PEAK D E W D SHAVING BY COGENERATION

M.Ei-Shibini M.El-Marsafawy Electrical Engineering Department,Faculty of Engineering,Cairo University,Cairo,Egypt

Abstract - The paper presents a methodology for the calculation of the optimal cogeneration facility capacity and operation suitable for demand side peak shaving ensuring a reliable service and economic utilization of the facility.The developed methodology takes into consid- eration steam conditions in the plant,electric load profile,fuel price,operating hours,plant critical load,- power factor penalty ,and economic indicators.The neth- odology depends upon increasing the shaving amount to increase the facility utility factor for improving its economy.The computer program developed for this study provides cogeneration facility capacity,costs,payback period,benefit to cost ratio and facility utilization factor.The output of the program also contains improved load factor,reduced demand leve1,new contracting demand, future tariff evolution,and project cash flow table The results of the application of the proposed methodology to an industrial company in Egypt have shown that it is technically and economically feasible to use cogeneration facility for peak demand shaving.

I. INTRODUCTION

Since Middle East War in 1973 the efficient usage of energy has become an important objective all over the wor1d.Cogeneration and electric load management have been considered as energy conservation programs measures.Load management has been used to control o r shift the peak of aggregate electric loads in order to reduce the need for system expansion and t o reduce fuel cost. Many of Utilities planners started programs to extend tiieir activities to the other side of demand meters,taking into consideration the demand side requirements which can be briefly summarized in reducing cost, conserving ene- rgy,maintaining lifestyle, increasing service options,and enhancingquality of service[l].These activities are known by demand side management (DSM)which can be defined as the planning, implementation and monitoring of those utilit,y activities designed to influence customer use of electric- ity in ways that will produce desired changes in the utility’s load shape.

DSM objectives include peak shaving,valley filling,load shifting,strategic load Growth,and strategic Conservati- on.The evaluation of demand side management is based on its cost effectiveness. Each utility has its own specific cost effectiveness measures which should be related to utility avoided cost. If the DSM alternative costs are less than o r equal to avoided costs, the proposed alterna- tive is considered to be cost-effective. There would be a

0-7803-1462-x/93$03.00 01993IEEE

M I Emam Organization for Energy Pianning

Cairo,Egypt

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periodic evaluation process t o be done by the utility dealing with DSM . Adoption of DSM alternatives by any utility reduces supply-side costs by scheduling proposed capacity addition or by changing operation program[2].

Electric power Research Institute has presented its final report in April 1981 on the potential for load management in selected industries.The study evaluated the technical and economical feasibility of altering existing load shapes in seven industrialoperations,which were,pet- roleum refiner,chlorine/caustic production,steel produc- tion,cement production,aluminum production,paper produc- tion,and pipelines[3].

In this paper a methodology for optimum peak shaving by cogeneration facility has been developed.Input data required for the computer program are steam conditions in the plant,electric load profile,fuel price,operating hours,plant critical load,power factor penalty,and eco- nomic indicators.The methodology depends upon increasing the shaving amount to increase the facility utility factor for improving its economy.The output of the program are cogeneration facility capacity,costs,payback period,be- nefit to cost ratio and facility utilization factor.The output of the program also contains improved load factor reduced demand leve1,new contracting demand, future tariff evolution,and project cash flow table .The application of the developed program to an industrial Company for Coke and Chemicals indicated that the use of cogeneration facility for peak demand shaving has proven to be techni- cally and economically feasible.

11. COGENERATION AS A DSM ALTERNATIVE

Cogeneration is the sequential use of a primary energy source to produce two energy forms,heat and power. The improvement of overall efficiency in case of combining two systems may exceed 70 percent,while the conventual energy system will be less than 47%[41.

There are two fundamental types of cogeneration systems- ,topping and bottoming cycles,differentiated on the basis of whether power or thermal energy is produced first[Z].- The evaluation of cogeneration system starts by the technical feasibility analysis and finalized by the eco- nomic feasibility study. The technical feasibility depends upon the difference between generated steam pressure and the process needs,that difference is usually dissipated in reducing valve which can be replaced by a steam turbine to generate power instead of the dissipation of the steam power. The turbine can be a back pressure turbine which may drive mechanical load directly coupled to it o r electric generator,to feed the electric load of the factory.The required investment in this case is the cost of turbo-generator set alone. The factors affecting the cogeneration feasibility are:process steam pressure,proc- ess steam rate,electric load,operating hours,electric cost,and fuel cost.Beside the six main factors mentioned above which affect the feasibility of cogeneration system,there are other economic factors which influence the results.These factors are:the cost of equipment,inst- allation,equipment depreciation,operation and maintenance cost in addition to inflation rate for each cost items (fuel,electric,spare parts,and salaries), life cycle of equipment,and banking interest.

The normal operation of any cogeneration facility is to be switched off only in the emergency cases for repair or according to maintenance schedule requirement. Cogen- eration facility can be used for peak load shaving ,but this would affect the economy of the cogeneration project if it was not chosen for that task.The task will be the design of cogeneration facility to feed part of site electric load on peak time.The facility can be operated partially during off-peak time.

I I I . PROPOSED METHODOLOGY

3.1. Technical Considerations:The calculation of cogeneration capacity which is equivalent to the dif- ference between peak demand and the shaving level is made based on the steam paths pressures,rates,constrains and electric load profile, taking into consideration required reliability as shown below.

a- Calculate the available power generation according to steam conditions using the following equation

GT C C(i) MW G(i) = Q(i) * (H(1) - H(i))*EFF(i)/36OO MW (1)

where: H(1) is boiler house output steam enthalpy,Q(i),- and H(i) are input steam rate and enthalpy,EFF(i) is efficiency and conversion factor,GT is total generation capacity,and i is the generation unit number.

b-Determine the required power shaving:starting with initial value of shaving power which is a fraction of the available generation,the initial value of after shaving maximum demand will be given as shown below:

ZR = ZM - AF*GT (2) where: ZR is after shaving maximum demand,ZM is maximum

load demandland AF is fraction.

The initial value of after shaving maximum demand will be modified according to other constrains calculationB.The required power shaving(DZ) will be in general the differ- ence betweenmaxiaum load demand and after shaving maximum demand as shown by the following equation

DZ = ZM - ZR ( 3 )

C-Adjust cogeneration power to the recommended shaving 1evel.The total facility power should be compared with the recommended shaving in case that facility total power is less than or equal to recommended shaving, there will be no other trial for modifying the generation capacity ,but if that capacity was greater than recommended shaving the generation unit capacities should be reduced by a portion- (DG) equal to the difference as follows:

DC = GT - DZ ( 4 )

The power capacity can be reduced by reducing the steam flow through one of the turbine using a parallel steam path equipped by steam reducing valve.The required re- duction of flow (DQ)can be calculated as shown below:

DQ = DG*3600/((H(l) - H(i))*EFF(i)) The steam rate flow through that path has to

lated again as shown below :

Q(i) = Q(i) - DQ That unit capacity should be calculated again

to the new steam flow through it.

(5)

be calcu-

(6)

according

d-Check electric supply reliability and determine con- tracting demand.Considering that utilities capabilities can ensure the power supply for contracting demand ,it is required to check system reliabilbty, which should fulfill the following constrains: duration of any outage should be less than maximum allowable outage time for critical loads,and a minimum power supply should be avallable for critical 1oads.The process conditions determine these two 1imits.In general critical demand ZC is the sum of the main loads which are supposed to be in operation or ready to operate any time.In case that critical demand was less than after-shaving maximum demand,contracting demand ZN would be chosen equal to that after-shaving maximum demand as shown in following equation

( 7 ) If ZC < ZR take ZN = ZR

If critical demand was higher than after-shaving maximum denandla reliability test should be carried on.This will require the following data:the probabilityof cogeneration units outage and load occurrence probability table.For cogeneration facility,the probability of outages data can be obtained/estimated by the help of vendors and/or utility experts.The load occurrence probabilities have to be calculated by the analysis of load duration data.These data have to be recorded over a sample of days represent- ing loading profile of the site. The load occurrence probabilities could be obtained through changing dura- tion time of each demand level to per unit value with respect to overall time of the sample.

The occurrence of different outage levels of cogenerat- ion and each demand level time should be checked.If this time exceeds the allowable outage time ,the difference between critical demand and cogeneration output power should be supplied through utility network.The contracting demand should ensure the supply of critical load during cogeneration outages.This can be done using the following formula:

TST(i,j) = OZi * qj* HRS $60 (8)

where: TST( i, j) is time of coincident cogeneration capa- city(j) outage and load demand level (i)in minutes,HRS is operating hours,qi is outage of (j) cogeneration capacity per unit time, and OZi is per unit time occurrence of load demand level(i).

Compare TST(i,j) with allowance outage time as shown below:

If TST(i,j) < TAL. take ZN(i,j) = ZC - GTj

where :TAL is maximum allowed outage time,ZN(i,j) is the required contracting demand foe consequence cogeneration capacity(j)outage and load demand level (i)in ninutes,and GTj is cogeneration facility output power for outage condition level ( j ) ,and is given by

m GTj = GT - .Ejzl Gj (10)

where: Gj is output power of unit (j), and GT cogenera- tion total rated output power.

These calculations should be repeated for simultaneously different generation outage levels and load demand levels. The results of previous test will be a group of recom- mended contracting demands and the maximum value will be the suitable one.

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3.2 Economical Considerations:The saving of purchased electricity will be lhe revenue of the project which is equal to the difference of electricity cost with and without cogeneration.This saving has to be compared with the other cost items to get the net saving each year along the life cycle of the project.Cost items include equipment capital cost,depreciation cost,banking interest cost,maintenance cost,operation cost and fuel cost.These cost items are calculated as follows:

a-Capital Cost: In the feasibility analysis phase,capi- tal cost has to be calculated according to known specific cost o r estimated specific cost.The specific cost of these equipment varies according to vendors nationality and quality ,as for example far east products are cheaper than western products.Capita1 cost of a cogeneration facility includes the cost of turbo-generation unit in addition to any modification to electric board and installation.The cogeneration facility cost could be estimated as shown below[5]:

CC = SCC * C (11)

where:CG is the cogeneration facility cost,SCC is the cogeneration specific cost,and C is the cogeneration facility capacity.

b-Depreciation Cost: The value of any equipment decreas- es by time.This decrease has to be considered as a cost item in the analysis.The most common method for calcii- lating depreciation cost is the straight line nethod.The depreciation cost will be related to capital cost and life cycle of equipment as shown below.

f-Electric Cost:Electric cost is the most effective item in the cogeneration economy.The cost of purchased electric energy composed in general of two main terms,demand charge and energy charge.These two terms are the base for the electric bill in addition to the power factor penalty which will be applied to the energy charge .Electric cost for loads higher than 500 KW will be estimated according to the following formula which was developed by the authors :

EC =b,*Zt B"-'ai*bi*Ztbn(X-Bn-'ai*Z))[ ltppf) (15) 1 4 i .1

Such that n < 6 and X > 1500 *Z

and X > E"-' ai *Z I= 1

where : EC is Purchased electric cost ,Z is Contracting demand, X is Electric energy consumed in the year,ppf Power factor penalty,ai(i=l-5)are equal to 1000,500, 10000,1000,1500 hours respectively b is the demand charge (28.9 LE/KW in yea^-1989), and b, (lif1-6)is the ith block price(Theywere51.8,48,8,42.5,36.5,27.7,23.7respectively in 1989). The previous formula illustrates that unity load factor

brings the calculation of electric cost to the lowest price block which is 23.7 mils/kwh.

IV. OPTIMIZATION MODEL

DCG = CG/LC (12)

is the life

The objective function is to maximize accumulated levelized benefit to cost ratio along the expected life cycle of the generating units.The benefit to cost ratio where: DCC is the depreciation costsand Lc

cycle years of equipment. (BCR) is given by[6]:

c-Banking 1nterest:The profit of banking interest which LC K will be lost by this investment has to be considered as a BCR= B ((R(k)-C(k))/(ltFLT) )/c.c. (16) cost item in the evaluation of the payback period.The K = l yearly cost of this item will be the book value interest.

where:FLT is the inflation rate,LC is the life cycle d-Yearly Maintenance and Operation Costs:Maintenance years,C.C.is the considered cost of capital,R(k) is

cost depends mainly upon the spare parts cost which is project revenue in year k,and C(k) is cost items sum in normally related to the capital cost of equipment by an year k. estimated percentage.The prices of spare parts are in- creasillg by tine . ~ l ~ i ~ price increasing is not the same as The revenue R(k) Will equal to the difference between inflation rate it is considered as a price iridic- purchased electricity costs with and without cogeneration ator.0peration cost depends mainly upon the worker sala- as shown ries which varies according country and plant condition- s.Numbers of operating and maintenance staff depends upon (17) the size of the facility,so operation cost can be related to the capital cost of the units for this particular where:EC(l,K) is purchased electricity cost for year application.The increasing rates of salaries would tie (k)without cogeneration,and EC(2,K) is purchased elec- considered in the evaluation program.

R(k) = EC(1,K) - EC(2,K)

tricity cost for year (k)with cogeneration.

The cost difference will be due to the difference in three items :demand charge,energy charge,and Power factor penalty.The cost of purchased electricity increases each

e-Yearly Fuel Cost: Input fuel to boiler is distributed year according to the tariff structure inflation.Electric between power generation and processheating.The term fuel tariff historical data could be used to forecast the charged to power FCP(i) for unit i will be calculated future electric prices by least square curve fitting tecti- according to the steam flow rate and its enthalpy differ- n i n i i p s .

- . -_1- - - - ence ,as shown below: The term C(K) represents maintenance ,operation and

( 1 3 ) fuel costs.These costs are also increasing each year FCP(i) = Q(i) * (H(1) - H(i))/Q(l)*H(l) according to their own inflation rates or prices indica-

The cost of fuel for each generation unit Will be esti- tors,and they should be calculated for each year as shown mated according to the fuel price and total consumed fuel below: - _ _ _ . during the year of analysis as shown below:

-Maintenance cost represents spare parts cost each year This cost will be calculated according to the following equation:

CPF(i) = FCP(i)*FP*TFC (14)

where: CPF(i) is cost of fuel for generation unit (i),FP is the fuel price,and TFC is total yearly consumed fuel.

K (18) MC(K)= CMT*(ltFLM)

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where: MC(K) is maintenance cost for year (K), CMT is spare parts cost required each year according to base year prices and it is estimated as a per cent of capital costland FLM is inflation rate of spare parts cost.

-Operation cost represents working staff cost including salaries,social careland other related expenditures.The cost operation will be calculated for each year according to the following relation:

k WC(k) = CWT*(ltFLW) (19)

where: WC(K) is operation cost for year (K),CWT is oper- ation cost required each year according to base year conditions and it is estimated as a per cent of capital costland FLW is operation cost inflation rate.

-Fuel cost is corresponding to generated energy and it is calculated through energy flow balance analysis as shown by equations 13 and 14.Fuel cost will increase by its inflation rate as shown below:

k FC(k) = PET*(l+FLF) (20)

where:FC(K) is fuel cost for year (K),PET is fuel cost required each year according to base year priceeland FLF is fuel coat inflation rate. The term(C.C )considers capital cost and its compound banking interest profit accumulated to the end of facility life levelieed by inflation rate to the base year as shown below:

C.C.= CGT*((ltR)/(ltFLT))Lc (21)

where:CGT is capital cost paid in base year,and R is bank interest,FLT is inflation rate.

The optimal solut'ion is the naximun BCR represented in equation 16 by choosing a cogeneration facility of a capacity sufficient to be used in shaving the maximum demand to the required demand 1evel.The loading to the electric utility will be reduced to the level which fulfills the task as shown in the following equations:

GT < ZM - ZR (22)

The operation of this facility will be limited to the shaving level required and utility contracting conditio- ns.Economic evaluation may require changing shaving level and generating units operation hours.Payback period could be calculated by considering additional costs which are depreciation costs and book value banking interest profit .Payback period is that number of years sufficient to recover capital investment considering all cost items mentioned before as shown below :

CGT = c'?R(K)- C(K) - DCG -BCG(K)) (23)

where: L is the payback period ,and BCG(K) is the facil- ity book value banking interest for year (k)and is cal- culated by the following equation

k= 1

BCG(K)= (CGT-K*DCG)*R (24)

V. CASE STUDY

The industrial company tor coke and chemicals is one of the major industrial enterprises in Egypt.The production of this company includes the following products:industrial and laboratory chemicals, tar and Electrode pitch,anmonium sulfate fertilizer,and coke oven gas.

5.1 Description of the Study system: Chemical process requiring heating steam,consumes 20 ton/hr steam of pressure 15 bar and temperature of 350 C, in addition to 55 ton/hr steam of pressure 5 bar and temperature 250 C.The boiler house is equipped with six boilers and two steam turbine sets.0ne set drives compressor used as gas exhausters and the second set is used for electric power generation.The main data of the Turbo-generation set are:input steam conditions 14.7 bar & 350 C. Out put steam conditions 4.5 bar 250 C(steam rate is Glton/hr).Design power is 3.2 MW.This system has fulfilled the following tasks:

-Ensuring the safety of batteries by avoidi~~g power interruption . -Ensuring power supply to other critical loads and re-

ducing the electric energy cost by generating portion of the electric energy consumed.

5.2-Planned Expansion: It is planned to install a new industrial unit in the company.The erection of this new unit will require additional steam.The steam required will be in the average of 95-120 ton/hour.For the additional steam required,two boilers will be added within the contract of the new industrial unit.The rating of these two boilers are 50 ton/hour and of pressure of 40 bar with a temperature of 440 C for each one.

*Expected Boilers Conditions:The future conditions of the boilers will determine the availability of steam energy for cogeneration.The company can provide only 180 Ton/HR of steam as follows:

-100 Ton of steam of 40 bar &440 C from the new boilers -80 Ton of steam of 15 barb 350 C from old boilers

*Expected Electric Loading:The increase of electric demand is estimated to be less than 3 MW,and in the average of 2 MW(company staff estimation).So the average demand will be less than 6 MW(2 MW expected increase,and 4 MW current average demand) while maximum demand will be less than 10 MW.The expected maximum demand will be about 9 MW.The load profile of the plant after expansion is expected to be as current loading profile but with a different maximum demand.A computer program was also developed to estimate(f0recast)the future electricity tariff.

5.3 Cogeneration for Peak Shaving : The objective is to test the feasibility of using cogeneration to supply peak loading which means that the base loading would be fed through Electric Utility feeders.The electric loading to Utility in this case will be of higher load factor.Steam conditions in the factory under study determine the available power generation.The levels of steam conditions will be as follows:

-Higher level of 40 bar and 440 C Its enthalpy is about

-Second level of 15 bar and 350 C its enthalpy is about

-Third level is of 5 bar and 250 C its enthalpy is about

3308 KJ/KG.The quantity is about 100 Ton/HR.

3148 KJ/KG.The quantity is about 25 Ton/HR.

2960KJ/KG.The quantity is about 85Ton/HR.

Through recording the electric power consumption during three weeks representing the normal loading the loading profile has been developed.This load curve was normalized and adjusted to expected future maximum demand to get demand occurrence probability curve shown in Fig.1, which shows that the occurrence of loads higher than 7000KW is less than 7X.The ratio between the average demand to the peak of that profile (load factor) is about 0.57.If apart of the peak demand is shaved, the load factor will increase.The amount of shaving controls the load factor improvement.Fig.2 shows that the load factor increases by the increase of shaving amount.

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20. _ _ _ . -.__-

I

07 2000 3ooo 4000 5000 6000 7000 8000 9000 h" M IT

P1q.I O E E Y I ~ I I C ~ Probability

Y.I.U. D...nd h v . 1

S J U l I d XT 5doo 6000 7doO 8doo 9 i

tlq.3 Genermtcd and Purchased ~ n e r g y .gainst shaved power

The use of cogeneration for peak shnvirtg has the advan- tages of improving load factor and decreasing contracting demand,but it has the disadvantage of less operating time and uneconomic use of the facility.The utility factor(d- efined by generated energy to available energy ratio)will be low.To improve the this economy application'it is required to increase the amount of shaving.Fig.3 shows generated and purchased electric energy corresponding to shaving amount.It is clear that using cogeneration for peak shaving decreases the purchased energy but it doesn't use all possible generation capability. Fig 4 shows the load factor and generators utility factor for different possible generators rating,which are equal to the shaving amount.It is clear that load factor and generators utility factors are improved as the shaving amount increase.Altho- ugh Fig 3 shows that purchased electricity decreases but this doesn't mean that electricity cost decreases as the investment in cogeneration project has t o be recovered in certain period of years.That cost should be considered as a portion of yearly electricity cost.Fig 5 shows the purchased electricity cost and total cost including capital cost of equipment assuming a payback period of five years at different shaving arnounts.It is clear that increasing shaving amount improves the economy of the facility,except that portion near to the peak where occur- rence probability is very low for concerned application.It is clear in Fig.1 that base load is about 4 MW,while peak demand is semi-sharp and starts from 6.3 MW and reaches 9 MW.This type of loading requires the increase of shaving to improve the application economy.Fig 6 shows generators rating and corresponding payback period.This curve shows that payback period decreases by increasing generators ratings . Recommended Cogeneration System: As previous shaving analysis indicated that maximum

Possible power generation will be the optimum as shown in

lo5 I I I /-- 95 __ -. - .. . . - ..- . _ _ - - . . . . . . .. . .. - .

/

0 1000 2000 3000 4000 5000 6000 7000 8000 9 S h a d P a n in Kr

55

Flq.2 Load Factor V e r s u s

shaved Power

1 / I

r i P . 4 Load and Generator utility n c t o r m V ~ ~ D Y . ~ e n c r a t o r s R ~ L ~ , , ~

Fig.5.The recommended system shown in Fig.7 satisfies the process heat requirements which will be about 120 tons/h- our of steam(35ton/hour of 15 bar and 350 C in addition to 85 yon/hour of 5 bar and 250 C).

*New Boi1ers:They will supply the process heat require- ment by 100 ton/hour steam of 40 bar and 440 C.It's enthalpy is 3309KJ/KG.This amount of steam will flow into two paths:

-first path to be through first turbine is about 40ton/- hr,the back pressure will be 5 bar and temperature will be 250 C.Its enthalpy is 2961KJ/KG.

-second path to be through second turbine is about 60to- n/hr,the back pressure will be 15 bar and temperature will be 350 C.Its enthalpy is 3149 KJ/KG.

*-Benefit to Cost Ratio:Economic factors have to be known or estimated to be considered in running the de- veloped program The following are the estimated factors: -banking interest was considered to be -inflation rate was considered to be -spare parts price inflation rate was considered to be about 4% -increasing rate of workers wages to be about -foreign currency exchange LE/US$ to be -specific cost of cogeneration facility will be according to equation(25)

8% 13%

6% 3.3

(25) SCC K/G"

where : K = 340 and n= 0.333

-power factor penalty will be reduced from 0.15 to 110

penalty condition -starting date for fiscal year 1992 is June 1991 -yearly operating hours is 8760 hours.

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TlP.5 Varlotloa of Purehas*d L l . e t r l e l t y c o s t ond 'Sotol E h c t r i c l t y Cost Ylth Amount of shmvlnq

30

50

I I I

3 50 3 50 350 350 350 A

4LD

G 1 Existing cogeneration Unit

G2 Planned Cogeneration Units

d1->06 Existing boilers

8 7 - > 8 8 new boilers

Fig.7 Planned Cogeneration System

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‘20- -

0- 1992 1994 1996 1998 2000 2002 2004 2006 2006 201 0 2

1 ra

FIG.0. .PURCHASED ELECOST WITHBWITHOUT COGENERATIONBPROFIT ALONG LIFE CYCLE

I l q . 1 0 Peak shivins Cost and Bane Load Cost \rer.u. coqcneration POYel ( 1 9 9 1 Price.)

2

.. ~ . _ _ .

9’8& 0.6 0.65 0.7 0.75 016 0.85 019 0.95 1 1 LOM FACTDR

FIG. 9 Y.PROFlT,BENEFIT BLNELIZED BENEFIT ALONG LIFE CYCLE OF PROJECT

I , I

0.1 0.2 0.3 0.4 0.5 0.6 IDZJ, F.4TOR

FIG .I1 WAD FACTOR&ELE.AI’ERAGE PRICES AC.191 PIKES H1M D.C‘H.4RGE=bO/lfl

I

riq.13 Peek Shmvinq Coat nnd 8.m. Lead Cost versus Cegenrr*tion Power (1991 Prlcem YlthD.Charqe-bo/Lrl

1390

The main results of running the developed program are summarized as follows:

- load factor which was 0.56 increased to 0.8075 - Contracting demand reduced from 9000 KW to - The recommended cogeneration facility consists of two generating units ,their ratings are:

2794.8 KW

G(1) First generating unit = 3.67 MW G(2) Second generating unit = 2.53 MW

- Payback period = 3.0 years - Actual benefit to cost ratio = 8.63 - Relative benefit to cost ratio 21.35 (This ratio take into consideration inflation rate and banking interest ) - Total levelized benefit = 41.22 M.L.E. - Total capital cost 1.447 M US$

= 4.2 M.L.E.

Fig.8 shows the expected evolution of factory purchased electricity without and with cogeneration project in addition to yearly profit.It is clear that these values are increasing along the life of the project while Fig.9 shows that even that yearly profit and benefit are in- creasing but levelized benefits are slightly decreasing near the end of the project life.

* Discussion:Cogeneration facility could be used as a main power supply which is the normal case keeping Elec- tric Utility feeders to be loaded by peak loading .The second application for cogeneration facility is to supply peak loading keeping Electric Utility feeders to supply the base 1oading.The first application decreases Electric Utility loading factor with a high value for local generation utility factor while the second npylication is of reverse result.Economics of the application determine the best solution.Egyptian tariff encourages electric loading to be higher than 0.57,but the first application is still m r e economical than the second as shown in Fig.lO,which was prepared according to tariff structure in year 1991.The figure showed that both application total electricity costs decrease by the increase of cogeneration rating ,but supplying base loading by local generation is still more economical than shaving peak.

Different modifications for tariff structure have been tried,the best suggestion was to float the demand charg- e(bo in equation 15) to be related to load factor such that the demand charge would be high for low load factor and to be normal for high load factor.The sugge6ted demand charge ratecould be calculated according to the following equation.

bo = bu / LF

where: b is unity LF is loadrng factor

(26)

load factor demand charge rate ,and to Utility network.

This suggestion leads to an increase in per unit elec- tricity prices for low load factor up to more than 120L- E/KWH for load factor less than 0.1 as shown in Fig.11,- while it will be less than 0.1 LE/KWH for load factors higher than 0.85 as shown in Fig.12.The test of this suggestion to the studied Company for Coke and Chemicals indicated that the total cost of electricity decreased by using cogeneration facility either in supplying base load or in shaving peak demand.Fig.13 shows that the decrease of cost is steeper in the first case than in the second applicationland overall electricity cost is higher in the second application.The electricity cost for first applica- tion starts to incrense sharply at about 4500 KW generat- ing power,while cost for peak shaving continues its decrease as generation rating increases,and starts to be less than first application electricity cost in the range 5000 KW and higher,where peak shaving by cogeneration will be more economic than supplying the base loading .

VI. CONCLUSIONS

The application of the developed program to the studied Company for Coke and Chemicals has indicated that it is possible to have technically and economically feasible application for peak shaving by cogeneration f ac i 1 it y . The analysis and discussion has indicated that according

to the applied tariff structure and the case study loading profile the cogeneration facility as a main power supply to the base loading w i l l be of higher economy than peak shaving application.

The suggestion of modifying tariff structure by relating demand charge to load factor has divided the economy of cogeneration facility application into two rating regions as shown for the case study.In the first region the usage of cogeneration facility for base loading supply could be more economic than for shaving ,while in the second region the shaving application could be more economic than base load supplying.

VIL. REFERENCES

M.Wayne and C.Gellings,"Demand planning in the 80's",EPRI Journal December 1984.

J.E.Runnels and D.W. Hyte,"Evaluation of Demand Side Management" Proceeding IEEEIVol.73,NO. 10,0ctober, 1985.

K.Stern and B.Wait,"The potential for load management in selected industries" EPRI EA-1821-SY Project 1212.3 April 1981.

"COGENERATION TECHNOLOGY" Short course,University of Wisconsin-Madison, Dallas,Texas,January 1988.

F.E1-Mahelwi and H.E1 Nakib,"Cogeneration report of EL-Nasr Company for Coke and Chemicals",Report, Organization for Energy Planning(OEP),Dec. 1988.

S.Anis, "Economic Evaluation of Energy Conservation Projects" ,Energy Conservation short course, OEP, Cairo,1989.

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