Salient design considerations for an ideal combined cycle power plant

Heat RecotwrySysteem& CliP Vol. 15, No. 2, pp. 97-104, 1995

Pergamon

08~..4332(94)0006'7-.0

c~,~ O 1994. J ~ c ~ r Scim~ i.~d PJ~nd in Greet Britain. All dShU ~ a ' v e d (~)0-.4332/95 $9J0 + .00

SALIENT DESIGN CONSIDERATIONS FOR AN IDEAL COMBINED CYCLE POWER PLANT R. G. Narula Bechtel Power Corporation, Gaithersburg, Maryland

ABSTRACT Combustion turbines and combined cycles have become a dominant mode of new capacity addition in most parts of the world. However, to maximize the benefits of a combined cycle, it must be designed to take into account site-specific technical, economic, and environmental considerations. This paper outlines the important design considerations that must be addressed in the early stages of a project's development. INTRODUCTION Combustion turbines (CTs) and combined cycles (CCs) have become the dominant form of new electric power generation in the USA; this trend seems to be spreading throughout the world. This is attributed to low installed cost per kilowatt, shorter construction schedules, low emission levels, and competitive operating costs. Recent advances in CT and compressor technology have led to thermal efficiency approaching 60 percent for gas-based CCs. However, to maximize the benefits of a CC plant, it must be designed to meet the plant's intended mode of operation and site-specific environmental requirements. This paper is an update of Reference 3 (Narula, 1993) and is based on Bechtel's recent domestic and international experience in designing CC plants. The design considerations included in this paper are: • • • • • •

Combustion turbine selection Steam cycle parameters selection NO x control technologies Single versus multishaft design Minimization of makeup water use and maximization of wastewater reuse Power enhancement alternatives COMBUSTION TURBINE SELECTION

Unlike steam turbine (ST) selection, where turbine suppliers can offer STs with ratings very close to the desired rating, CTs are available in discrete sizes with fixed ratings at the standard conditions (15 °C [59 °F], 1.013 bara [14.7 psia], and 60 percent relative humidity [RH]). Before selecting the type of CT, it is important to understand the following basic objectives and economic criteria: •

Desired overall plant rating at a predefined site ambient temperature 97

R. G. Narula

98

Intended mode of plant operation such as base load or peaking Plant economic parameters such as the value of incremental output in $/kW and incremental heat rate in S/kJ/kWh Broadly speaking, CT suppliers offer heavy-duty and aero-derivative combustion turbines. Heavy-duty CTs are further classified as conventional or advanced, depending on the firing temperature. Each of these types have certain technical features which offer operational and economic advantages to the owner. A detailed technical and economic evaluation is required to select the CT that best meets the basic plant objectives and economic criteria. The salient features of each of these types of machines are: Aero-derivative CTs CT size is limited to approximately 40 MW or less. This leads to a CC output of 55 to 60 MW. For a larger plant, multiple CT units are required. Higher firing temperature (1,200 to 1,260 °C or 2,200 to 2,300 °F) and higher compression ratio yield high CT thermal efficiency (up to 42 percent). Units are lighter and very compact, come in modular design, and as such, require less real estate. The engine can be replaced on site in about 2 days. Conventional CTs •

Proven designs with extensive operating experience. Modest firing temperatures (approximately 1,100 °C or 2,000 °F) yield somewhat lower efficiency.

•

Generally more fuel impurities tolerance than aero-derivative or advanced CTs. Available up to about 110 MW in 60 Hz applications and 165 MW in 50 Hz applications.

Advanced CTs Available up to about 165 MW in 60 Hz applications and 240 MW in 50 Hz applications. This leads to a CC plant of about 250 MW in 60 Hz and about 360 MW in 50 Hz applications. Higher firing temperatures (up to 1,290 °C or 2,350 °F) yield thermal efficiencies of up to about 38 percent in simple cycle and 58.5 percent in combined cycle plants. Higher exhaust temperatures (approaching 595 °C or 1,100 °F) make reheat steam cycles economically viable. STEAM CYCLE PARAMETERS SELECTION Considerable savings in life-cycle cost of a CC can be achieved by optimum selection of key cycle design parameters. The key steam cycle design parameters include initial steam conditions,

Designing combined cycle power plants

99

single versus multipressure heat recovery steam generators (HRSG), and reheat versus non-reheat cycles. Initial Steam Conditions Initial steam pressure for CCs is generally in the 62 to 103 barg (900 to 1,500 psig) range (as opposed to 124 to 240 barg [1,800 to 3,500 psig] for coal/oil/gas-fired power plants). The heat rate improvement due to still higher pressures (higher than 103 barg or 1,500 psig) is marginal and in many cases is not economically justifiable. This is attributed to the absence of regenerative feedwater heaters in the CC plants and to the fact that the ST represents only 30 to 35 percent of the total CC output. As an example, for a GE 7EA based CC, the increase in initial pressure from 62 to 86 barg (900 to 1,250 psig) increases the output (and improves the heat rate) by 0.5 percent. The corresponding change from raising the initial pressure from 86 to 100 barg (1,250 to 1,450 psig) is only 0.1 percent. The other practical consideration is to limit moisture in the last stage of the ST to about 13 percent. The initial steam temperature generally ranges from 426 to 538 °C (800 to 1,000 °F) and is limited by the CT exhaust temperature. Single Versus Multipressure HRSG Effective recovery of CT exhaust heat depends on the number of pressures at which steam is raised in a HRSG. Heat extraction at a single pressure is limited because the temperature of exhaust gas leaving the evaporator section of the HRSG must be above the saturation temperature of steam being raised. Because of the limited amount of heat that can be recovered in an economizer, single pressure HRSGs result in higher stack temperature and hence lower cycle efficiency. They are, however, less costly to install, require less space, and result in lower maintenance costs. Multipressure HRSGs, on the other hand, are more costly but result in substantially higher heat recovery. As an example, heat recovery with a two pressure cycle results in a 3.5 to 4.0 percent better heat rate than a single pressure cycle. Adding a third pressure level allows an additional 1.0 percent better heat rate (General Electric, 1990) but at a higher cost. In most cases, three pressure HRSGs are cost-effective. Reheat Versus Non-reheat Cycle Steam reheating improves cycle efficiency because thermal energy is more effectively utilized. Additionally, reheating reduces the moisture content of the steam in the low pressure turbine stages permitting the use of longest available last-stage blades without undue risk of erosion. A reheat cycle has a thermal efficiency advantage of 0.7 to 0.9 percent over a non-reheat cycle (General Electric, 1990). Since reheating adds significant cost and complexity to the plant, it is generally not cost-effective for conventional CTs where reheating is limited to about 480 °C (900 °F) because of relatively lower CT exhaust gas temperature (< 538 °C or 1,000 °F). With advanced CTs where exhaust temperatures approach or exceed 595 °C (1,100 °F) and reheat steam temperature up to 538 °C (1,000 °F) is achievable, reheating has been found to be costeffective. A more comprehensive analysis of cycle selection considerations is presented in Reference 7 (Tawney, 1990). NO x CONTROL TECHNOLOGIES A CC cogeneration project may look economically attractive if it is located in an industrial park close to a steam host, a natural gas pipeline, and an electric utility substation. However, if the ambient air concentration of a regulated pollutant exceeds the regulatory requirements, plant permitting may become a more difficult issue. Even though carbon monoxide, volatile organic compounds, sulfur dioxide, and particulate are receiving increasing scrutiny for gas-fired CC

100

R.G. Narula

plants, NO x emissions are still the major issue. Air emissions permitting issues are addressed in detail in Reference 1 (Desai, 1991). An overview of the available NO x control technologies is outlined below. There are currently three technologies available to control NO x in a CT. These are steam injection, water injection, and dry low NO x combustion. Each of these technologies has a significant impact on the plant output, heat rate, and overall capital and operation and maintenance cost. While a site-specific study based on the plant's economic evaluation parameters must be carried out, the following trends have emerged from past Bechtel studies. For natural gas-fired CTs, NO x emissions to 25 parts per million by volume, dry (ppmvd) corrected to 15 percent 02 can be achieved by any of these technologies. Some CT suppliers are offering NO x levels as low as 9 ppmvd with dry low NO x combustion technology. NO x emission limits below those attainable through combustion technology require the use of selective catalytic reduction (SCR) technology. The SCR system is installed in the HRSG. Dry low NO x combustion technology today is not only an acceptable alternative, but also a cost-effective answer to growing regulatory demands for further reduction in NO x emissions. Reference 8 (Ugolini, 1992) describes in detail the status of dry low NO x technology and compares it with the other NO x control methods. Steam or water injection, while producing higher plant output, has an adverse impact on plant heat rate and perhaps on CT component life. Table 1 shows a comparison of plant performance for the three NO x control methods for a 230 MW CC plant. It is important to note that this comparison is based on reducing NO x level to 25 ppm. TABLE 1 Performance Effects of NO x Control Methods Dry Low NOxm

Water Injection

Steam Injection

Combustion Turbine Output

Base

+8.5%

+14.0%

Combustion Turbine Heat Rate (LHV)

Base

+3.5%

-5.8%

Combined Cycle Net Output

Base

+6.9%

+3.9%

Combined Cycle Net Heat Rate (LHV)

Base

+5.2%

+3.5%

Notes:

2.

This table is based on a nominally rated 230 MW CC plant using an advanced heavy duty CT rated nominally at 160 MW at ISO conditions and firing natural gas. The performance numbers are based on ambient conditions at 15 °C (59 °F), 1.013 bara (14.7 psia), and 60 percent RH. SINGLE VERSUS MULTISHAFT

There is a recently renewed interest in single-shaft combined cycle (SSCC) power plants because of their perceived lower capital cost. The term SSCC refers to the configuration where the CT and ST drive a single electric generator, the various rotors being connected by couplings to form a single shaft and operating at a common speed. The configuration where each CT and ST drives

Designingcombined cycle power plants

10l

a separate electric generator is called a multishaft combined cycle (MSCC). Combining CT and ST shafts eliminates one electric generator, its associated bus duct, transformer, and control and protection equipment. Thus the SSCC reduces the cost of, and the space requirements for, the power generation equipment. These savings, in what is typically called power island equipment, earl be as much as $10 to $20/kW. The power island generally comprises the CT, HRSG, ST, distributed control system (DCS), and continuous emissions monitoring system (CEMS) equipment. Reference 4 (Narula, 1993) covers in detail the impact of SSCC design on the balance-of-plant (BOP) equipment cost, reliability, operational flexibility, and maintainability of the plant. On an overall plant basis, the total installed cost savings are approximately 2 to 4 percent. A major portion of the cost savings is due to reduced cost of the major equipment provided by the power island supplier. The savings associated with the BOP equipment are very site, client, and CT supplier-dependent. A detailed project-specific study is recommended to establish the actual cost savings. From the studies undertaken by Bechtel, the following conclusions emerge: For all practical purposes, there is very little difference in plant availability and heat rate between the two designs. Overall plant construction duration is also about the same. The anticipated reduction in field labor due to fewer components and potentially decreased bulk quantities of the SSCC is offset by the increased rigging effort associated with the heavier electrical generator and transformer. SSCC design with a ST clutch provides some operational flexibility to operate the CT in simple cycle when the ST is either not available or not required. In SSCC designs without an ST clutch, an auxiliary boiler is often required to provide sealing and last stage blade cooling steam for the ST during startup. MSCC configuration allows construction of plant in phases. For the SSCC design, civil/structural costs tend to decrease, mechanical piping and equipment costs tend to increase, and electrical equipment and wire and cable costs tend to decrease. The major thing to watch for is cost of the generator breaker. For larger CC plants (> 100 MW), if the combined output of CT and ST requires the use of an in-line S F 6 type breaker in lieu of a metal-clad vacuum type breaker, there is significant increase in the breaker cost. This may nullify all of the BOP cost savings. MINIMIZATION OF MAKEUP WATER USE AND MAXIMIZATION OF WASTEWATER REUSE In arid, water-short, or heavily populated regions where tight restrictions are imposed on water withdrawal/use and wastewater discharge, alternatives must be found to satisfy these restrictions. Reference 5 (Sinha, 1993) covers this subject in greater detail. In summary, the options available for minimization of water use and maximization of wastewater use are: Using an air-cooled condenser in lieu of surface condenser/cooling tower. Plant output reduction due to higher condenser pressure must be weighed against the cost associated with obtaining makeup water, water treatment of the circulating water system, and the wastewater treatment of the cooling tower blowdown. Use of dry low NO x combustors can significantly reduce the makeup water requirements. Use of flash tanks to partially recover the HRSG blowdown can further reduce the makeup water requirements.

102

R. G. Narula

Because of the cleaner environment of CC plants, the floor drains from the CT and HRSG areas can be treated with an oil/water separator and/or membrane type filters and recycled to the cooling tower or raw water tank. Wet cooling towers can be optimized to operate at the maximum cycles of concentration that can be tolerated by the selected materials of construction for the condenser and the circulating water system. This would reduce the cooling tower blowdown significantly. Where cost-effective, use of rental demineralizers should be considered. This eliminates any onsite regenerant waste that requires neutralization and disposal. Elimination of pretreatment equipment for makeup water would minimize wastewater generation. Therefore, a water source with low suspended solids, such as city water, should be selected where economically viable. POWER ENHANCEMENT ALTERNATIVES In a CC plant, the power output varies with the ambient temperature. During summer months, a CC plant could lose as much as 10 to 15 percent of its rated ISO output. In many power purchase agreements (PPAs) between the utility and the non-utility generator, the capacity charge is based on the peak output that can be demonstrated on a preselected hot summer day. In such cases, a 10 to 15 percent reduction in output in summer may economically be unacceptable to the power producer. Peak load output enhancement methods are intended to cover all or part of the CC plant power lost during hot weather. In generic terms, the concept is to increase the mass flow through the power-producing portions of the cycle. The predominant methods for power output enhancement are: •

CT inlet air cooling with evaporative or refrigeration cooling

•

CT power augmentation with steam or water injection

•

Supplemental firing of the HRSG

Each of the above power enhancement methods will result in a different level of power output recovery and will have a varying effect on the overall plant thermal performance and capital cost. Table 2 provides the performance and incremental capital cost summary. A detailed analysis of each of the alternatives is outlined in Reference 6 (Tawney, 1993). Selection of a power enhancement option is often project-specific and is based on variables that include site ambient conditions; the level of desired output enhancement; the anticipated hours of operation; water availability; allowable plant emissions; PPA structure; and Owner's economic evaluation factors for plant output, heat rate, and O&M costs. Nevertheless, the following generic conclusions can be drawn from past Bechtel projects: A significant gain in net plant power output can be obtained from all the power enhancement options except the evaporative cooling option, which is not particularly effective when utilized in a location with high RH. The cooling effect achieved with evaporative cooling is dependent upon the ambient wet bulb temperature. Thus for dry arid regions with low relative humidity and prolonged summers, evaporative cooling will most likely be the preferred choice. However, for regions with high relative humidity and a PPA where capacity charge

Designing combined cycle power plants

103

TABLE 2 Performance and Cost Summary for Power Enhancement Alternatives Parameter

Change in CT Output, kWe

Change in ST Output, kWe

Change In Auxiliary Power, kWe

Change in Net Plaat Outpm, kWe

Change in Net Plant Heat Rate (LHV), U/kWh

Change in Makeup Water Consump., mJ/hr

Cspital Cea/ lnermteatal Net Output, $1kWe

Base

Base

Base

Base

Base

Base

Base

! Case I Evap. Cooling

+5,800

+900

+50

+6,650

-16

+18

+180

Case 2 Evap. Cooling @ 40% Rtl

+ 10,000

+4,200

+100

+14,100

-137

+28

+85

Case 3 Mech. Chilling

+20,200

+2,400

+4,500

+18,100

+58

+23

+155

Case 4 Absorp. Chilling

+20,200

-2,100

+700

+ 17,400

+74

+23

+230

Case 5 Steam Inj. Power Aug.

+21,800

-13,000

+400

+8,400

+285

+69

+75

Case 6 Water Inj. Power

+15,500

+3,700

+200

+ 19,000

+459

+52

+15

+8,000

+400

+7,600

+95.

+23

+70

+35,000

+ 1,000

+34,000

+338

+9'7

+450

Base Case w/o Power Enhancement

Aug. Ca~ 7

PartiallySupp. Firing Case 8 Full Supp. Firing Notes: I. 2.

Table based on a 230 MW CC plant using an advancedheavy duty CT nominally rated at 160 MW at ISO conditions and firing natural gas. Plant performancefor all the cases is based on ambientcondition of 35 *C DB and 60 percent RH except Case 2, which is based on 40 percent RH.

is based on demonstrable peak summer output, refrigeration cooling of inlet air will offer a more reasonable solution. During peak periods or for PPAs where the energy charge is extremely high, water injection or supplementary firing of the HRSG may be the option of choice. For the supplementary firing options, additional fuel burned in the duct burner may increase the potential emissions of NO x and CO in tons per year and may possibly require a larger SCR and CO catalyst. CONCLUSIONS

As long as natural gas prices stay at or near the current level, CC plants will continue to be the dominant mode of new power generation. In today's competitive market, the success and viability of the CC plant depend on correct and careful selection of plant design parameters. As these decisions are made at the onset of a project, a detailed, project-specific study is recommended as soon as the project's principal objectives are established. REFERENCES .

Desai, M. S. and R. G. Narula. "Air Emissions Permitting Trends for Combined Cycle Projects." Paper presented at the POWER-GEN Conference, Tampa, Florida, 1991.

104

2.

R. G. Narula

General Electric 35th GE Turbine State-of-the-Art Technology Seminar Booklet, 1990.

.

Narula, R. G. "Design Considerations in Selecting a State-of-the-Art Combined Cycle Power Plant." Paper presented at the POWER-GEN AMERICAS Conference, Dallas, Texas, 1993.

.

Narula, R. G., P. J. West, and B. M. Banda. "Single-Shaft Combined Cycle Plants: The Pros and Cons." Paper presented at the POWER-GEN EUROPE Conference, Paris, France, 1993.

.

Sinha, P. K. and R. G. Narula. "Innovative Methods to Minimize Wastewater in Fossil Power Plants." Paper presented at the POWER-GEN EUROPE Conference, Paris, France, 1993.

.

Tawney, R. K., R. G. Narula, M. J. Boswell, and F. DeCandia. "Power Output Enhancement Options for Combined Cycle Plants." Paper presented at the International Joint Power Conference, Kansas City, Missouri, 1993.

.

Tawney, R. K., D. J. Ugolini, T. J. Wengert, and R. G. Narula. "Steam Cycle Selection Considerations for a Combined Cycle Plant." Paper presented at the Joint Power Conference, Boston, Massachusetts, 1990.

.

Ugolini, D. J., R. K. Tawney, and R. G. Narula. "Dry Low NOx--A Technology of Choice for Combined Cycle Plants." Paper presented at the POWER-GEN Conference, Orlando, Florida, 1992.