Heat Balance Of Marine Diesel Engine Drawing

Fig. 26-35 Two 12,500 kW Multi-Valve, Extraction, Non-Condensing Steam Turbine Generator Sets in University Application. Source: Dresser-Rand
Fig. 26-36 Multi-Valve 6,327 kW Condensing Steam Turbine Generator Set. Source: Tuthill Corp. Murray Turbomachinery Div.

level of reliability makes them well-suited for critical applications and as back-up power generation for critical systems.

Steam Turbine Application Examples

Figures 26-33 through 26-38 are examples of steam turbine-driven electric generation system applications.

Fig. 26-37 Performance Curve for 6,327 kW Condensing Steam Turbine Generator Set. Source: Tuthill Corp. Murray Turbomachinery Div.

Figures 26-33 and 26-34 show skid-mounted packaged steam turbine generator sets. Figure 26-33 shows a single-stage steam turbine generator package for applications of up to 2,000 kW. Figure 26-34 shows a skid-mounted multi-stage turbine generator set with the full range of accessories, including integral speed reduction gear.

Figure 26-35 shows two 12,500 kW multi-valve extraction non-condensing steam turbine generator sets in a university application. These cogeneration units operate between 400 psig/750°F (28.6 bar/399°C) and 15 psig (2 bar), with extraction at 60 psig (5.2 bar). High turbine mechanical efficiency and a relatively large pressure/temperature drop allow these steam turbine generator sets to achieve a high power-to-steam flow ratio over the full range of extraction steam conditions. In choosing the multi-valve extraction steam turbine, the focus in this application is on optimizing power output through conservative exploitation of the low-pressure steam load or heat sink. Figure 26-36 shows a multi-valve condensing steam turbine generator set installed in a Midwest energy recovery plant. The turbine generator rating is 6,327 kW at 4,670 rpm with steam conditions of 500 psig/650°F (35.5 bar/343°C) to 3 in. HgA (10.2 kPa). The generator is driven at a speed of 1,800 rpm through a reduction gear. This bottoming-cycle application makes use of heat recovery-generated steam from a relatively high-temperature source. Figure 26-37 is a performance curve for this axial flow impulse type steam turbine.

Figure 26-38 is an example of an application featuring two very different steam turbines. The system on the

Fig. 26-38 Steam Turbine System Application Featuring One BackPressure and One Condensing Turbine Generator Set. Source: Tuthill Corp. Murray Turbomachinery Div.

Fig. 26-37 Performance Curve for 6,327 kW Condensing Steam Turbine Generator Set. Source: Tuthill Corp. Murray Turbomachinery Div.

Fig. 26-38 Steam Turbine System Application Featuring One BackPressure and One Condensing Turbine Generator Set. Source: Tuthill Corp. Murray Turbomachinery Div.

right features a multi-valve back-pressure unit rated at 1,962 kW at 7,500/1,800 rpm with steam conditions of 600 psig/650°F (42.4 bar/343°C) to 60 psig (5.2 bar). The system on the left features a condensing steam turbine rated at 2,217 kW at 5,300/1,800 rpm with steam conditions of 60 psig/323°F (5.2 bar/162°C) to 4 in. HgA (13.5 kPa).

Drivers for Combined-Cycle Electric Generation Systems

Combined-cycle electric generation systems typically consist of one or more combustion engines (most commonly gas turbines), an HRSG, and a steam turbine. Combined-cycle systems may be designed as cogeneration systems or as power generation systems without additional heat recovery. In combined-cycle cogeneration, a portion of the heat recovered from the combustion-engine topping cycle is used to meet thermal process loads. For a cogeneration system to be classified as a Qualified Facility (QF), a minimum portion — 5 or 15% — of the thermal output must be passed on to a thermal process. Combined-cycle cogeneration applications feature back-pressure or extraction condensing turbines that discharge steam at pressures above atmospheric to process.

The primary application for conventional combined-cycle generation today is in medium- and larger-scale power generation projects. However, combined-cycle power plants can also be effective in cogeneration applications as low as 5 or 10 MW Variations on the combined-cycle theme are used in which the steam turbine (and, in some cases, the combustion engine as well) is used for mechanical drive service instead of electric generation. While gas turbines are most common in combined-cycle applications in the United States, reciprocating engines are also sometimes applied.

If a facility has an extensive low-pressure steam load (and some high-pressure steam load), it often makes sense to install not only a gas turbine, but also a steam turbine as an intermediate-stage power producer. High-pressure steam is made in the HRSG, and the back-pressure or extraction steam turbine functions as a PRV, while producing shaft power for electric generation (or mechanical drive) service.

Steam pressure and quality requirements are one potential difference between conventional cogeneration and combined-cycle operation. The need for high-pressure superheated steam to drive the steam turbine can result in a two- or even threefold increase in the cost of the heat recovery steam generator. This may be cost-justified when the value of the power produced substantially exceeds the value of the potential thermal energy output or when there is insufficient thermal load to support a simple-cycle turbine-based cogeneration plant.

Combined-Cycle Cogeneration Plant Configurations

The typical combined-cycle cogeneration plant uses back-pressure or extraction turbine steam output to meet thermal load requirements. In some cases, all of the exhaust gas-generated steam is passed on to thermal processes and in other cases just a portion, depending on the load characteristics and on the relative values of producing added power or thermal energy. With a back-pressure turbine, power generation is fixed by steam flow.

Similar to the turbine arrangement shown in Figure 2638, some combined-cycle configurations include one condensing turbine and one back-pressure turbine sized to match the process load. For facilities that experience varying thermal load requirements, the use of a single multi-stage extraction/condensing turbine adds a large degree of operating flexibility. Compared with the use of back-pressure steam turbines, however, condensing and extraction turbines add significantly to overall system capital cost.

Many existing facilities that are built around steam turbine operation can be re-configured to operate as combined-cycle plants. By strategically building steam turbine loads, combined-cycle operation can be made increasingly compatible and financially attractive, even on a relatively small scale (below 10 MW). For facilities already configured with topping-, condensing-, or bottoming-cycle steam turbine operation, the addition of a gas turbine can be viewed as an alternative upstream heat source that also produces power.

Supplementary firing of combustion engine exhaust can be used to efficiently increase thermal output and control steam condition. Because a relatively small portion of the oxygen in an open gas cycle is used for combustion, the remainder, which provides oxygen-rich exhaust, can be used for supplementary firing in the exhaust duct or the HRSG. In some cases, reciprocating engine exhaust gases can also be supplementary-fired.

An important potential benefit of supplementary firing is that it can allow a facility to be more flexible in responding to varying load conditions. For combined-cycle plants that either buy or sell power with differentiated cost rate periods, it may be advantageous to increase steam turbine power output with supplementary firing in the higher cost rate periods. In cogeneration type plants that have varying thermal loads, the combustion engine exhaust can be baseloaded and supplementary firing can be

Supplementary FiringDiesel Generator Wartsila Diagram
Fig. 26-40 Heat Balance Diagram of 45 MW Combined-Cycle System Featuring Four Dual-Fuel-Fired Reciprocating Engines and One Steam Turbine. Source: Wartsila Diesel

used to meet all additional thermal loads. In many cases, dynamic operating strategies are developed to use supplementary firing to meet either peak electric or thermal loads. Similar supplementary firing strategies may also be employed with STIG-cycle systems.

Usually, the combustion engine, HRSG, and steam turbine are housed in a centralized plant, though sometimes the steam turbine is housed separately and used downstream of the steam distribution system as a pressure reducing station. Combined-cycle systems are also available as prepackaged modules, with some configurations featuring a single common shaft.

Combined-Cycle System Performance

While a large capacity combined-cycle plant can exceed thermal fuel efficiencies of 50% (LHV), cogenera-tion combined-cycle plants can reach overall thermal efficiencies of 80 or 90%, with net thermal fuel efficiencies in excess of 65%. While the heat rate of a very efficient conventional combined-cycle plant might be as low as 7,000 Btu/kWh (7,385 kJ/kWh), the net heat rate of the cogener-ation combined-cycle plant may be 5,000 Btu/kWh (5,275 kJ/kWh).

Multiple-pressure HRSGs can improve overall combined-cycle system thermal fuel efficiency when used in conjunction with steam turbines that include two or more admissions. In cogeneration applications, the lower-pressure steam can sometimes be used directly to serve thermal processes.

Overall combined-cycle thermal fuel efficiencies may be unchanged when reciprocating engines are used as the driver for the topping cycle component. However, the reciprocating engine will provide a greater portion of the total system power output. It is also necessary to find a productive process use for the lower-temperature outputs from the reciprocating engine's coolant system.

Combined-Cycle Application Examples

Figures 26-39 and 26-40 provide examples of combined-cycle applications. Figure 26-39 shows a relatively small system with a gas turbine driver and Figure 26-40 shows an application using reciprocating engine drivers (refer to Chapter 12 for additional examples of combined-cycle systems).

• Figure 26-39 shows a heat and material balance for a 9 MW combined-cycle cogeneration system applied in a paper mill, featuring a two-pressure boiler (450/5 psig) with a 150 psig steam turbine discharge pressure and water injection for NOX abatement. Notice that the non-condensing steam turbine produces only about 14% of the system's total capacity.

• Figure 26-40 is a heat balance diagram for a 45 MW combined-cycle system featuring four 6.42 MW dual-fuel-fired reciprocating engines and one 20.7 MW steam turbine. In this application, about 46% of the total energy input goes directly to the fuel-fired HRSG. More than half of the engine coolant system heat is used for preheating condensate through a heat exchanger located upstream of the deaerator. The remaining engine heat is dissipated in a jacket cooler.

Comparison of Cogeneration and Combined-Cycle Alternatives

Figures 26-41 through 26-45 illustrate five different cogeneration and combined-cycle arrangements that could be considered alternatives for a given application. Figure 26-46 is an energy map showing thermodynamic performance for each of the arrangements and Table 26-9 compares their performance. Three performance factors are compared in the table:

1. Overall thermal fuel efficiency based on the sum of the electrical output and the thermal output divided by the fuel input.

2. Net electric generation thermal efficiency based on a fuel credit for steam with an assumed displaced fired boiler fuel efficiency of 90%.

3. Electrical-to-thermal ratio (ETR) based on the heat value of electrical production versus steam production.

The five alternative configurations are described as follows:

1. Figure 26-41 illustrates the baseline arrangement

Efficiency

Efficiency

%

Electrical-to-Thermal Ratio

Simple Cycle

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