MINIMUM-EMISSION DISPATCH

M. R. Gent

Dept. of Water and Power

City of Los Angeles

John Wm. Lamont

Univ. of So. California

Los Angeles, Calif.

Abstract-A program has been developed for on-line steam unit

dispatch that results in the minimizing of Nitrogen Oxide emissions.

A unique mathematical representation of the steam generating units

coupled with a Newton-Raphson convergence technique for dispatch

produces base points and participation factors for any load level and

any unit configuration. Emission reductions and corresponding cost

increases are compared to standard economic dispatch.

INTRODUCTION

Economy dispatch is defined as supplementary regulation applied

to the speed governors of the generators operating within a controlled

system for the purpose of allocating generation changes on an optimum economy basis.1 Minimum emission dispatch is a similar type

of supplementary regulation used to minimize the total stack emission

of nitrous oxides for the entire power system. Although this supplementary regulation may be controlled either manually or automatically, this paper presents the logic used in an actual program to control unit loading automatically and compares results obtained by

minimum emission dispatch (MED) and economic dispatch (ED).

Since the beginning of the free enterprise system, man has always

tried to maximize his profits while reducing his expenses. Prior to

1940, most utilities tried to minimize cost by supplying light loads

from the most efficient plant or plants.2 Power to meet increasing

system load was supplied by the most efficient plant until that plant

reached its point of maximum efficiency. Further increases in system

load were supplied by the next most efficient plant in a similar manner;

each plant was added in terms of its efficiency. When it was finally

accepted that this method failed to minimize cost, the use of the incremental fuel cost method was developed and put into use. This second

method also had its shortcomings for most power systems, since

transmission losses were neglected.3

4 In 1943, E. E. George produced a paper which presented

a transmission-loss formula including transmission losses as function

of the powers of the individual sources. Since then, many distinguished personnel from the power industry have written numerous

papers pertaining to economic dispatch and penalty factors.5'6'7'8

In the past few years the power industry has been shocked by

that element of society referred to as "ecologists". At first, there

was emphasis on beautification, both underground, and overhead,

followed by the multitude of arguments against nuclear plant sites.

All of these objections to power system facilities have been well

founded; however, no public outcry has ever been as loud or

as justified as the plea for clean air. For example, a number of utilities

have been temporarily thwarted in their attempts to build much needed

thermal fossil fuel generating stations.

Minimum cost can no longer be the goal of operation if society

is to continue to exist. Many organizati-ons, including the utilities,

realize the necessity of cleaning up our environment as evidenced

by the planned phase-out of coal as a steam plant fuel and the regulatory agencies' insistence on the burning of low-sulfur fuel oil.

Minimum emission dispatching is one method which all power utilities

have within their grasp to help fight the battle against air pollution.

Paper 71 C 26-PWR-I-A, recommended and approved by the Power System Engineering Committee of the IEEE Power Group for presentation at the

1971 PICA Conference, Boston, Mass., May 24-26, 1971. Manuscript submitted

January 1 3, 1971; made available for printing June 9, 1971.

ECONOMIC DISPATCH

Based on the results of studies,. the Los Angeles Department.

of Water and Power (DWP) concluded that for an interim period

transmission losses could be neglected without introducing significant

error into its dispatch calculations. Hence, economic dispatching

(ED) is done based on the solution of the familiar equation: 2,3

dFn =

dPn

SN (1)

where

Fn = input to plant n in dollars per hour

Pn = output from plant n in megawatts

X = incremental cost of received power in dollars per megawatthour

subject to the following constraint:

k

£ pn -- PR 0°(2 (2)

n=1

where

PR = total power received by the loads connected to the trans- mission system.

Thus, economic dispatch is achieved by solving a set of nonlinear equations in such a manner that the total cost is minimized

for a particular system load. The representation of the individual

generators is discussed in a later section.

MINIMUM EMISSION

Minimum emission dispatching (MED) may be required by governmental and regulatory agencies in the near future to control and

reduce air pollution. Many factors determine how power plants contribute to air pollution. The following factors should be included:9

1. Type and grade of fossil fuel employed.

2. Proximity of plant sites to heavily populated areas.

3. General topography and geography of area.

4. Prevailing climate and meteorological conditions.

5. Proximity and number of other industries in relation to power

plant sites.

6. Concentration of power plants in any given urban area or

city district.

For some or all of the above factors, regulatory agencies, including

the Air Pollution Control District of Los Angles County (APCD),

might decide to limit power plant stack emissions in certain areas

which have high concentrations of contaminants.

MED may be accomplished by substituting a different set of

generator representations into the economic dispatch program. The

MED generator equations for each unit are functions of nitrous oxides

(NOX) versus megawatt output, instead of input (cost of Btu's) versus

megawatt output for ED.

The normal minimum emission program minimizes the total

system output of NOX for a given system load. As one might suspect,

however, while the sum of 'the parts is minimized, each part is not

necessarily minimized. Using the normal condition (ED) as base, it is

2650
quite natural that, while the total number of tons of NOX emitted into

the atmosphere is less while on MED, the individual plant's participation in the total pollution may have increased. For various reasons,

it may be desirable to limit a particular plant or plants to a maximum

percent increase over ED.

A second program (MEDPC) has been developed which limits

the total stack emission from any plant to a given precent- increase,

over the normal ED emission level.

The MEDPC program operates in the following manner:

1. For a given system load the ED program is solved.

2. The NOX emission for each plant is calculated.

3. For any plant whose NOX emission is to be limited during

MED, the megawatt output which would produce the maximum allowable NOX emission is calculated. The new unit maximum load is the

smaller value of the number just calculated for allowable NOX and the

maximum unit rating.

4. The MED program is then solved for the same given system load using the new unit maximum calculated in the previous

step.

GENERATOR REPRESENTATION

All of the Department's steam-fired units have been tested at

25%, 50%, 75%, and 100% of rated load to determine the Btu input

and NOX emission at these levels of load. The results from one of

the NOX emission tests is shown in Figure 1 in the Appendix.

Mathematically, these curves of NOX output in Tons/Hour as

a function of Net Output in megawatts have been represented by

the equation

Y = Al + A2X + A3e A4X +A5eA6X, (3)

which is a combination of a straight line and two exponentials. Because of the limited number of data points, equation 3 has been reduced to

Y = A1 + A2X + A3Ae (4)

The functional relationship thus described between NOX output and net power output for each generator unit is substituted in

the dispatching program to achieve MED; whereas the customary

Btu input-megawatt output function of the same form is used by the

dispatching program to achieve ED.

The development of the coefficients A1, A2, A3 and A4 for either

minimum emission dispatch or economic dispatch is a relatively simple

procedure. A flow chart (Figure 2) and brief explanation of the solution procedure have been included as an Appendix.

It is the opinion of the authors that this function (Eq. 4), when

used to represent each unit, has several advantages, including:

1. The function is monotonically increasing.

2. It eliminates the inaccuracies and cumbersome calculations

required of straight-line segments.

3. Unlike a polynomial, all derivatives exist.

4. Most importantly, it appears to be the truest and most accurate representation.

THE COMPUTER SYSTEM

The ED-MED program is presently being utilized in a quasi online state by the DWP Load Dispatch Headquarters. DWP is presently

converting from the Leeds and Northrup Load Frequency Control Equipment, described in Reference 5, to an all-digital system

which includes two on-line IBM 1800 process control computers

interconnected with an IBM 360/65. Automatic execution of the program will occur when a change is made in unit configuration, unit

minimum or maximum limits, fuel type or fuel price.

Presently, a combination of the two systems is in use. Two

CRT's (IBM 2250's) are located in the immediate proximity of the

dispatcher through which he initiates the execution of the program.

The primary IBM 1800 accepts the data supplied through the

CRT (such as a unit change) by the dispatcher. Changes are made

by the use of a light pen on the input display shown in Figure 4 of

the Appendix. The input data is then transmitted to the IBM 360

over a 5000 foot underground communication line. An immediate

interrupt occurs within the IBM 360, resulting in the execution of

the ED-MED program, Upon completion, the results are returned to

the initiating IBM 1800 and displayed on the CRT for the dispatcher.

Figures 5 and 6 are actual copies of the displays containing the results.

Until such time as the IBM 1800's assume the complete role,

it is necessary for the dispatcher to transfer the results to the L&N

Analog equipment. In order to prevent error and for convenience,

a "copy" feature has been included that provides a "hard copy"

on a temporarily installed printer. This function is activated by lightpenning "COPY" as shown on the displays (Figures 5 and 6).

THE PROGRAM

The basic computer program can be coded in 60-100 statements

in either PL/l or Fortran. As with most operational programs, the

core requirement is largely a function of the Input/Output. The flow

chart is shown as Figure 3.

In most applications a comparison of ED versus MED is desirable

as output. For dispatching purposes it is also necessary to have output

for an Economy Energy quote. Such an output featuring incremental

and decremental costs for 100 MW increments is shown as a display

in Figure 7.

The mechanics of the program are such that an input key is examined to determine whether ED, MED or both are desired. The ED

output is always generated first, if both are required, and then the

generator coefficients and necessary variables are loaded to perform

the MED dispatch. MEDPC, as previously indicated, requires prior

execution of ED.

Execution time of the Load Dispatcher's version varies with the

availability of the IBM 360/65 but averages to about 30 seconds from

CRT input to CRT output. Actual 360 CPU time is 3.5 seconds depending on the particular unit configuration and possible unit loading

limitations.

PRODUCTION PLANNING

Presently, steam units are committed to service based upon the

daily spinning reserve requirements and economics.10 Eventually,

it is anticipated that agencies will require units to be deployed on a

minimum emission basis (either MED or MEDPC) as opposed to the

present economic basis. Preliminary investigations from a computer

program being developed indicate little, if any changes, will be required

in commitment priorty schedule of units.

Nearly all of the programs using dispatch techniques have been

modified to handle MED. All production planning and fuel-use studies

require comparisons of the two methods of dispatch and the results

to indicate effective reductions and increased costs of operation.

COMPARISON OF DISPATCHING METHODS

To show how emissions of NOX are reduced and costs are increased, four examples were prepared incorporating a particular configuration of DWP steam units. For the example, only steam load is

required and no particular attention is given to hydrothermal coordination.

Daily steam load patterns consisting of twenty-four values were

studied for the following four cases:

1. Typical summer peak load day.

2651
TABLE I. COMPARISON OF MINIMUM EMISSION DISPATCH AND ECONOMIC DISPATCH

MWHRS

PLANT ED MEDPC* NED

HARBOR 588 991 887

VALIEY 6,704 7,816 11,834

SCALTERGOOD 5,383 6,540 5,680

HAYNES 35,951 33,279 30,225

TOTAL 48,626 48,626 48,626

NET DIFFERENCE

PER CENT DIFF.

TYPICAL SUMER PEAK LOAD DAY

TONS OF NOX MEGABTUS

ED MEDPC* NED ED NEDPC* ED

0.86 1.57 1.34 7,257 11,160 10,121

6.56 7.88 12.72 67,260 77,594 117,718

5.30 7.84 5.92 50,210 60,984 52,948

47.57 39.20 32.71 313,173 290,629 265,012

60.29 56.49 52.69 437,900 440,367 445,799

-3.80 -7.60 +2,467 +7,899

-6.30 -12.61 + 0.56 + 1.80

COST IN DOLLARS

ED MEDPC* NED

2,413.65 3,711.73 3,366.23

22,370.12 25,807.20 39,151.66

16,699.07 20,282.44 17,609.68

104,157.40 96,659.55 88,140.09

145,640.24 146,460.92 148,267.66

+820.68 +2,627.42

+ 0.56 + 1.80

PLANT ED

HARBOR-- 513

VALLEY 4,948

SCATTERGOOD 4,026

HAYNES 32,644

TOTAL 42,131

NET DIFFERENCE

PER CENT DIFF.

PLANT ED

HARBOR 488

VALLEY 4,288

SCATTERGOOD 3,416

HAYNES 27,361

TOTAL 35,553

NET DIFFERENCE

PER CENT DIFF.

PLANT ED

HARBOR 480

VALLEY 3,36o

SCATTERGOOD 1,920

HAYNES 17,567

TOTAL 23,327

NET DIFETRENCE

PER CENT DIFF.

MWHRS

MEDPC* MED

877 755

5906 10,862

5,592 4,680

29,756 25,834

42,131 42,131

MWHRS

NEDPC* NED

749 656

5,030 8,880

4,530 3,846

25,244 22,171

35,553 35,553

MWRS

NEDPC* MED

527 499

3,680 4,742

2,794 2,622

16,326 15,464

23,327 23,327

ED

0.77

4.7

3.28

40.33

49.12

ED

0.75

4.08

2.46

32.02

39.31

TYPICAL SUMNER MIIMUM LOAD DAY

TONS OF NOX MEGABTUS

MEDPC* NED ED NEDPC* NED

1.32 1.10 6,546 10,023 8,830

5.70 11.16 51,436 6o,054 108,088

3 5.74 4.02 38,200 52,126 43,868

331.84 24.84 284,006 261,011 228,257

?44.6o 41.12 380,188 383,214 389,,043

-4.52 -8.00 +3,026 +8,855

-9.20 -16.29 + 0.80 + 2.33

TYPICAL WINTER PEAK LOAD DAY

TONS OF NOX NEGABTUS

MEDPC* NMED ED NEDPC*

1.11 0.95 6,342 8,795

4.78 8.94 45,594 52,200

4.o8 2.88 32,864 42,664

25.09 19.93 239,896 223,676 a

L35.o6 32.70 324,696 327,335

-4.25 -6.61 +2,639

-lo.81 -16.82 + 0.81

MED

7,892

89,356

36,566

198,094

331,908

+7,212

+ 2.22

TYPICAL WINTER MNIMM LOAD DAY

TONS OF NOX MEGABTUS

ED MEDPC* NED ED MEDPC* NED

0.74 0.79 0.76 6,272 6,696 6,44o

3.26 3.54 4.52 37,516 4o,346 50,050

1.02 1.68 i.48 20,024 27,472 25,988

17.33 13.62 12.29 158,962 149,944 142,786

22.35 19.63 19.05 222,774 224,458 225,264

-2. 72 -3.30 +1,684 +2,490

-12.17 -14.77 + 0.76 + 1.12

COST IN DOLLA

ED NEDPC*

2,183.21 3,333.62

17,107.42 19,972.76

12,704.76 17,336.60

94,456.27 86,809.05

126,451.66 127,452.03

+1,000.37

+ 0.79

ED

2,109.

15,164.(

10,930.

79,786.:

107,989.'

ED

2,085.E

12,477.C

6,659.(

52,869.:

74,091.

LS

3'1

71

12C

+r

COST IN DOILARS

NEDPC*

25 2,925.08

02 17,361.58 2c

34 14,189.68 1i

17 74,391.95 6r

78 108,868.29 llC

+ 878.51 +'

+ 0.81 +

COST IN DOLLARS

NEDPC*

38 2,226.88 2

20 13,418.22 1(

62 9,136.84 E

11 49,869.60 47

31 74,651.54 71

+ 559.73 4

+ 0.76 4

NED

2,936.89

5,948.82

4,589. 82

5,915.42

9,390.95

2,939.29

2.32

NED

2,624. 71

9,718, 70

2,161.16

5,883. 26

0,387.83

2,398.05

2.22

NED

2 8141.o

6,645.90

8,643.60

7,488.59

4,919.89

+ 828.08

+ 1.12

*NOTE: VALLEY PLANT is limited to a 20% increase in NOX Emission under Minimum Emission Dispatching (MEDPC).

2652
2. Typical summer minimum load day.

3. Typical winter peak load day.

4. Typical winter minimum load day.

Table 1 is a brief synopsis of the results of the examples.

It is interesting to note that a comparison of the two methods

ED and MED, applied to a "Typical Summer Peak Load Day", indicates that an increase in fuel consumption and cost on the order of

1.8 percent results in a sizable NOX decrease of 7.6 tons per day or

12.6 percent.

Each utility must consider a reduction of this nature in its proper

perspective. From Reference 11, power plants are responsible for 57

percent of the daily NOX emissions from stationary sources in Los

Angeles County. After consideration is given to transportation, power

plant contribution to NOX emissions reduces to 14 percent of the

total tons per day. Hence if all power utilities in Los Angeles County

were to employ MED with similar results, the NOX emissions could

be reduced by 1.8 percent.

Therefore, considering no action other than conversion to MED

by electric utilities in Los Angeles County, the percent cost - percent

benefit ratio appears to be 1. That is, for every one percent increase

in fuel cost resulting from MED, a benefit of one percent decrease

in contamination of the atmosphere from NOX is enjoyed.

INCREMENTAL COST

5. Research is also needed in determining the feasibility of

emission dispatching based on multiple emission reduction such as

NOX and S02.

Future plans call for continued work in emission dispatching

including an attempt to find a suitable method for incremental cost

using emission dispatching and investigation into S02 emission dispatching. Although methods expressed in this paper are not new,

the applications are. Using the methods outlined in this paper, the

power industry has another tool in its hands to aid in curbing air pollution.

APPENDIX

Derivation of generator representation equation coefficients.

Source of Data

An elaborate test program is presently underway to insure that

unit representation is always as correct as possible. It is hoped that

continuous stack-gas monitoring equipment will be purchased and that

a mobile laboratory will soon be ready.

The results of a typical NOX emission test are shown in Figure 1.

HAYNES 3 8 4

Most power utilities, either through pooling agreements or interchange agreements, have economy energy provisions for transactions

with neighboring systems. These transactions generally involve incremental and decremental costs.

In fact, nearly all recent contracts call for energy costs to be

based on incremental costs where energy types range from emergency

to economy.

Figure 8 shows the futility of the incremental and decremental

principles when applied to a system of fossil fuel units operating on

MED. The smooth contiguous curve is, of course, the incremental

fuel cost for any system load level using ED. The seemingly random

points falling both above and below the ED curve are what the authors

feel is the incremental cost of one megawatt dispatched by the MED

program for all load levels attainable with the particular set of units

used in this example.

It is hoped that further investigation and perhaps closer tolerances will uncover a method of computing incremental costs that

will be meaningful.

CONCLUSIONS

In general, the following conclusions have been reached:

1. Reduced NOX emission is possible through systematic scheduling.

2. MED-MEDPC scheduling results in higher operating costs.

3. Better public relations may be obtained by a utility whose

actions show concern for the plight of the environment.

4. Utilities need to inform the general public of their contribution to pollution and what they are doing to reduce and eliminate

the various forms of pollution.

With regard to the further development and use of the MEDMEDPC scheduling, these further conclusions should be stated:

1. MED or MEDPC is an extremely simple program to implement regardless of whether plant or unit dispatch is employed.

2. The two to three percent loss in efficiency may be an excellent

investment in clean air and public relations.

3. Definite improvement is needed in the methods of obtaining

and the accuracy of the emission output data.

4. Further research is needed in implementing transmission losses

and NOX emission dispatching.

.301 __X

D <XX-t~~~~~~-/ I --

I 0-v-r---~ _-_

HK .1 -i-KY

0 11

100 200 300

NET MEGAW^ATTS

E3 DWP TEST DATA

9) APCD DATA

Fig. 1. Typical NOX Emission Test Data

Problem:

It is necessary to fit a given number of data points by a function

of the form:

Y = A + Bx + CeDX.

Using the least square criteria as a standard for goodness of fit,

it becomes necessary to find a minimum value of S, where

n

S =E (Yi Y i) *(A2)

S is a function of the variables A, B, C, and D. S is minimized

by taking the partial derivatives of S with respect to A, B, C, and D

and setting them equal to zero.

2653

(Al)
Complications are introduced, however, due to the presence of the

exponential term. This prohibits the partial derivatives from becoming

linear equations. This obstacle can be overcome by assuming a value

of D and solving the set of linear equations obtained by taking the

partial of S with respect to A, B, and C and setting them equal to

zero.

The resulting set of equations in matrix form is:

An iterative process is employed whereby repeated values of Dn+1 are

'used in the solution of equations A3 through A5 until the change in

D is less than a predetermined tolerance.

Equation Al can now be solved with any value of MW (X),

using the coefficients obtained through the described method of solution, for the corresponding NOX emission. Similar results for ED

are obtained by using Btu's instead of NOX emission.

N

~EXi

Dxi e

Xi rE eDxi

Xi x e

Z xeDxi xi e2Dxi

YiI

! xiyi

Dxi

{ie

0

_ -_

A

B

C

where D has been initially assumed.

There exists a value of D which satisfies

necessary condition that aS = 0. Since

aD

equation A3 and the

as 2 Dxi Dx

aD = 2 Z~Cxie (A+Bxi+Cel .-Lyi) =0° (A4)

D cannot be obtained directly. The suggested approach is the use of

the Newton-Raphson technique for the next approximation of D as

shown in A5.

f(Dn)

f'(Dn)' where f(D) =a-. (A5)

\ Input: Generator coefficients,

minimums, maximums, commitment,

and fuel costs

LCalculate unit incremental rates

at unit max and mins

1.

I Set all unit outputs to minimum I

Input: Load requirement

Calculate unit first derivatives

(incr. rate) and 2nd derivatives

Calculate average incr. rate

Do all unit incr. rates

NO compare within tolerance YES

of the average?/

Output: Unit Mws/

Calculate new unit outputs using

Newton's Method for distributing

..

residual power - ~~~~~~~~~~~I

Fig. 3. ED or MED Program - Basic Flow Chart

Fig. 2. Generator Coefficient Program Basic Flow Chart

REFERENCES

[1] N. Cohn, Control of Generation and Power Flow on Interconnected Systems, New York: Wiley, 1961.

[2] W. D. Stevenson, Elements of Power System Analysis, New

York: McGraw Hill, 1962.

[3] L. K. Kirchmayer, Economic Operation of Power Systems,

New York: Wiley, 1958.

[4] E. E. George, "Intrasystem Transmission Losses," AIEE Transactions, vol. 69, Part I, 1950, pp. 626-631.

[5] P. G. Lubisich, "Use of Computers in Generation Scheduling,"

AIEE CP-60-1397.

[6] P. G. Lubisich, "Penalty Factors from Power-System Equations,"

AIEE Transactions, August 1958, pp. 494-501.

[7] J. B. Ward, "Economy Loading Simplified", AIEE Transactions,

December 1953, pp. 1306-13 12.

[8] A. F. Glimn, L. K. Kirchmayer, V. R. Peterson, G. W. Stagg,

"Accuracy Considerations in Economic Dispatching of Power

Systems - I," AIEE Transactions, December 1956, pp. 1125-1137.

[9] G. D. Friedlander, "Power Pollution and the Imperiled Environment - II", IEEE Spectum, December 1971, pp. 65-75.

[10] P. G. Lowery, "Generating Unit Commitment by Dynamic Programming", IEEE Trans. Power Apparatus and Systems, vol.

85, May 1966, pp. 422.

[11] Profile of Air Pollution Control in Los Angeles County Los

Angeles: Air Pollution Control District, January 1969.

2654

I
GENERATION DISPATCH INPUT DATA

HARBOR

UNIT i

UNIT 2

UNIT 3

UNIT 4

UNIT S

VALLEY

UNIT I

UNIT 2

UNIT 3

UNlT 4

SCATTERGOOD

UNIT i

UNIT 2

HAYNES

UNIT i

UNIT 2

UNIT 3

UNIT 4

UNIT 5

UNIT 4

IN/OUT MAX NET LIMIT

MW

0

0

0

0

I

I

I

I

I

I

I

I

I

I

I

I

018

Oil

0t4

i3

i'3

115

11i

233

234

232

234

344

MIN NET LIMIT

MW

020

020

020

020

020

030

030

O-qo

040

0'0

150

150

GAS PRICE .

ECON SCHED

ENERGY QUOTE

EMIS SCHED

OIL PRICE .34810

CIL

*GAS

EXECUTE

CONF I RM

RESET

Fig. 4. Generation Dispatch Input Data Display

2655

SAVE

MASTER

+Oj.t 2 3 4

- 5 4 1 8 I*
MO DA T I ME

11 02 0ol0

ECONOMIC DISPATCH SCHEDULE

DWP HARBC

STEAM BASE P

2414

2 00

-2o0

2400

2300

2200

2100

2000

too0

1800

1100

I'40

150oo

1400

1300

1200

1100

1000

ENERGY

MASTER

tt

'3

41

32

21

24

23

22

21

21

21

21

21

21

21

21

21

21

OUOTE

JR VAL

)ART BASE

540

48

508

22

44'

312

5

33'

3

210

1

2

244

218

244

184

0

144

0

144

144

0

144

0

144

0

.144

0

144

0

144

GAS

GEN INPUT

.LEY SCATTERGOOD

PART BASE PART

3'4

42 10 35'

*2 14

340

54 14

324

54 .13

41313

301

24 1

214

22 8

284

2# 8

218

34 ¶

241 40 10

251 0 21

238 13

225

0 0

225 0 0

225

0 0

225 0 0

225

0 0

225

PRICE .3iX15

ECON SCHED E

HAYNES 1-4

BASE PART

*s5 oS 04

¶ 5

0

* 5

0 "45 13 152 5'

5' 840

52 188

q48 140

40 100

4

'3'

48

548

14 4¶2

12

420

12

348 58

210

2

288

OIL PRICE

EMIS SCHED

HAYNES 5-&

BASE PART

108

108

108

485

'5'

'33

*21

408

5S15

584

514

5"1

542

518

410

442

420

322

.34810

COPY

0

0

23

24

24

12

13

t 3

13

10

15

1I

24

28

28

42

l8

Fig. 5. Economic Dispatch Schedule Display

2656
DAT8IME

1 02 0l00

MINIMUM EMISSION SCHEDULE

-HARBOR

BASE PART

52 4

48

4

44 2

1 3 3, 3 33 ,

3' 2

3 3

1

32 2

22

2s ,

25 2

2 2

23 2

22 I

21

0

21 0

21

tUOTE

VALLEY

BASE PART

540

540

540

534

524

514

50

484

414

442

448

41i

314

330

212

208

144

144

GAS

GEN INPUT

0

0

.to

14

10t2

12

14

32

40

58

4

4

0

PRICE

ECON

SCATTERGOOD HAYNES 1-4

BASE PART BASE PART

~~~0

15

34¶ X5

18

333 ¶41

12 34

321 ¶13

34

310 81¶

32

211 841

33

288 814

40

232 154

5'

214 #8

58

210 440

1 53

2X3 581

5 54

258 533

5 41

253 48 1

4 31

241 44¶

3 32

24 4 11

4 32

242 385

11 83

225 302

.3ti15 OIL PRICE

SCHED EllIS SCHED

HAYNES 5-4

BASE PART

108

41t

5¶8

542

50o

458

418

381

358

334

314

308

308

308

308

308

308

3108

.34810

COPY

38

81

5'

42

42

40

31

23

24

20

0

0

0

0

0

Fig. 6. Minimum Emission Schedule Display

2657

DWP

STEAM

2400

2400

2300

2200

210O

2000

¶ 00

180o

1100

1 00

15o0

1400

1 300

1200

1100

1000

ENERGY

MASTERt
MO DA TIME

I 1 02 0,00

ECONOMY ENERGY QUOTES

MILS PER KWH

MW

2400

2500

2400

2300

2200

21O0

2000

100

1100

1'400

1400

1300

1200

1100o

-1 00MW

3.4144

3.2115

3. 1 1 1 4

3.0151

3.013k

2.1182

2.142k

2.1101

2.8834

2.8505

2.8120

2.1411

2.111k

2.4143

2.4352

2.5820

0 MW

3. 4148

3.3111

3. 2210

3. 1 135

3.0344

2.11 1

2.1515

2.1253

2.8158

2 .81 10

2.8301

2.1140

2.1418

2. 114

2.4552

2. 152

+ 1OMW

3.1508

3.4144

3.2115

3.1114

3.0151

3.0 151

2. ¶182

2.142k

2.1101

2.8834

2.8505

2 .8120

2.1 11

2. *11k

2. 143

2.3352

ENERGY QUOTE GAS

MASTER GEN INPUT

PRICE .31415

ECON SCHED

OIL PRICE

EMIS SCHED

Fig. 7. Economy Energy Quotes Display

2658

.3C810

COPY
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'Fotal Net Generation In MW

190 2000 

Fig. 8. Incremental Fuel Cost Curves for ED (Solid Line) and MED (Points)

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Discussion

Norton Savage (Federal Power Commission, Washington, D.C,): The

paper describes an ingenious application of the incremental loading

technique to minimization of a factor other than cost: emission of

nitrogen oxides by a fossil steam boiler. Efforts such as tlhis, to apply

existing methods for new purposes, are to be encouraged.

The authors' remarks regarding further investigation with respect

to minimum emission of sulfur oxides, are of interest. Have they

made any analysis of the relationship between emission of NOX and

sulfur oxides and/or particulates? A useful study would be an examination of total volume of pollutant emission as affected by the programs described. Since the system-wide reduction of NOX emission

is achieved at the expense of an increase in fuel consumption, it would

appear that the quantity of other pollutants may be increased. If such

increase does take place, it would be in order to evaluate the relative

undesirability of the nitrogenous compounds and the other emissions.

Several questions come to mind regarding the function used by

the authors to represent the relationship between NOX output and

generator net power output. First, a least squares polynomial fit

could be obtained by standard procedures without the necessity of an

iterative program. Did the authors find the exponential a better fit

to the test data for all the plants? Second, for a common-header

system, will the constants of the equations change significantly for

the various possible combinations of boilers in service? Third, if boilers (common-header or unit type) are equipped to burn more than

one kind of fuel individually or in combination, will the constants

change significantly as the mix of fuels changes? It would seem that

even if a single fuel such as coal is used, the constants of the NOXoutput formula would be strictly valid if very tight quality control were to be exercised on the coal supply source.

One further remark is in order regarding Figure 8 of the paper.

The figure seems to indicate that system loads less than 1550 MW

(approximately) always result in minimum-estimate incremental costs

that are greater than economic dispatch cost, but loads greater than

1550 MW will in many instances result in minimum-emission incremental costs being less than economic dispatch costs. Would the authors

care to comment on this seeming anomaly?

The views expressed herein are those of the author and do not

represent an official statement of the Federal Power Commission.

Manuscript received June 1, 1971.

L. S. VanSlyck (American Electric Power Service Corporation, New

York, N. Y. 10004): In the opinion of this discusser, the authors

have taken a "have solution, will find problem" approach in their

philosophy of air pollution control. They have sought to minimize

a cost function subject to certain constraints when the philosophy

should have been to eliminate the problems at their source rather than

to "live with them" as it were. What they propose should have been

recommended only as a temporary amelioration of pollutant emission

for existing facilities until plant equipment modification or fuel conversion, or more effectual solutions could be found and implemented.

The true solution to noxions gas emission by power plants is

one of elimination rather than control, or as the authors propose

"optimization". The authors are referred to a recent authoritiative

and most significant paper in this area (1).

REFERENCE

[I] Sporn, Philip, "Our Environment-Options on the way into the

Future". IEEE Spectrum, May 1971, pp. 49-58.

Manuscript received June 10, 1971.

M. R. Gent and John Wm. Lamont: The authors wish to thank Mr.

Savage for his excellent comments. The Department of Water and

Power does not burn coal in its Los Angeles area power plants, the

primary fuel being natural gas, supplemented by low-sulfur, low ash

fuel oil during curtailment. Natural gas firing results in approximately

one thousand times the amount of oxides of nitrogen as oxides of

sulfur. Since, as in our summer peak day example, the amount of

natural gas used is increased only 1.8 percent while the oxides of nitrogen are reduced 12.6% while on MED, the total amount of pollution

is reduced. As far as we can determine, sulfur oxides are directly

proportional to the number of btu's burned and could best be controlled by btu dispatch if they are determined to be the pollutant of

chief concern.

The exponential curve fit was chosen as a generator representation for several reasons. They include:

a. A better representation than with a polynomial.

b. All derivates are continuous and the functions are always

monotonically increasing.

c. Same number of coefficients are always necessary.

Although an iterative approach is required to evaluate the coefficients

for an exponential curve fit, it is necessary to calculate these constants

only once. The initial value assigned to the "D" coefficient seems to

have little effect on the CPU solution time.

The Department of Water and Power does not have any commonheader plants and such systems were not considered. The constants

would probably change significantly for the various combinations in

a common-header system. It should be possible, however, to modify

the program to accept common-header plants by either generating

coefficients at the time of program execution or storing several sets

of coefficients.

With regard to multi-fuel firing, the Department uses natural

gas, switching to oil only when sufficient natural gas is not available.

It is not our normal practice to burn in the mixed fuel mode for extended periods. We have not seriously examined the condition of

mixed firing in individual units or on the system. On the DWP System,

fuel oil logistics determine where and how much oil is burned. Testing

would be required to adequately represent generators under mixed

firing as well as the common-header conditions mentioned by Mr.

Savage.

We perhaps took too much liberty in defining incremental cost

as the cost of the next megawatt. The curve and points of Figure 8

would seem to indicate the incremental cost at 2000 mw is less while

on MED than ED. Comparing the cost of each megawatt before the

2001st shows an average of 3.048 $/mwh for MED and $2.989/mwh

for ED. Since cost plays no part in MED, the next increment of power

could very easily cost less while maintaining equal incremental emission rates.

In reply to Mr. Van Slyck, electric utilities, including American

Electric Power, have many problems; one of the largest and most

costly problems being air pollution. If this discusser had taken the

time to thoroughly read this paper, he would have seen the material

proposed by the authors was presented only as an interim solution.

Moreover, an inquiry on Mr. Van Slyck's part would have enlightened

him to the fact that minimum emission dispatching has been required

by the governmental control agencies pf California.

Fuel conversion has become outmoded as a solution. All steam

plants in Los Angeles County have burned only natural gas when

available, supplemented by low-sulfur fuel oil (less than 0.5% sulfur

by weight) since January 1964. Few utilities, including Mr. Van Slyck's,

have operated with these stringent limitations.

The authors believe the elimination of oxides of nitrogen to

be impossible as long as fossil fuels are burned at high temperatures;

however, interim solutions should be considered until such processes

as off-stoichiometric burning are fully explored. Other utilities may

soon be faced with regulations limiting the amount and types of fuel

used as well as the amount of pollution generated. Hopefully, the

ideas presented will aid in an interim solution until elimination of

air pollution is reasonably feasible.

Manuscript received July 6, 1971.

2660