial cogeneration applications. per unit of heat energy delivered to process, will usually not exceed 1. Straight Non-Condensing Steam Turbine Generator (SNC) 2. Straight Condensing Steam Turbine Generator (SC) To Process Gen. Gen. Condenser To Process 3. Single Automatic Extraction Non-Condensing Steam Turbine Generator (SAEC) 4. Double Automatic Extraction Condensing Steam Turbine Generator (DAEC) Gen. Gen. Condenser To Process P1 To Process P2 To Process P1 To Process P2 5. Uncontrolled Extraction Steam Turbine Generator NOTE: Steam Turbine Configuration Options for Either: Fossil-Fueled Steam Plants OR Combined-Cycle Plants To Process Figure 6. Steam turbine configurations for power generation and process needs GE Energy | GER-3430G (05/09) 5 about 85 kW/MBtu (0.6 kW/GJ) net heat supplied. This is generally condensing steam turbine is likely necessary to provide the less power than that required to satisfy most industrial plant balance of the industrial plant power needs. electrical energy needs. Thus, with thermally-optimized steam turbine cogeneration systems, a purchased power tie or additional Condensing power generation (although not necessarily energy efficient) has proven economic in many industrial applications. Favorable economics are often associated with systems where: kW Generated per 1 Million Btu/hr (1.055 MkJ/hr) of Net Heat to Process • Condensing power is used to control purchased power demand 80 Power to Heat Ratio • Low-cost fuels or process by-product fuels are available Turbine Inlet 70 • Adequate low-level process energy is available for a bottoming 1450 psig – 950°F (101 bars – 510°C) 60 cogeneration system 50 40 • Condensing provides the continuity of service in critical plant 30 operations where loss of the electric power can cause a major 600 psig – 750°F (42.4 bars – 399°C) 20 850 psig – 825°F (59.7 bars – 440°C) disruption in process operations and/or plant safety 10 0 • Utility-specific situations favoring power sales, particularly if low 0 Process Steam 0 Pressure 100 200 6.9 13.8 300 psig 20.7 400 500 600 28.6 34.5 42.4 bars cost fuels are available Steam Turbine Performance Flexibility Significant flexibility is achieved when combining a non- Basis: condensing turbine with a condensing steam turbine, or when a 1) Average temperature of process returns and makeup is 165°F (74°C) steam turbine supplies controlled pressure steam to more than one 2) Power cycle credited for feedwater heating to: 455°F (235°C) for 1450 psig (101 bars) 400°F (204°C) for 850 psig (59.7 bars), and 370°F (188°C) for 600 psig (42.4 bars) systems process header. This is accomplished with a single- or double-auto extraction condensing steam turbine generator. (See Figure 6.) 3) Turbine efficiency 75% Figure 9 illustrates a performance map (flow vs. kilowatt output) for Figure 7. Cogeneration power with steam turbines a single auto extraction steam turbine generator. This generic performance map applies equally to single-auto non-condensing and to single-auto condensing steam turbine generators. The Inlet Steam Conditions maximum throttle flow line (B-C) defines the maximum guarantee bars °C 129 / 538 psig °F 1800 / 1000 101 / 510 1450 / 950 steam turbine, whereas the zero extraction line (E-D) shows the 87.2 / 482 1250 / 900 performance of the steam turbine with zero extraction. The line on 59.7 / 440 850 / 825 42.4 / 399 600 / 750 28.6 / 343 400 / 650 17.6 / 260 250 / 500 steam flow that can be admitted to the high-pressure inlet of the the far left (A-B) defines the performance of the steam turbine with minimum flow to exhaust. This portion of the curve denotes a turbine operating with only cooling steam being sent to the exhaust of the steam turbine and the balance of steam is 0 100 200 300 400 500 600 operating as a non-condensing turbine. The sloping lines in the 1000 lb/h 0 45 91 136 182 227 273 Tons/Hr Turbine Inlet Steam Flow Figure 8. Range of initial steam conditions normally selected for industrial steam turbines 6 extracted. In this area of the curve, the steam turbine is essentially center of the performance map (E’-D’) are lines of constant extraction flow. The performance map (or envelope) flows and kilowatt production accurately define the flexibility of the steam turbine, and in the