Energy Vol. 21, No. 12, pp. 1169-1178, 1996 Copyright © 1996 Elsevier Science Ltd

Pergamon PII: S0360-5442(96)00065-5 Printed in Great Britain. All rights reserved 0360-5442/96 $15.00 + 0.00

INDUSTRIAL ENERGY EFFICIENCY IMPROVEMENT THROUGH COGENERATION: A CASE STUDY OF THE TEXTILE INDUSTRY

IN THAILAND

O. TANG and B. MOHANTY* Energy Program, School of Environment, Resources and Development, Asian Institute of Technology, P.O.

Box 2754, Bangkok 10501, Thailand

(Received 23 February 1996)

Abstract--Natural gas cogeneration presently appears to be a promising alternative to satisfy the energy utility requirement of the process industries thanks to the favorable energy policy of the Government of Thailand. In this paper, we detail a case study in a textile factory where use of gas-turbine cogeneration with a post-combustion heat recovery system is found to be the most suitable solution. This system has not only the highest thermal efficiency, but it can also provide flexibility in operation. Financial analysis of the most suitable cogeneration configuration provides the net present value (NPV), pay-back period (PBP) and internal rate of return (IRR) with values of 310 million Baht, 5.3 years and 26.6%, respectively. The thermal-matching option is not found to be attractive because the sale price of electricity to the state electric utility is not high enough to absorb the additional investment required for the prime mover. Incorporation of an absorption chiller in the cogeneration system does not bring in any additional advantage as there is no excess waste heat available in this factory. Copyright © 1996 Elsevier Science Ltd.

1. INTRODUCTION

According to the Department of Energy Development and Promotion (DEDP) of Thailand, the industry sector is a major electricity consumer, which accounted for 38.1% of the total power demand in 1993. Since the growth rate of electricity demand has been exceeding 13% in recent years and over 10% growth rate has been predicted for the coming years by the Load Forecast Summary Report, the national authorities have to face the burden of financing the development of new power-generation facilities to cope with this rapidly increasing demand. In 1992, the government revised the national energy policy in order to allow and encourage private participation in power-sector investment, providing particularly favorable conditions to those who make use of renewable energies, indigenous by-product energy sources and more efficient use of primary energy through cogeneration.

In Thailand, cogeneration has been employed for more than 40 years in the sugar industry. Its use seems especially appropriate for process industries such as food, paper, chemicals and textiles due to the fairly steady demand for heating, cooling and power. At present, the total installed capacity in these industries is about 900 MW. 2

Even though cogeneration has higher thermal efficiency than a conventional utility system, the econ- omic opportunities for cogeneration depend upon many on-site factors, such as the installation cost, relative electricity price, fuel cost, maintenance cost, government policy, etc. In this paper, cogeneration potential for a textile factory is evaluated based on the energy utility requirements of the plant. Technical and economic results of different alternatives are compared so as to determine the most attractive option.

2. A GAS-TURBINE COGENERATION SYSTEM

Selection of the prime mover for a cogeneration system is usually based on the ratio of thermal energy to power requirement, the type of thermal energy needed, availability of energy source, and economic viability of the selected primer mover.

Natural gas (NG) has the highest share of fossil-fuel consumption for power generation in Thailand,

*Author for correspondence. 1169

EGY 21:12-I

1170 O. Tang and B. Mohanty

accounting for 44.1% of the total fossil fuel consumption in 1993) This form of energy is particularly suited for use because of its high quality as a fuel, ease of transportation, more efficient use in combined or cogeneration cycles than compared to a stand-alone power generating unit, short gestation time for commissioning of gas power projects, etc. The Petroleum Authority of Thailand (PTT), the sole NG distributor in Thailand, has a policy to encourage NG use for cogeneration applications through a favorable pricing mechanism) NG is priced at 86 Baht per million Btu (1 US$ = 25 Baht approximately) for cogeneration utilization as compared to 112 Baht per million Btu for non-cogeneration systems.

With the possibility of selling excess power to the utility grid and a guarantee for standby power supply from the grid during system breakdown, cogeneration systems based on the gas turbine as prime mover have developed into a flexible and reliable source of thermal energy and power: With techniques such as post-combustion, thermal load following, and a combined-cycle system, the gas turbine can be used in all applications regardless of the thermal energy to power ratio:

2.1. Exhaust gas

The exhaust gas of a gas turbine at full load is generally between 430 and 550°C and contains 15- 18% oxygen by volume: There is a significant amount of energy recoverable for other uses in a cogeneration system. The high temperature of the exhaust gas allows either the direct heating of an industrial product or the production of a heat carrying fluid that may be used for heating or cooling applications. The most common method of exhaust heat utilization is the production of steam. Although steam can be generated at almost any required conditions, gas turbine cogeneration systems are usually designed for steam pressure ranging from 100 to 2000 kPa because the exhaust heat can be more fully used at low steam generation pressures. In addition, exhaust gas can be used for any fluid heating, which involves raising the temperature of a working fluid by addition of heat through a heat exchanger. Most fluid heating systems utilize organic heat transfer fluids which satisfy the special requirement of temperature ranges that cannot be met by steam.

2.2. Post-combustion

As the exhaust gas contains as much as 15-18% oxygen by volume, one can make effective use of this available oxygen through post-combustion to further increase the temperature of the exhaust gas. This obviously requires provision of additional fuel but increases the overall system efficiency consider- ably. Such a post-combustion system can be installed either directly at the turbine exit (hot post- combustion) or after the exhaust gas is cooled down to 220-250°C in a heat exchanger (cold post- combustion). Typical temperatures in post-combustion are in the range of 650-950°C. Standard designs are limited to 980°C for NG. 6

Post-combustion should be considered for any application that requires a high ratio of thermal energy to electrical power. Post-combustion provides an efficient and convenient means of meeting the thermal requirements of a plant where the electrical and thermal needs do not closely match the capabilities of the prime mover. In addition, post-combustion provides greater flexibility in satisfying the thermal energy requirement over a certain range.

2.3. Absorption chiller

Chilled water is a usual utility requirement for process cooling in many industries, especially in the tropical climate. Cogeneration with absorption chiller provides a chance to improve the whole system efficiency by further recovery of available heat. 7 On the other hand, since the compression chiller can be replaced, the total electricity demand can be reduced. The additional investment on absorption chiller is compensated by the down-sizing of the prime mover and the compression chiller.

Chilled water can be generated in a vapor absorption chiller with a fluid mixture such as lithium bromide and water solution used in the absorber. Devices have been designed which utilize direct exhaust gas heat or steam generated from the exhaust gas as the heat source for concentrating the absorbent solution by boiling off the water in the generator of the chiller. Exhaust gases at 280°C or higher temperatures can be routed directly to the chiller as a heat source. The chiller capacity can be controlled through partial gas bypass. More often, 850 kPa saturated steam is used to perform the same heat source function.

Industrial energy efficiency improvement through cogeneration 1171

3. HEAT-RECOVERY SYSTEM DESIGN

3.1. Gas turbine operation parameters

The operation parameters of the gas turbine can significantly affect the overall efficiency of the cogeneration system. Generally, the amount of available heat that can be extracted from a gas turbine exhaust is a function of exhaust gas temperature and its flow rate. The overall thermal efficiency of the cogeneration system will also depend on the heat rate which is defined as the thermal energy needed to produce a unit of power. These parameters vary with the capacities of the turbine, load factors, site conditions and manufacturers. Using data available from the catalogue of a gas-turbine manufacturer, the following parameters have been selected as the basis for design (the turbine capacity ranges from 3000 to 5000 kW, which is suitable for the factory being analyzed): heat rate = 3.55 kJ-s-l-kW -~, exhaust gas temperature = 485°C, exhaust gas specific flow rate = 17.3 kg-hr-]-kW -1.

3.2. Pinch temperature and stack temperature

Two critical parameters required to design the heat recovery system for a particular application are the pinch and stack temperatures. Pinch temperature is defined as the minimum temperature difference between the thermal fluid and the exhaust gas along the length of a heat recovery device such as a heat recovery steam generator (HRSG). Figure 1 presents a simplified temperature profile curve for a typical HRSG, showing the relationship of the water-side temperatures in the economizer, evaporator and superheated sections relative to the exhaust gas.

Pinch temperature is a measure of the heat transfer surface required in a given system. As the heat transfer surface increases, more energy can be extracted from the exhaust gas, which reduces the pinch temperature. However, a point is reached where the amount of energy recovered from the turbine exhaust is smaller with any incremental increase in heat transfer surface. An optimum surface, and a corresponding pinch point, is reached based on the value of the additional steam produced. As fuel costs vary, the value of the produced steam will also vary, affecting the optimum pinch temperature. In a typical HRSG, the pinch temperature is normally selected as 20°C. The second critical parameter

_Qw_ .~

I- Q_e_c. Qre

_ ~ _ Gas side

Fluid side

Economizer Evaporator Superheater

Enthalpy Fig. 1. Enthalpy-temperature diagram for the HRSG.

1172 O. Tang and B, Mohanty

in a waste heat recovery system is the stack temperature because the goal is to reduce the temperature of the exhaust gas to the lowest practical limit. This limit is ultimately set by not allowing the tempera- ture of the waste-heat system metal to reach a point where combustion product acids precipitate onto the metal. This is known as the acid dew point.

Dew-point corrosion is a major consideration with economizers in any steam generation system. Since the economizer is essentially a gas-to-water heat exchanger, the tube metal temperature at the feed water inlet tends to be at or near the feed water temperature. Consequently, the inlet water should be at a temperature to preclude dew-point precipitation. It is desirable to keep the feed water above 100°C and the exhaust gas stack temperature at least 20°C above the acid dew point of the exhaust gas. Feed water heating is easily accomplished if deaeration is required because most deaerators operate at 102°C.

The acid dew point of the exhaust gas is a function of the amount of sulfur in the fuel, Restricting the sulfur content in the fuel allows a lower stack temperature design. Care must be taken to evaluate the resulting exhaust stack temperature to ensure that the exhaust gas acid dew point has been avoided. If the calculated exhaust stack temperature is found to be too low, additional fuel to the burner will be required to raise the stack temperature to a practical lower limit.

3.3. Recoverable thermal energy

The available amount of thermal energy that can be recovered from the gas turbine in an evaporator or a thermal fluid heater is determined from the energy balance equation

Qe. = Ms (Hie - - Here), (1)

Mg = mg x P. (2)

The amount of steam or thermal fluid produced in a system without post-combustion is calculated from

NG 43.5MJ/s Fuel consumption: non cogeneration-249 GJ/hr cogeneration-177 GJ/hr

Thermal efficiency: 78.0%

~ IGeneratOrl 12"25MW

Exhaust Postcombustior 58.87kg/.~ NG 5.7MJ/s 485°C

Air 'Stack 150°C 1 208°C J

• - Heat recovery conomize~ boiler

q ,I 188°c "1 Feed water 100°C

15 bar steam 40 Ton/hr Fig. 2. Gas turbine with recovery boiler (electrical matching).

Industrial energy efficiency improvement through cogeneration 1173

NG 43.5Md/s [Fuel consumption: i ] non cogeneration-328 GJ/hr

[Thermal efficiency: 83.5%

I Generator [ 1,2.25 M W

T Exhaust P o s t c o m b u s t i o n 58.87kg/s NG 9.6MJ/s 485°C Air

Thermic fluid

30500 )] ThermiOheater fluid Ill 330°0 ~ 65 G J / h r

Post combustion 1 1 4.SMJ/s 345oc

T Stack 148°c 2°8°0 I Heat recovery

" ~Economizeg J boiler ~1 I 1 s s o c ']

F e e d w a t e r ] 100°C

15 bar steam ) 4 0 Ton/hr Fig. 3. Gas turbine with recovery boiler and thermal fluid heater.

Ms = Q e J ( H , , - H, i ) . (3)

The heat transfer in the post-combustion system is calculated from

Qre = Msr (Hso - Hsi). (4)

The heat provided in post-combustion is

Q p = Q r e - Q e v . (5)

Heat transfer for the whole system is

Qw = M~r (H~o - Hsy). (6)

The economizer duty and exhaust gas temperature are, respectively,

Qec = Qw - Qr, (7)

aec = Mg × (H,,e -nece ) . (8)

3.4. System performance

Although the primary concern of a company considering cogetleration is to obtain the best economic results possible for plant operation, the basic intent of the national authorities in supporting cogeneration is to encourage fuel conservation and the development of more fuel efficient systems. A gas turbine cogeneration system satisfies both these needs. To evaluate cogeneration system performance, para- meters such as thermodynamic efficiency are useful. The thermodynamic efficiency is given by

1174 O. Tang and B. Mohanty

NG 35 .3MJ/s Fuel consumption:

1 I non cogeneration-285 GJ/hr I cogenerat ion-207 GJ/hr

~ Thermal efficiency: 85.1%

I P.o=combust,on • I NG 22.4MJ/s 485oc

Air

T Stack 14°*C

/ | Heat recovery ¢ nomlze • bo i l e r

168°C F e e d wa te r 100*C 60.8 Ton/hr

15 bar steam ~ 4 0 Ton/hr

\ 7 ZX

I 11500 kWth A b s o r p t i o n ch i l l e r I ~"

Fig. 4. Gas turbine with recovery boiler and absorption chiller.

rl,h = (P + Qr~)IF (9)

and

F = P x hr. (10)

4. CASE STUDY IN A TEXTILE MILL

4.1. Background

The textile factory selected for this study is a polyester manufacturer with staple fiber and filament yam as main products. The normal operation time is 24 hours, with three shifts per day. After 700 days of production, the plant is shut down for 3 weeks for overall maintenance. The average annual production time is estimated to be 8400 hours. At present, there is no cogeneration system in this factory. Instead, the energy utility is supplied from two main sources: the first is heavy fuel oil, for producing steam (15 bar) and heating the thermal fluid (315-330°C) to satisfy the process requirement; the other is grid electricity, which is supplied to all the sections of the plant to run the motors and for lighting. Chilled water, which requires around 20% of the total power, is also necessary not only for air conditioning, but also for process cooling. All of the chilled water is produced by using vapor- compression chillers. This factory is in the process of doubling its production capacity within the next two years. As the total energy bill of the plant amounts to 138 million Baht (5.52 million US$) per year at present, the factory management is concerned about the future hikes in energy bill. Therefore, feasibility analysis of a suitable cogeneration system became necessary and imperative.

Energy load profiles were obtained from the result of an energy audit conducted in the existing utility plants. It was concluded that presently, the load fluctuations of electricity, steam and thermal fluid demands are 9.3%, 21% and 15.6% respectively. So the loads and the heat to power ratio can be considered to be relatively steady. Due to unavailability of data about the expansion plan, it is assumed that this load pattern will remain the same after the future expansion of the production facility. From

Industrial energy efficiency improvement through cogeneration 1175

the information provided by project management, the main utility loads after factory expansion are estimated to be as follows: electricity use = 12,250 kW, steam = 96 GJ-hr -~, thermal fluid = 65 GJ-hr -~, cooling load = 3270 RT. The heat to power ratio with these conditions is 3.64.

4.2. Alternative configurations

The optimal configuration for cogeneration depends on the criteria used and the conditions under which the system is designed. Selection of the cogeneration configuration depends on the cost effective- ness of the overall investment. Four alternatives are compared here by considering load patterns in this factory. Options 1-3 are based on electrical matching and option 4 is based on thermal matching. The accompanying figures provide energy balances to satisfy the energy needs of the factory after pro- duction-capacity expansion.

Option 1--Gas turbine with recovery boiler (electrical matching). The exhaust from a gas turbine will be introduced to the heat recovery boiler to produce steam. Post-combustion is necessary to make up for the deficient heat (Fig. 2). This is also expected to provide the flexibility to the whole system. When gas turbine is shut off during scheduled maintenance or due to unforeseen breakdown, NG can still be supplied to the boiler directly. Therefore, supply of the steam to the processes can be always assured in spite of a shut down of the gas turbine unit.

Option 2--Gas turbine with recovery boiler and thermal fluid heater. Since exhaust gas contains a large amount of excess air and the exit temperature is high, a thermal fluid heater can be incorporated in order to improve the system thermal efficiency. Post-combustion is required in both thermal fluid heater and boiler (see Fig. 3).

Option 3--Gas turbine with recovery boiler and absorption chiller. An absorption chiller is used instead of a compressor chiller in this system to produce the required cooling. Though the steam pro- duction rate increases in this case, the size of the prime mover is reduced due to the elimination of power demand by compression chiller (see Fig. 4).

Option 4---Gas turbine with recovery boiler (thermal matching). The system configuration is the same as that of option 1 (see Fig. 5). Instead of electricity matching, the prime mover is sized in order

NG 59.1 Md/s IFuel consumption: I non cogeneration-297 GJ/hr I cogeneration-213 GJ/hr Thermal efficiency: 72. 7%

Turb,oe i Geooratorl 16.66 MW !excessl Comp. I I

Exhaust 80.05kg/s 485oC

Air

Stack 208°C I Heat recovery

1 65°C

!conomizei J boiler 188°C 7

Feed water 100°C

15 bar steam 40 Ton/hr Fig. 5. Gas turbine with recovery boiler (thermal matching).

1176 O. Tang and B. Mohanty

Table 1. Data for economic evaluation.

Item Cost/benefit Source

Installation Equipment

A. Gas turbine/generator set 700 US$-kW -t Textile factory B. Boiler unit 18,600 US$-Ton steam-~-hr -~ Textile factory C. Thermal fluid heater 15,000 US$-GJ -~ Textile factory D. Compressor chiller 240 US$-RT -~ Textile factory E. Absorption chiller 390 US$-RT -j Textile factory F. Modification of existing equipment 20% Textile factory

Contingency 10% Boonrowd, 1995 Interest cost during construction 12% Boonrowd, 1995 Tax on imported equipment 5% Boonrowd, 1995

Revenues Displaced electricity 1.46 Baht-kWh -~ Textile factory Displaced steam 132 Baht-GJ -~ Textile factory Displaced thermal fluid 109 Baht-GJ -~ Textile factory Electricity sale to the power utility

A. Capacity payment 204 Baht-kWh-~-month -~ EGAT, 1992 B. Electricity payment 0.85 Baht-kWh -t EGAT, 1992

Expenses Natural gas price 86 Baht-GJ -~ Boonrowd, 1995 Operation & maintenance cost 2.5% of installation cost Insurance 0.5% of installation cost Standby charge 36 Baht-kW -~ EGAT Depreciation S-Y-D method

Others Discount rate 12% Life of the project 15 Years

EGAT = Electricity Generating Authority of Thailand.

to recover enough energy from the waste heat to produce the steam required by the process. The excess electricity produced is supposed to be sold to the power utility grid.

4.3. Economic evaluation

The evaluation of economic potential of such a project involves determination of different sources of revenues and expenses and computation of internal rate of return (IRR), pay-back period (PBP) and net present value (NPV). The net cash flow method is used here to determine the attractiveness of the alternatives.

4.4. Result

The four different options for cogeneration systems are compared on the basis of the annual operation cash flow analysis. A summary of the main results is listed in Table 2. Among the first three options, option 2 appears to be the best, providing maximum NPV, IRR and minimum PBP. In this option, the self-generated electricity price is computed as 0.76 Baht per kWh, which is much lower than the rate at which electricity is presently purchased by the textile mill from the utility grid ( 1.46 Baht per kWh).

The initial investment cost to be incurred in option 2 is slightly higher than option 1 because the

Table 2. Results of the economic analysis.

Item Option 1 Option 2 Option 3 Option 4

Investment (million Baht) 324.3 332.0 298.3 437.9 NPV (million Baht) 266.3 310.0 188.4 166.0 IRR (%) 25.0 26.6 22.2 18.5 PBP (years) 5.74 5.32 6.63 8.22

Industrial energy efficiency improvement through cogeneration 1177

major investment cost is that of the gas turbine set. The capacities of gas turbine in both of these options are the same. Option 3 is not attractive because there is no excess exhaust heat available in this particular case. Post-combustion is already required to produce adequate steam to satisfy all the heating needs of the plant. As further heat is necessary to run the absorption chiller, the fuel consumption increases, and the net revenue of this project is reduced.

High investment is necessary for option 4. Even though this option offers the possibility to sell the excess electricity to power utility, the revenue generated from the sale of power is not adequate to compensate the high investment. Consequently, the NPV is less and the PBP is higher than other options.

5. CONCLUSIONS

With the availability of cheap NG, cogeneration operating with such a fuel is a promising option for reducing the total energy bill in the textile factory. Gas-turbine cogeneration provides a good margin of saving per kWh of power generation relative to the no-cogeneration option. Economic feasibility is heavily determined by the configuration of the heat-recovery system and the size of the prime mover. A gas-turbine unit incorporating a thermal fluid heater and a heat-recovery boiler appears to be the best option. The PBP is found to be 5.32 years and IRR is 26.6%. Cogeneration with thermal matching is not appropriate because the sale price of electricity to the utility is not high enough to compensate for the increase in the initial investment of the prime mover. Cogeneration incorporating an absorption chiller is not economically viable, even though the size of the prime mover is reduced. This option will tend to increase the operation cost because more NG will be required to raise additional steam.

The result of this specific study is encouraging enough for other process industries to look seriously into the prospects of opting for cogeneration in their respective plants, which will not only be rewarding to them, but also to the country as a whole since the indigenous energy sources will be exploited more rationally and the national power utility would have a lower burden of coping with the ever-increasing power demand.

REFERENCES

1. DEDP, "Electrical Power in Thailand 1993", Department of Energy Development and Promotion, Bangkok (1993).

2. P. Amranand, "Establishing an Effective and Conducive Environment for the Promotion and Development of Cogeneration Projects in Asia: Lessons from Thailand", The 1994 Cogeneration Conf., AIC, Bangkok (1994).

3. C. Boonrowd, "Case Study of Cogeneration", Seminar on Potential for Cogeneration in Thai Textile Industry, The Energy Conservation Center of Thailand, Bangkok (1995).

4. J. Vervaecke, "Application Viability of Small Cogeneration Systems for Industry", Turbomachinery Tech- nology Seminar 1989, Solar Turbines Inc., San Diego, CA (1989).

5. W. Fisk, J. M. Kovacik, and W. B. Palmer, "Cogeneration Application Consideration", 37th GE Turbine state- of-the-art Technology Seminar, GE Power Generation, Schenectady, NY (1993).

6. W.A. Leland, "Power and Thermal Cycle Optimization", Turbomachinery Technology Seminar 1989, Solar Turbines Inc., San Diego, CA (1989).

7. B. Lui, "The Feasibility Study of Thermal Storage Application and Cogeneration with Absorption Chillers in a Spinning Mill", Thesis, ET-93-2, AIT, Bangkok (1993).

NOMENCLATURE

F = Total fuel required by the system H,i = Enthalpy of the steam or thermal (El-s -l ) fluid at the inlet of evaporator or

hr = Heat rate (kJ-s-l-kW -~ ) thermal fluid heater (kJ-kg -j ) H~y= Enthalpy of feed water at the inlet H~o = Enthalpy of the steam or thermal

of economizer (El-hr -~) fluid at the outlet of evaporator or Hece = Exhaust gas enthalpy at the outlet thermal fluid heater (El-kg -~)

of economizer (kJ-kg -~) Hte= Enthalpy of exhaust gas at the /-/eve = Enthalpy of exhaust gas at the turbine exhaust (kJ-kg -~)

outlet of evaporator or thermal fluid mg= Exhaust gas specific flow rate heater (kJ-kg -1 ) (kg hr-l-kW -~)

1178 O. Tang and B. Mohanty

M s = Exhaust gas mass flow rate (kg- Qp = Additional heat provided by post- hr -t) combustion (kJ-hr -1)

Ms = Steam or thermal fluid mass flow Q,~ = Total heat transfer to produce rate (kg-hr -s) thermal energy required for the

M~, = Steam or thermal fluid flow rate to process (kJ-hr -~) satisfy the process requirement (kg- Qw = Overall heat recovery including hr -1) post-combustion (kJ-hr -l)

P = Power generated in the gas turbine RT = Refrigeration ton (kW) (1 RT = 3.517 kW~he~ma~)

Qec = Heat transfer duty in economizer r/, h = Thermal efficiency (%) (kJ-hr -1)

Qev = Heat available from the exhaust gas in evaporator (kJ-hr -~)