ENERGY MANAGEMENT HANDBOOKS phần 3 ppt

172 ENERGY MANAGEMENT HANDBOOK data, confi rm selected alternative and fi nally size the plant equipment and systems to match the application. Step 3. Design Documentation. This includes the preparation of project fl ow charts, piping and instru- ment diagrams, general arrangement drawings, equipment layouts, process interface layouts, building, struc- tural and foundation drawings, electrical diagrams, and specifying an energy management system, if required. Several methodologies and manuals have been developed to carry out Step 1, i.e. screening analysis and preliminary feasibility studies. Some of them are briefl y discussed in the next sections. Steps 2 and 3 usually require ad-hoc approaches according to the characteristics of each particular site. Therefore, a general methodology is not applicable for such activities. 7.2.4.2 Preliminary Feasibility Study Approaches AGA Manual—GKCO Consultants (1982) developed a cogeneration feasibility (technical and eco- nomical) evaluation manual for the American Gas As- sociation, AGA. It contains a “Cogeneration Conceptual Design Guide” that provides guidelines for the development of plant designs. It specifi es the following steps to conduct the site feasibility study: a) Select the type of prime mover or cycle (piston engine, gas turbine or steam turbine); b) Determine the total installed capacity; c) Determine the size and number of prime movers; d) Determine the required standby capacity. According to its authors “the approach taken (in the manual) is to develop the minimal amount of information required for the feasibility analysis, deferring more rigorous and comprehensive analyses to the actual concept study.” The approach includes the discussion of the following “Design Options” or design criteria to determine (1) the size and (2) the operation mode of the CHP system. Isolated Operation, Electric Load Following—The facility is independent of the electric utility grid, and is required to produce all power required on-site and to provide all required reserves for scheduled and un- scheduled maintenance. Baseloaded, Electrically Sized—The facility is sized for baseloaded operation based on the minimum historic billing demand. Supplemental power is purchased from the utility grid. This facility concept generally results in a shorter payback period than that from the isolated site. Baseloaded, Thermally Sized—The facility is sized to provide most of the site’s required thermal energy using recovered heat. The engines operated to follow the thermal demand with supplemental boiler fi red as required. The authors point out that: “this option frequently results in the production of more power than is required on-site and this power is sold to the electric utility.” In addition, the AGA manual includes a descrip- tion of sources of information or processes by which background data can be developed for the specifi c gas distribution service area. Such information can be used to adapt the feasibility screening procedures to a specifi c utility. 7.2.4.3 Cogeneration System Selection and Sizing. The selection of a set of “candidate” cogeneration systems entails to tentatively specify the most appro- priate prime mover technology, which will be further evaluated in the course of the study. Often, two or more alternative systems that meet the technical requirements are pre-selected for further evaluation. For instance, a plant’s CHP requirements can be met by either, a recip- rocating engine system or combustion turbine system. Thus, the two system technologies are pre-selected for a more detailed economic analysis. To evaluate specifi c technologies, there exist a vast number of technology-specifi c manuals and references. A representative sample is listed as follows. Mackay (1983) has developed a manual titled “Gas Turbine Cogeneration: Design, Evaluation and Installation.” Ko- vacik (1984) reviews application considerations for both steam turbine and gas turbine cogeneration systems. Limaye (1987) has compiled several case studies on industrial cogeneration applications. Hay (1988) discusses technical and economic considerations for cogeneration application of gas engines, gas turbines, steam engines and packaged systems. Keklhofer (1991) has written a treatise on technical and economic analysis of combined- cycle gas and steam turbine power plants. Ganapathy (1991) has produced a manual on waste heat boilers. Usually, system selection is assumed to be separate from sizing the cogeneration equipment (kWe). How- ever, since performance, reliability and cost are very dependent on equipment size and number, technology selection and system size are very intertwined evaluation factors. In addition to the system design criteria given by the AGA manual, several approaches for co- COGENERATION AND DISTRIBUTED GENERATION 173 generation system selection and/or sizing are discussed as follows. Heat-to-Power Ratio Canton et al (1987) of The Combustion and Fuels Research Group at Texas A&M University has developed a methodology to select a cogeneration system for a given industrial application using the heat to power ratio (HPR). The methodology includes a series of graphs used 1) to defi ne the load HPR and 2) to compare and match the load HPR to the HPRs of existing equipment. Consideration is then given to either, heat or power load matching and modulation. Sizing Procedures Hay (1987) considers the use of the load duration curve to model variable thermal and electrical loads in system sizing, along with four different scenarios described in Figure 7.14. Each one of these scenarios defi nes an operating alternative associated to a system size. Oven (1991) discusses the use of the load duration curve to model variable thermal and electrical loads in system sizing in conjunction with required thermal and electrical load factors. Given the thermal load duration and electrical load duration curves for a particular facility, different sizing alternatives can be defi ned for various load factors. Eastey et al. (1984) discusses a model (CO- GENOPT) for sizing cogeneration systems. The basic inputs to the model are a set of thermal and electric profi les, the cost of fuels and electricity, equipment cost and performance for a particular technology. The model calculates the operating costs and the number of units for different system sizes. Then it estimates the net present value for each one of them. Based on the maximum net present value, the “optimum” system is selected. The model includes cost and load escalation. Wong, Ganesh and Turner (1991) have developed two statistical computer models to optimize cogeneration system size subject to varying capacities/loads and Figure 7-14. Each operation mode defi nes a sizing alternative. Source: Hay (1987). 174 ENERGY MANAGEMENT HANDBOOK to meet an availability requirement. One model is for internal combustion engines and the other for unfi red gas turbine cogeneration systems. Once the user defi nes a required availability, the models determine the system size or capacity that meets the required availability and maxi- mizes the expected annual worth of its life cycle cost. 7.3 COMPUTER PROGRAMS There are several computer programs-mainly PC based-available for detailed evaluation of cogeneration systems. In opposition to the rather simple methods discussed above, CHP programs are intended for system confi guration or detailed design and analysis. For these reasons, they require a vast amount of input data. Below, we examine two of the most well known programs. 7.3.1 CELCAP Lee (1988) reports that the Naval Civil Engineer- ing Laboratory developed a cogeneration analysis computer program known as Civil Engineering Laboratory Cogeneration Program (CELCAP), “for the purpose of evaluating the performance of cogeneration systems on a lifecycle operating cost basis.” He states that “selection of a cogeneration energy system for a specifi c application is a complex task.” He points out that the fi rst step in the selection of cogeneration system is to make a list of potential candidates. These candidates should include single or multiple combinations of the various types of engine available. The computer program does not specify CHP systems; these must be selected by the designer. Thus, depending on the training and previous experience of the designer, different designers may select different systems of different sizes. After selecting a short-list of candidates, modes of operations are defi ned for the candidates. So, if there are N candidates and M modes of operation, then NxM alternatives must be evaluated. Lee considers three modes of operation: 1) Prime movers operating at their full-rated capacity, any excess electricity is sold to the utility and any excess heat is rejected to the environment. Any electricity shortage is made up with imports. Pro- cess steam shortages are made-up by an auxiliary boiler. 2) Prime movers are specified to always meet the entire electrical load of the user. Steam or heat demand is met by the prime mover. An auxiliary boiler is fi red to meet any excess heat defi cit and excess heat is rejected to the environment. 3) Prime movers are operated to just meet the steam or heat load. In this mode, power defi cits are made up by purchased electricity. Similarly, any excess power is sold back to the utility. For load analysis, Lee considers that “demand of the user is continuously changing. This requires that data on the electrical and thermal demands of the user be available for at least one year.” He further states that “electrical and heat demands of a user vary during the year because of the changing working and weather conditions.” However, for evaluation purposes, he assumes that the working conditions of the user-production related CHP load-remain constant and “that the energy-demand pat- tern does not change signifi cantly from year to year.” Thus, to consider working condition variations, Lee classifi es the days of the year as working and non-working days. Then, he uses “average” monthly load profi les and “typical” 24-hour load profi les for each class. “Average” load profi les are based on electric and steam consumption for an average weather condition at the site. A load profi le is developed for each month, thus monthly weather and consumption data is required. A best fi t of consumption (Btu/month or kWh/month) versus heating and cooling degree days is thus obtained. Then, actual hourly load profi les for working and non- working days for each month of the year are developed. The “best representative” profi le is then chosen for the “typical working day” of the month. A similar procedure is done for the non-working days. Next an energy balance or reconciliation is performed to make sure the consumption of the hourly load profi les agrees with the monthly energy usage. A multiplying factor K is defi ned to adjust load profi les that do not balance. K j = E mj /(AE wj + AE nwj ) (7.9) where K j = multiplying factor for month j E mj = average consumption (kWh) by the user for the month j selected from the monthly electricity usage versus degree day plot AE wj = typical working-day electric usage (kWh), i.e. the area under the typical working day electric demand profi le for the month j AE nwj = typical non-working day usage (kWh), i.e. the area under the typical non-working day electric demand profi le for the month j. Lee suggests that each hourly load in the load profi les be multiplied by the K factor to obtain the “cor- COGENERATION AND DISTRIBUTED GENERATION 175 rect working and non-working day load profi les for the month.” The procedure is repeated for all months of the year for both electric and steam demands. Lee states that “the resulting load profi les represent the load demand for average weather conditions.” Once a number of candidate CHP systems has been selected, equipment performance data and the load profi les are fed into CELCAP to produce the required output. The output can be obtained in a brief or detailed form. In brief form, the output consists of a summary of input data and a life cycle cost analysis including fuel, operation and maintenance and purchased power costs. The detailed printout includes all the information of the brief printout, plus hourly performance data for 2 days in each month of the year. It also includes the maximum hourly CHP output and fuel consumption. The hourly electric demand and supply are plotted, along with the hourly steam demand and supply for each month of the year. Despite the simplifying assumptions introduced by Lee to generate average monthly and typical daily load profi les, it is evident that still a large amount of data handling and preparation is required before CELCAP is run. By recognizing the fact that CHP loads vary over time, he implicitly justifi es the amount of effort in representing the input data through hourly profi les for typical working and non-working days of the month. If a change occurs in the products, process or equipment that constitute the energy consumers within the industrial plant, a new set of load profi les must be generated. Thus, exploring different conditions requires sensitivity analyses or parametric studies for off-design conditions. A problem that becomes evident at this point is that, to accurately represent varying loads, a large number of load data points must be estimated for sub- sequent use in the computer program. Conversely, the preliminary feasibility evaluation methods discussed previously, require very few and only “average” load data. However, criticism of preliminary methods has arisen for not being able to truly refl ect seasonal variations in load analysis (and economic analysis) and for lacking the fl exibility to represent varying CHP system performance at varying loads. 7.3.2 COGENMASTER Limaye and Balakrishnan (1989) of Synergic Re- sources Corporation have developed COGENMASTER. It is a computer program to model the technical aspects of alternative cogeneration systems and options, evaluate economic feasibility, and prepare detailed cash fl ow statements. COGENMASTER compares the CHP alternatives to a base case system where electricity is purchased from the utility and thermal energy is generated at the site. They extend the concept of an option by referring not only to different technologies and operating strategies but also to different ownership structures and fi nancing arrangements. The program has two main sections: a Technology and a Financial Section. The technology Section includes 5 modules: • Technology Database Module • Rates Module • Load Module • Sizing Module • Operating Module The Financial Section includes 3 modules: • Financing Module • Cash Flow Module • Pricing Module In COGENMASTER, facility electric and thermal loads may be entered in one of three ways, depending on the available data and the detail required for project evaluation: — A constant average load for every hour of the year. — Hourly data for three typical days of the year — Hourly data for three typical days of each month Thermal loads may be in the form of hot water or steam; but system outlet conditions must be specifi ed by the user. The sizing and operating modules permit a variety of alternatives and combinations to be considered. The system may be sized for the base or peak, summer or winter, and electric or thermal load. There is also an option for the user to defi ne the size the system in kilowatts. Once the system size is defi ned, several operation modes may be selected. The system may be operated in the electric following, thermal following or constantly running modes of operation. Thus, N sizing options and M operations modes defi ne a total of NxM cogeneration alternatives, from which the “best” alternative must be selected. The economic analysis is based on simple payback estimates for the CHP candidates versus a base case or do-nothing scenario. Next, depending on the fi nancing options available, different cash fl ows may be defi ned and further economic analysis-based 176 ENERGY MANAGEMENT HANDBOOK on the Net Present Value of the alternatives—may be performed. 7.4 U.S. COGENERATION LEGISLATION: PURPA In 1978 the U.S. Congress amended the Federal Power Act by promulgation of the Public Utilities Regulatory Act (PURPA). The Act recognized the energy saving potential of industrial cogeneration and small power plants, the need for real and signifi cant incentives for development of these facilities and the private sector requirement to remain unregulated. PURPA of 1978 eliminated several obstacles to cogeneration so cogenerators can count on “fair” treat- ment by the local electric utility with regard to intercon- nection, back-up power supplies, and the sale of excess power. PURPA contains the major federal initiatives regarding cogeneration and small power production. These initiatives are stated as rules and regulations pertaining to PURPA Sections 210 and 201; which were issued in fi nal form in February and March of 1980, respectively. These rules and regulations are discussed in the following sections. Initially, several utilities—especially those with excess capacity-were reticent to buy cogenerated power and have, in the past, contested PURPA. Power (1980) magazine reported several cases in which opposition persisted in some utilities to private cogeneration. But after the Supreme Court ruling in favor of PURPA, more and more utilities are fi nding that PURPA can work to their advantage. Polsky and Landry (1987) report that some utilities are changing attitudes and are even invest- ing in cogeneration projects. 7.4.1 PURPA 201* Section 201 of PURPA requires the Federal Energy Regulatory Commission (FERC) to defi ne the criteria and procedures by which small power producers (SPPs) and cogeneration facilities can obtain qualifying status to receive the rate benefi ts and exemptions set forth in Section 210 of PURPA. Some PURPA 201 defi nitions are stated below. Small Power Production Facility A “Small Power Production Facility” is a facility that uses biomass, waste, or renewable resources, including wind, solar and water, to produce electric power and is not greater than 80 megawatts. Facilities less than 30 MW are exempt from the Public Utility Holding Co. Act and certain state law and regulation. Plants of 30 to 80 MW which use biomass, may be exempted from the above but may not be exempted from certain sections of the Federal Power Act. Cogeneration Facility A “Cogeneration Facility” is a facility which pro- duces electric energy and forms of useful thermal energy (such as heat or steam) used for industrial, commercial, heating or cooling purposes, through the sequential use of energy. A Qualifying Facility (QF) must meet certain minimum effi ciency standards as described later. Co- generation facilities are generally classifi ed as “topping” cycle or “bottoming” cycle facilities. 7.4.2 Qualifi cation of a “Cogeneration Facility” or a “Small Power Production Facility” under PURPA Cogeneration Facilities To distinguish new cogeneration facilities which will achieve meaningful energy conservation from those which would be “token” facilities producing trivial amounts of either useful heat or power, the FERC rules establish operating and effi ciency standards for both topping-cycle and bottom-cycle NEW cogeneration facilities. No effi ciency standards are required for EXISTING cogeneration facilities regardless of energy source or type of facility. The following fuel utilization effectiveness (FUE) values—based on the lower heating value (LHV) of the fuel—are required from QFs. • For a new topping-cycle facility: — No less than 5% of the total annual energy output of the facility must be useful thermal energy. • For any new topping-cycle facility that uses any natural gas or oil: — All the useful electric power and half the useful thermal energy must equal at least 42.5% of the total annual natural gas and oil energy input; and — If the useful thermal output of a facility is less than 15% of the total energy output of the facility, the useful power output plus one-half the useful thermal energy output must be no less than 45% of the total energy input of natural gas and oil for the calendar. *Most of the following sections have been adapted from CFR18 (1990) and Harkins (1980), unless quoted otherwise. COGENERATION AND DISTRIBUTED GENERATION 177 For a new bottoming-cycle facility: • If supplementary fi ring (heating of water or steam before entering the electricity generation cycle from the thermal energy cycle) is done with oil or gas, the useful power output of the bottoming cycle must, during any calendar year, be no less than 45% of the energy input of natural gas and oil for supplementary fi ring. Small Power Production Facilities To qualify as a small power production facility under PURPA, the facility must have production capacity of under 80 MW and must get more than 50% of its total energy input from biomass, waste, or renewable resources. Also, use of oil, coal, or natural gas by the facility may not exceed 25% of total annual energy input to the facility. Ownership Rules Applying to Cogeneration and Small Power Producers A qualifying facility may not have more than 50% of the equal interest in the facility held by an electric utility. 7.4.3 PURPA 210 Section 210 of PURPA directs the Federal Energy Regulatory Commission (FERC) to establish the rules and regulations requiring electric utilities to purchase electric power from and sell electric power to qualifying cogeneration and small power production facilities and provide for the exemption to qualifying facilities (QF) from certain federal and state regulations. Thus, FERC issued in 1980 a series of rules to relax obstacles to cogeneration. Such rules implement sections of the 1978 PURPA and include detailed instructions to state utility commissions that all utilities must purchase electricity from cogenerators and small power producers at the utilities’ “avoided” cost. In a nutshell, this means that rates paid by utilities for such electricity must refl ect the cost savings they realize by being able to avoid capacity additions and fuel usage of their own. Tuttle (1980) states that prior to PURPA 210, cogeneration facilities wishing to sell their power were faced with three major obstacles: • Utilities had no obligation to purchase power, and contended that cogeneration facilities were too small and unreliable. As a result, even those cogenerators able to sell power had diffi culty getting an equitable price. • Utility rates for backup power were high and often discriminatory • Cogenerators often were subject to the same strict state and federal regulations as the utility. PURPA was designed to remove these obstacles, by requiring utilities to develop an equitable program of integrating cogenerated power into their loads. Avoided Costs The costs avoided by a utility when a cogeneration plant displaces generation capacity and/or fuel usage are the basis to set the rates paid by utilities for cogenerated power sold back to the utility grid. In some circumstances, the actual rates may be higher or lower than the avoided costs, depending on the need of the utility for additional power and on the outcomes of the negotiations between the parties involved in the cogeneration development process. All utilities are now required by PURPA to provide data regarding present and future electricity costs on a cent-per-kWh basis during daily, seasonal, peak and off- peak periods for the next fi ve years. This information must also include estimates on planned utility capacity additions and retirements, and cost of new capacity and energy costs. Tuttle (1980) points out that utilities may agree to pay greater price for power if a cogeneration facility can: • Furnish information on demonstrated reliability and term of commitment. • Allow the utility to regulate the power production for better control of its load and demand changes. • Schedule maintenance outages for low-demand periods. • Provide energy during utility-system daily and seasonal peaks and emergencies. • Reduce in-house on-site load usage during emergencies. • Avoid line losses the utility otherwise would have incurred. In conclusion, a utility is willing to pay better “buyback” rates for cogenerated power if it is short in capacity, if it can exercise a level of control on the CHP plant and load, and if the cogenerator can provide and/ or demonstrate a “high” system availability. 178 ENERGY MANAGEMENT HANDBOOK PURPA further states that the utility is not obligat- ed to purchase electricity from a QF during periods that would result in net increases in its operating costs. Thus, low demand periods must be identifi ed by the utility and the cogenerator must be notifi ed in advance. Dur- ing emergencies (utility outages), the QF is not required to provide more power than its contract requires, but a utility has the right to discontinue power purchases if they contribute to the outage. 7.4.4 Other Regulations Several U.S. regulations are related to cogeneration. For example, among environmental regulations, the Clean Air Act may control emissions from a waste- to-energy power plant. Another example is the regulation of underground storage tanks by the Resource Conservation and Recovery Act (RCRA). This applies to all those cogenerators that store liquid fuels in underground tanks. Thus, to maximize benefi ts and to avoid costly penalties, cogeneration planners and developers should become savvy in related environmental mat- ters. There are many other issues that affect the development and operation of a cogeneration project. For further study, the reader is referred to a variety of sources such proceedings from the various World En- ergy Engineering Congresses organized by the Associa- tion of Energy Engineers (Atlanta, GA). Other sources include a general compendium of cogeneration planning considerations given by Orlando (1990), and a manual- developed by Spiewak (1994)—which emphasizes the regulatory, contracting and fi nancing issues of cogeneration. 7.5 EVALUATING COGENERATION OPPORTUNITIES: CASE EXAMPLES The feasibility evaluation of cogeneration opportunities for both, new construction and facility retrofi t, require the comparison and ranking of various options using a fi gure of economic merit. The options are usually combinations of different CHP technologies, operating modes and equipment sizes. A fi rst step in the evaluation is the determination of the costs of a base-case (or do-nothing) scenario. For new facilities, buying thermal and electrical energy from utility companies is traditionally considered the base case. For retrofi ts, the present way to buy and/or generate energy is the base case. For many, the base-case scenario is the “actual plant situation” after “basic” energy conservation and management measures have been implemented. That is, cogeneration should be evaluated upon an “effi cient” base case plant. Next, suitable cogeneration alternatives are generated using the methods discussed in sections 7.2 and 7.3. Then, the comparison and ranking of the base case versus the alternative cases is performed using an economic analysis. Henceforth, this section addresses a basic approach for the economic analysis of cogeneration. Specifi cally, it discusses the development of the cash fl ows for each option including the base case. It also discusses some fi gures of merit such as the gross pay out period (simple payback) and the discounted or internal rate of return. Finally, it describes two case examples of evaluations in industrial plants. The examples are included for illustra- tive purposes and do not necessarily refl ect the latest available performance levels or capital costs. 7.5.1 General Considerations A detailed treatise on engineering economy is presented in Chapter 4. Even so, since economic evaluations play the key role in determining whether cogeneration can be justifi ed, a brief discussion of economic considerations and several evaluation techniques follows. The economic evaluations are based on examining the incremental increase in the investment cost for the alternative being considered relative to the alternative to which it is being compared and determining whether the savings in annual operating cost justify the increased investment. The parameter used to evaluate the economic merit may be a relatively simple parameter such as the “gross payout period.” Or one might use more sophisticated techniques which include the time value of money, such as the “discounted rate of return,” on the discretionary investment for the cogeneration systems being evaluated. Investment cost and operating cost are the expen- diture categories involved in an economic evaluation. Operating costs result from the operations of equipment, such as (1) purchased fuel, (2) purchased power, (3) purchased water, (4) operating labor, (5) chemicals, and (6) maintenance. Investment-associated costs are of primary importance when factoring the impact of federal and state income taxes into the economic evaluation. These costs (or credits) include (1) investment tax credits, (2) depreciation, (3) local property taxes, and (4) insurance. The economic evaluation establishes whether the operating and investment cost factors result in suffi cient after-tax income to provide the company stockholders an adequate rate of return after the debt obligations with regard to the investment have been satisfi ed. When one has many alternatives to evaluate, the COGENERATION AND DISTRIBUTED GENERATION 179 less sophisticated techniques, such as “gross payout,” can provide an easy method for quickly ranking alternatives and eliminating alternatives that may be particularly unattractive. However, these techniques are applicable only if annual operating costs do not change signifi cantly with time and additional investments do not have to be made during the study period. The techniques that include the time value of money permit evaluations where annual savings can change signifi cantly each year. Also, these evaluation procedures permit additional investments at any time during the study period. Thus these techniques truly refl ect the profi tability of a cogeneration investment or investments. 7.5.2 Cogeneration Evaluation Case Examples The following examples illustrate evaluation procedures used for cogeneration studies. Both examples are based on 1980 investment costs for facilities located in the U.S. Gulf Coast area. For simplicity, the economic merit of each alternative examined is expressed as the “gross payout period” (GPO). The GPO is equal to the incremental investment for cogeneration divided by the resulting fi rst-year annual operating cost savings. The GPO can be converted to a “discounted rate of return” (DRR) using Figure 7.15. However, this curve is valid only for evaluations involv- ing a single investment with fi xed annual operating cost savings with time. In most instances, the annual savings due to cogeneration will increase as fuel costs increase to both utilities and industries in the years ahead. These increased future savings enhance the economics of cogeneration. For example, if we assume that a project has a GPO of three years based on the fi rst-year operating cost savings, Figure 7.15 shows a DRR of 18.7%. However, if the savings due to cogeneration increase 10% annually for the fi rst three operating years of the project and are constant thereafter, the DRR increases to 21.6%; if the savings increase 10% annually for the fi rst six years, the DRR would be 24.5%; and if the 10% increase was experienced for the fi rst 10 years, the DRR would be 26.6%. Example 6: The energy requirements for a large industrial plant are given in Table 7.3. The alternatives considered include: Base case. Three half-size coal-fi red process boilers are installed to supply steam to the plant’s 250-psig steam header. All 80-psig steam and steam to the 20-psig deaerating heater is pressure-reduced from the 250-psig steam header. The powerhouse auxiliary power requirements are 3.2 MW. Thus the utility tie must provide 33.2 MW to satisfy the average plant electric power needs. Case 1. This alternative is based on installation of a noncondensing steam turbine generator. The unit initial Table 7.3 Plant Energy Supply System Considerations: Example 6 ——————————————————————————————————————————————————— Process steam demands Net heat to process at 250 psig. 410°F—317 million Btu/hr avg. Net heat to process at 80 psig, 330°F—208 million Btu/hr avg. (peak requirements are 10% greater than average values) Process condensate returns: 50% of steam delivered at 280°F Makeup water at 80°F Plant fuel is 3.5% sulfur coal Coal and limestone for SO 2 scrubbing are available at a total cost of $2/million Btu fi red Process area power requirement is 30 MW avg. Purchased power cost is 3.5 cents/kWh ——————————————————————————————————————————————————— Fig. 7.15 Discounted rate of return versus gross payout period. Basis: (1) depreciation period, 28 years; (2) sum- of-the-years’-digits depreciation; (3) economic life, 28 years; (4) constant annual savings with time; (5) local property taxes and insurance, 4% of investment cost; (6) state and federal income taxes, 53%; (7) investment tax credit, 10% of investment cost. 180 ENERGY MANAGEMENT HANDBOOK steam conditions are 1450 psig, 950°F with automatic extraction at 250 psig and 80 psig exhaust pressure. The boiler plant has three half-size units providing the same reliability of steam supply as the Base Case. The feedwater heating system has closed feedwater heat- ers at 250 psig and 80 psig with a 20 psig deaerating heater. The 20-psig steam is supplied by noncondensing mechanical drive turbines used as powerhouse auxiliary drives. These units are supplied throttle steam from the 250-psig steam header. For this alternative, the utility tie normally provides 4.95 MW. The simplifi ed schematic and energy balance is given in Figure 7.16. The results of this cogeneration example are tabu- lated in Table 7.4. Included are the annual energy requirements, the 1980 investment costs for each case, and the annual operating cost summary. The investment cost data presented are for fully operational plants, including offi ces, stockrooms, machine shop facilities, locker rooms, as well as fi re protection and plant security. The cost of land is not included. The incremental investment cost for Case 1 given in Table 7.4 is $17.2 million. Thus the incremental cost is $609/kW for the 28.25-MW cogeneration system. This il- lustrates the favorable per unit cost for cogeneration systems compared to coal-fi red facilities designed to provide kilowatts only, which cost in excess of $1000/kW. The impact of fuel and purchased power costs other than Table 7.3 values on the GPO for this example is shown in Figure 7.17. Equivalent DRR values based on fi rst-year annual operating cost savings can be estimated using Figure 7.15. Sensitivity analyses often evaluate the impact of uncertainties in the installed cost estimates on the profi tability of a project. If the incremental investment cost for cogeneration is 10% greater than the Table 7.4 estimate, the GPO would increase from 3.2 to 3.5 years. Thus the DRR would decrease from 17.5% to about 16%, as shown in Figure 7.15. Table 7.4 Energy and Economic Summary: Example 6 ——————————————————————————————————————————————————— Alternative Base Case Case 1 ——————————————————————————————————————————————————— Energy summary Boiler fuel (10 6 Btu/hr HHV) 599 714 Purchased power (MW) 33.20 4.95 Estimated total installed cost (10 6 $) 57.6 74.8 Annual operating costs (10 6 $) Fuel and limestone at $2/10 6 Btu 10.1 12.0 Purchased power at 3.5 cents/kWh 9.8 1.5 Operating labor 0.8 1.1 Maintenance 1.4 1.9 Makeup water 0.3 0.5 Total 22.4 17.0 Annual savings (10 6 $) Base 5.4 Gross payout period (yrs) Base 3.2 ——————————————————————————————————————————————————— Basis: (1) boiler effi ciency is 87%; (2) operation equivalent to 8400 hr/yr at Table 7-3 conditions; (3) maintenance is 2.5% of the estimated total installed cost; (4) makeup water cost for case 1 is 80 cents/1000 gal greater than Base Case water costs; (5) stack gas scrubbing based on limestone system. ——————————————————————————————————————————————————— Fig. 7.16 Simplified schematic and energy-balance diagram: Example 6, Case 1. All numbers are fl ows in 10 3 lb/hr; Plant requirements given in Table 7.8, gross generation, 30.23 MW; powerhouse auxiliaries, 5.18 MW; net generation, 25.05 MW. COGENERATION AND DISTRIBUTED GENERATION 181 Example 7: The energy requirements for a chemical plant are presented in Table 7.5. The alternatives considered include: Base case. Three half-size oil-fi red packaged process boilers are installed to supply process steam at 150 psig. Each unit is fuel-oil-fi red and includes a particulate removal system. The plant has a 60-day fuel-oil-storage capacity. A utility tie provides 30.33 MW average to supply process and boiler plant auxiliary power requirements. Case 1. (Refer to Figure 7.18). This alternative examines the merit of adding a noncondensing steam turbine generator with 850 psig, 825°F initial steam conditions, 150-psig exhaust pressure. Steam is supplied by three half-size packaged boilers. The feedwater heating system is comprised of a 150-psig closed heater and a 20-psig deaerating heater. The steam for the deaerating heater is the exhaust of a mechanical drive turbine (MDT). The MDT is supplied 150-psig steam and drives Table 7.5 Plant Energy Supply System Considerations: Example 7 ————————————————————————— Process steam demands Net heat to process at 150 psig sat—158.5 million Btu/hr avg. (peak steam requirements are 10% greater than average values) Process condensate returns: 45% of the steam delivered at 300°F Makeup water at 80°F Plant fuel is fuel oil Fuel cost is $5/million Btu Process areas require 30 MW Purchased power cost is 5 cents/kWh ————————————————————————— some of the plant boiler feed pumps. The net generation of this cogeneration system is 6.32 MW when operating at the average 150-psig process heat demand. A utility tie provides the balance of the power required. Case 2. (Refer to Figure 7.19). This alternative is a combined cycle using the 25,000-kW gas turbine generator whose performance is given in Table 7.7. An unfi red HRSG system provides steam at both 850 psig, 825°F and 150 psig sat. Plant steam requirements in excess of that available from the two-pressure level unfi red HRSG system are generated in an oil fi red packaged boiler. The steam supplied to the noncondensing turbine is expanded to the 150-psig steam header. The net generation from the overall system is 26.54 MW. A utility tie provides power requirements in excess of that supplied by the cogeneration system. The plant-installed cost estimates for Case 2 include two half-size package boilers. Thus full steam output can be realized with any steam generator out of service for maintenance. The energy summary, annual operating costs, and economic results are presented in Table 7.6. The results show that the combined cycle provides a GPO of 2.5 years based on the study fuel and purchased power costs. The incremental cost for Case 2 relative to the Base Case is $395/kW compared to $655/kW for Case 1 relative to the Base Case. This favorable incremental investment cost combined with a FCP of 5510 Btu/kWh contribute to the low CPO. The infl uence of fuel and power costs other than those given in Table 7.5 on the GPO for cases 1 and 2 is Fig. 7.17 Effect of different fuel and power costs on cogeneration profi tability: Example 1. Basis: Condi- tions given in Tables 7.3 and 7.4. Fig. 7.18 Simplified schematic and energy-balance diagram: Example 7, Case 1. All numbers are fl ows in 1000 lb/hr; gross generation, 6.82 MW; powerhouse auxiliaries, 0.50 MW; net generation; 6.32 MW. [...]... Expansion Temperature Melting Point (per °F) (°F) (°F) 8 × 10–6 9 × 10–6 13 × 10–6 3 × 10–6 8 × 10–6 7 × 10–6 10 × 10–6 11 × 10–6 10 × 10–6 5 × 10–6 7 × 10–6 3 × 10–6 7 × 10–6 8 × 10–6 5 × 10–6 4 × 10–6 33 00 4000 4200 4000 32 00 32 00 30 00 4000 35 00 30 00 2800 30 00 33 00 30 00 35 00 4400 37 00 4600 4700 6500c 38 00 — 33 00 5000 5000 33 50 31 00 4000d — 33 00 4500 4800 of these materials are available commercially as refractory... Al2O3 BeO CaO C 40% Cr2O3 90% Al2O3 2 MgO SiO2 MgO MgO 3 Al2O3 SiO2 SiO2 SiC MgO Al2O3 TiO2 ZrO2 SiO2 ZrO2 aMost Density (lbm/ft3) 230 190 200 120 200 200 160 210 175 160 110 170 220 260 220 36 0 Mean Thermal Conductivity Specific Heat (Btu/ft hr °F) (Btu/lbm) (to 1000°) 0.24 0.24 0.18 0 .36 0.20 0.22 0. 23 0.25 0.25 0. 23 0.24 0. 23 0. 23 0.17 0.15 0. 13 2.0 — 4.5 7 1.0 1.5 1.2 2 .3 2.0 1.2 1.0 8 5 2.2 1 .3 1 .3. .. ——————————————————————————————————————————————————— Energy summary Fuel (106 Btu/hr HHV) Boiler 1 83 209 34 Gas turbine — 297 Total 1 83 209 33 1 Purchased power (MW) 30 .33 23. 77 3. 48 Estimated total installed cost (106 $) 8 .3 12.6 18.9 Annual operating cost (106 $) Fuel at $5/M Btu HHV 7.7 8.8 13. 9 Purchased power at 5 cents/kWh 12.7 10.0 1.5 Operating labor 0.6 0.9 0.9 Maintenance 0.2 0 .3 0.5 Makeup water 0.1 0.2 0.2 Total 21 .3 20.2 17.0... °F (2000 – 60) °F = 34 .9 × 106 Btu/hr = (265.8 – 415.9 – 6 .3 + 34 .9 – 0.5 + 39 .3 Flow path 2 is the cooling-water flow for the conveyor H CW in = gpm × 60 min/hr × 8 .33 lb/gal × 1 Btu/lb • °F × TCW.in = 600 gpm × 60 min/hr × 8 .33 lb/gal × 1 Btu/lb • °F (100 – 60) °F = 12.0 × 106 Btu/hr H CW out = gpm × 60 min/hr × 8 .33 lb/gal × 1 Btu/lb • °F × TCW.out = 600 gpm × 60 min/hr × 8 .33 lb/gal × 1 Btu/lb •... 64 191 36 ,000 gph 39 ,30 0,000 9 2000 50 tons/hr 34 ,900,000 8 WASTE-HEAT RECOVERY 207 different The annual heat recovery for each fuel was assumed to be proportional to the total consumption of each fuel, so that the heat recovered was found as heat recovered 3 ft 3gas = 1 .39 × 10 9 yr × 12.95 ft3 air ft gas gal × 24.6 – 1.2 Btu + 4. 43 × 10 6 yr 3 ft 3 × 2040.8 ft air × 24.6 – 1.2 Btu gal oil ft 3 = 4.2... 22.65 + 85.4 ft3air — = —————— = —————— = 13. 0 ——— F volume of fuel 8 .3 ft3 gas H comb air = A × fuel firing rate × h' air F h’air at 100°F is found to be 1.2 Btu/ft3 3 H comb.air = 13. 0 × 4 03. 8 10 × 1.2 = 6 .3 × 10 6 Btu/hr The specific enthalpy of each of the flue-gas components at 2200°F is found from Figure 8.10 to be h'CO2 = 69 .3 Btu/scf h'O2 = 45.4 Btu/scf h'CO = 44.1 Btu/scf h'N2 = 43. 4 Btu/scf h'H2O... Btu/scf h'N2 = 43. 4 Btu/scf h'H2O = 54.7 Btu/scf H stack gas = fuel firing rate Q co 2 × h' co 2 + QO2 × h'O2 + QCO × h'COQN × h'N2 + Q2O × h'H2O = 4 03. 8 × 10 3 7.8 × 69 .3 + 6 .3 ×45.4 8 .3 8 .3 + 0.5 × 44.1 + 85.4 × 43. 4 + 2 × 8 .3 × 54.7 Btu/hr 8 .3 8 .3 8 .3 = 265.8 × 10 6Btu/hr Because each fuel has its own chemical composition, the stack-gas composition will be different for each fuel, as will the enthalpy... NA 21.6 21.4 ® 922 190 925 769 Steam (1 03 lb/hr) Steam conditions 250 psig sat 400 psig, 650°F 600 psig, 750°F 850 psig, 825°F 1250 psig, 900°F 1450 psig, 950°F FCP (Btu/kWh HHV) Steam (1 03 lb/hr) FCP (Btu/kWh HHV) Steam (1 03 lb/hr) FCP (Btu/kWh HHV) 133 110 101 93 — — 6560 7020 734 0 7650 — — 31 7 279 268 261 254 250 5620 5 630 5660 5700 5750 5750 851 751 722 7 03 687 675 4010 † ———————————————————————————————————————————————————... hypothetical furnace as follows: H f fuel energy rate = firing rate × HHV (8.12) where HHV is the higher heating value of the fuel n Btu/ft3 or Btu/gal H f 1 = 4 03. 8 × 10 3ft 3/ hr × 1 030 Btu/ft 3 = 415.9 × 106Btu/hr Because this is a dual-fuel installation, we can also construct a second heat-balance diagram for the alternative fuel: H f 2 = 31 62.6 gph × 131 ,500 Btu/gal = 415.9 × 106Btu/hr Writing... air/fuel ratio is maintained constant, then Qstack/gas/Qcomb.air remains almost constant; then equation 8.14 can be written This is an energy savings of 6 .3 × 1011 —————————————————— 1 .39 × 109 × 1 030 + 4. 43 × 106 × 131 ,500 = 0 .31 or 31 % The predicted cost savings is $1 ,30 8,900 for natural gas 950,200 for No 2 fuel oil —————————————— $2,259,100 total h'comb air, out – h'comb air, in Qstack gas ———— = . 2 ——————————————————————————————————————————————————— Energy summary Fuel (10 6 Btu/hr HHV) Boiler 1 83 209 34 Gas turbine — 297 Total 1 83 209 33 1 Purchased power (MW) 30 .33 23. 77 3. 48 Estimated total installed cost (10 6 $) 8 .3 12.6. conditions 250 psig sat. 133 6560 31 7 5620 851 4010 400 psig, 650°F 110 7020 279 5 630 751 600 psig, 750°F 101 734 0 268 5660 722 850 psig, 825°F 93 7650 261 5700 7 03 1250 psig, 900°F — — 254. Simplified schematic and energy- balance diagram: Example 6, Case 1. All numbers are fl ows in 10 3 lb/hr; Plant requirements given in Table 7.8, gross generation, 30 . 23 MW; powerhouse auxiliaries,