7/28/2019 0201.pdf

1/9

Steam Turbine Optimization

Andrew D. Gavrilos, P.E.ManagerCore Technology TeamABB/ETSI

Natrona Heights, PA 15065

KEYWORDS

Extraction Turbines, Industrial Turbines, Industrial Power House, Tie-Line Control, Steam TurbineOptimization, Turbine Control Systems

ABSTRACT

This paper discusses a supervisory program installed in the powerhouse for a domestic paper mill thatoptimizes the operation of the two extraction steam turbines. The powerhouse has a contract with thelocal utility to purchase power based on "real time pricing" where the purchase price remains fixed inany given hour but varies from hour to hour. For each hour in the day, the optimization programcompares the cost to purchase power against the calculated cost to produce power by both condensingsteam and venting steam to atmosphere. Based on this comparison, the optimization program operatesthe turbines in one of three modes:

Mode 1 - Maximize purchased power by minimizing generation and condensed steam.Mode 2 - Minimize purchased power by maximizing generation while condensing steam.Mode 3 - Minimize purchased power by maximizing generation by first condensing steam and then

venting steam to atmosphere.

The optimization strategies are overridden by plant steam conditions, as the first priority is to alwaysmaintain the plant steam headers to the paper mill.

INTRODUCTION

The plant steam system (see Figure 1) was designed with 4 main steam headers. The 850# steam headeris the main boiler header and is supplied by 2 recovery and 3 power boilers. The 425# steam header isused for powerhouse auxiliaries and is supplied by a single power boiler and the extraction from TG#1.The 165# steam header supplies steam to the mill and is supplied by the HP extraction from TG#2. The65# steam header supplies steam to the mill and is supplied by the exhaust from TG#1 and the LPextraction from TG#2.

Menu Print

7/28/2019 0201.pdf

2/9

Vent toAtmospherePRV

PRV

PRV

PRV PRV

Power

Boiler #6

Recovery

Boiler #5

Power

Boiler #4

Power

Boiler #3

Recovery

Boiler #2

Power

Boiler #1

850# Steam

Header

425# Steam

Header

165# Steam

Header

65# Steam

Header

TG #1 TG #2

Condenser

Figure 1

Plant Steam Diagram

There are five pressure reducing valves (PRVs) that supply steam to the different headers, one850#/425# PRV, one 425#/65# PRV, two 425#/165# PRVs and one 165#/65# PRV. There is also an

exhaust vent to atmosphere on the 65# steam header.

Turbine generator #1 is a single automatic extraction, non-condensing turbine supplied with 850# steamthat extracts steam to the 425# steam header and exhausts steam to the 65# steam header. The megawattload controller can operate in either Manual mode, where the operator adjusts the station output orAutomatic mode, where the operator adjusts the megawatt load setpoint. Instead of using the megawattload controller, the exhaust controller can be placed in Automatic mode, where the operator adjusts theexhaust pressure (65#) setpoint. The exhaust pressure controller is a new operating mode that did notexist with the original turbine controller and is now the desired mode of operation. The extractioncontroller can operate in either Manual mode, where the operator adjusts the station output or Automaticmode, where the operator adjusts the extraction pressure (425#) setpoint. The turbine controller is

configured for extraction priority, which will satisfy extraction steam flow first at the sacrifice ofmegawatts and exhaust (65#) steam.

Turbine generator #2 is a double automatic extraction, condensing turbine supplied with 850# steam thatextracts steam to the 165# and 65# steam headers. The megawatt load controller can operate in eitherManual mode, where the operator adjusts the station output or Automatic mode, where the operatoradjusts the megawatt load setpoint. The HP extraction controller can operate in either Manual mode,where the operator adjusts the station output or Automatic mode, where the operator adjusts the

Menu Print

7/28/2019 0201.pdf

3/9

extraction pressure (165#) setpoint. The LP extraction controller can operate in either Manual mode,where the operator adjusts the station output or Automatic mode, where the operator adjusts theextraction pressure (65#) setpoint. The desired mode of operation is to keep the 65# extraction steam toa minimum. The turbine controller is configured for HP extraction priority, which will satisfy HPextraction steam flow first, LP extraction steam flow second and megawatts last.

As a basis for control, the optimization program uses a Fixed Demand Tie-Line Control scheme withoperating constraints imposed on the control scheme based on plant operating conditions. In addition totie-line megawatt control, the optimization program provides tie-line power factor control and can alsoprovide plant frequency control when operating in the isolated grid or island mode. The optimizationprogram is integrated into the plant wide distributed control system that includes; boiler controls,extraction turbine controls, power house auxiliary systems, and PRV controls (see Figure 2).

Figure 2

Power House Distributed Control System

Most of the inputs required for the optimization program are transmitted to the control processors via thecommunications highway. Field I/O that is directly connected to the optimization program includes thetie-line megawatt and megavar pulses from the utility meter and the instantaneous values for megawattsand megavars from local mounted transducers.

REAL TIME PRICING

Traditional pricing structures between utilities and industrial users with generation capabilities havebeen based on peak/off-peak demand pricing. Recently, many utilities have initiated pricing programsbased on "real time pricing". Under this scenario, the price to purchase power is fixed for 1 hour but canchange each hour of a 24-hour regular day. Typically, once a day, the utility submits to the industrial

Operator

Console

Operator

Console

Rcvry Blr

#2

Field I/O

Power Blr#4

Field I/O

Power Blr#6

Field I/O

TurbineOptimize

Field I/O

Turbine#2

Field I/O

EnergyMetering

Field I/O

CommonLogic

Field I/O

Turbine#1

Field I/O

Power Blr#3

Field I/O

Power Blr

#1

Field I/O

Common

Logic

Field I/O

Rcvry Blr

#4

Field I/O

Communications Highway

Menu Print

7/28/2019 0201.pdf

4/9

user the purchase price for electrical power in hourly increments for the next 24-hour period. Theoptimization program allows the operator to enter the 24 hourly purchase price values. At this particularsite, a file with the 24 hourly purchase price values are sent via a modem to the operator console andautomatically downloaded into the optimization program.

MODE SELECTION

For each hour of the day, the optimization program calculates a cost to generate power when condensingsteam and when venting steam to the atmosphere. These costs are based on the current gas price, theefficiency of power boiler #6 and a steam flow per megawatt constant for condensing steam and ventingsteam.

Cost to generate power = Gas Price * PB#6 Efficiency * Steam required for additional generation

The following is entered by the operator and generally is constant, but can change with the seasons:

Gas price = 2.15 $/MMBTU

The following constants were supplied by the powerhouse management staff:PB#6 Efficiency = 1.3 MMBTU per KLB/HRSteam required for additional generation when condensing = 9.5 KLB/Hr per MWSteam required for additional generation when venting = 18.6 KLB/HR per MW

Cost to generate power when condensing:= (2.15 $/MMBTU)*(100 cents/1 $)*(1.3 MMBTU/KLB/HR)*(9.5 KLB/HR/MW)*(1 MW/1000KW)= 2.655 cents/KW

Cost to generate power when venting:= (2.15 $/MMBTU)*(100 cents/1 $)*(1.3 MMBTU/KLB/HR)*(18.6 KLB/HR/MW)*(1 MW/1000KW)= 5.199 cents/KW

For each hour increment, these calculated generation costs are compared to the purchase price ofelectrical power and one of three operating modes is selected:

Mode 1 Minimum Condensing and Minimum Generation(Purchase Cost

7/28/2019 0201.pdf

5/9

minimized to reduce steam flow from power boiler #6 but not to effect steam flowfrom power boilers #3 and 4.

Implementation - The tie-line setpoint is set to 15 megawatts but can not be attained under mostconditions. TG#1 controls the 65# steam header and TG#2 megawatt load demand isadjusted by the tie-line controller to maintain purchased power. While the turbines

are backing off to maximize purchased power, available steam to the condenser fromTG#2 will decrease first. However, a minimum condenser steam flow is maintainedto act as a buffer for swings in the steam headers, allowing the turbine to respondfaster. If condenser steam flow drops below the minimum value, or if pressure on the850# steam header is high or if power boilers #3, #4 and #6 have backed offsignificantly, then the tie-line setpoint starts to ramp down, allowing the turbines toincrease generation to alleviate the condition (see Table 1). Once the condition iscleared, the tie-line setpoint ramps back to 15 megawatts.

Mode 2 Maximum Condensing without Venting

(Purchase Cost >Condensing Cost, Purchase Cost Condensing Cost, Purchase Cost >Venting Cost)

Strategy - Maintain the steam headers in the plant and minimize purchased power bymaximizing generation while condensing steam and venting steam by forcing steamto the 65# steam header.

TG#1 - Maximize megawatt load by maximizing exhaust (65#) steam while maintainingextraction (425#) steam. This forces excess steam flow into the 65# steam header.Extraction (425#) steam continues to have priority and will back off exhaust (65#)steam if needed to maintain extraction (425#) steam (though this is an unlikelyscenario).

Menu Print

7/28/2019 0201.pdf

6/9

TG#2 - Maximize megawatt load while maintaining HP extraction (165#) steam, maximizingLP extraction (65#) steam and maximizing steam to the condenser. HP extraction(165#) steam continues to have priority over LP extraction (65#) steam. Megawattload will back off if there is low demand for extraction steam and flow to thecondenser is maximized (though this also is an unlikely scenario).

Implementation - The tie-line setpoint is set to zero but may not be attained under all possible scenarios.The exhaust (65#) steam setpoint to TG#1 increases providing there is a tie-line mwerror and TG#2 is at maximum megawatt load, and 850# steam pressure is above aminimum and the vent valve is not near its full open point. TG#2 megawatt loaddemand is adjusted by the tie-line controller to maintain purchased power. TG#2increases to maximum megawatt load before the 65# setpoint on TG#1 is increased(see Table 1).

PLANT CONSTRAINTS & OVERRIDE CONDITIONS

Plant operating conditions effect the system's ability to maintain purchased power. To accommodatethese conditions, a number of operating constraints are added to the control scheme to override the tie-line megawatt controller.

As described above, the optimization program maximizes purchased power while in Mode 1 andminimizes purchased power while in Modes 2 and 3. To allow these different modes of operation, someplant setpoints are adjusted from their normal settings. Additionally, certain plant conditions mustcompletely override the individual turbine demands. Table 1 summarizes the normal settings and theprocess constraints to plant operation.

Table 1

Plant Constraints & Override ConditionsParameter Normal Setting Comment

850# Steam Header 770 PSIG If pressure decreases below the setpoint, the loaddemand signal to TG#1 and TG#2 will decrease

65# Steam Header 68 PSIG - Mode 1 & 2

73 PSIG - Mode 3

If pressure increases above setpoint and TG#1 is not inexhaust AUTO, the load demand signal to TG#1 willdecrease

TG#1 65# Exhaust Setpoint 65 PSIG - Mode 1 & 2

73 PSIG - Mode 3

The increased setpoint for Mode 3 allows venting ofsteam to atmosphere from the 65# steam header. TG#2is increased to maximum load before setpoint isincreased. Vent Valve starts to open at 70 PSIG.

Tie-Line Megawatt Setpoint 15 MW - Mode 1

0 MW - Mode 2& 3

The increased setpoint for Mode 1 allows the turbines todecrease generation. While in Mode 1, if main steampressure increases above 870 PSIG, or if steam flow fromPB#3, #4 and #6 decreases below 700 PSIG, or ifcondenser flow decreases below 170 KLB/HR, the tie-linesetpoint is ramped down.

TG#2 Condenser Vacuum -22.0 INHG If condenser vacuum increases above the setpoint, theload demand signal toTG#2 will decrease

TG#2 Condenser Flow 280 KLB/HR If condenser flow increases above the setpoint, the loaddemand signal toTG#2 will decrease

TG#2 Condenser Hotwell Level 100 PCT If condenser hotwell level increases above the setpoint,the load demand signal to TG#2 will decrease

Menu Print

7/28/2019 0201.pdf

7/9

LOGIC IMPLEMENTATION

The optimization program uses a standard Fixed Demand Tie-Line Control scheme (see Figure 3) thatincludes Cost Analysis and Mode Selection Logic, a Tie-Line Megawatt Master Controller, a Total

Turbine Megawatt Demand Controller, and two Turbine Megawatt Masters for controlling megawattload demand to the 2 turbines. This control scheme is modified to accommodate scenarios dictated bythe selected mode, plant constraints and override conditions.

Figure 3

Block Diagram

The Fixed Demand Window method calculates a megawatt setpoint correction based on actual tie-line

power usage over a fixed time window of 15 minutes. Accumulated pulses representing actual tie-linepower usage is compared to a megawatt target that is ramped up over the same 15-minute interval. Ifthere is an error between the actual tie-line power usage and the target usage, a setpoint correction ismade to the tie-line megawatt controller.

The Tie-Line Megawatt Master Controller develops the plant megawatt demand signal. In Automaticmode, the setpoint correction signal developed by the Fixed Demand Window is added to the purchasedpower target from the Tie-Line Megawatt Master to develop a purchased power setpoint. This setpoint

Fixed Demand WindowMW Error Correction

Tie-Line Megawatt

Master Controller

Total Turbine MegawattDemand Controller

Turbine #1 MegawattMaster

Turbine #2 MegawattMaster

Plant Constraints &Override Conditions

Turbine #1

Plant Constraints &Override Conditions

Turbine #2

Cost Analysis andMode Selection

TG#1 Load Demand TG#2 Load Demand

Menu Print

7/28/2019 0201.pdf

8/9

is sent to the tie-line megawatt controller and compared to actual tie-line megawatts. The appropriatecontrol action is performed on the resulting error to develop a plant megawatt demand signal

The Total Turbine Megawatt Demand Controller develops the total turbine megawatt demand signal thatis sent to the individual Turbine Masters. This signal is developed from the plant megawatt demand

signal that is sent from the Tie-Line Megawatt Master Controller and is adjusted based on which turbinegenerators are available to respond to changes in plant generation demand. The Total Turbine MegawattDemand Controller assures that the total turbine generator demand (weighted sum of individual turbinegenerator load demand signals) is equal to the plant megawatt demand. This feature automaticallycompensates for variations in megawatt generating capacity between the turbine generators, manualturbine generator load changes, turbines operating against a limit imposed by the extraction steam map andturbine generator bias changes.

The total turbine megawatt demand signal developed in the Total Turbine Megawatt Demand Controller issent to the two Turbine Masters where it can be biased in either direction for balanced operation orunbalanced operation. In Automatic mode, the turbine load demand signal is checked against the high

and low limits developed in the individual turbine controller and the internal high and low limits locatedin the optimization module. To allow the tie-line control scheme to respond faster and more accuratelyto limits placed on the individual turbine controls by the extraction steam map, the calculated loaddemand limits are sent via the communication highway from the individual turbine controllers to theoptimization program.

OBSERVATIONS

Based on start-up and commissioning experience, the following observations were made:

1. The optimization program could be further enhanced if an optimization and/or allocation programexisted in the plant steam master. Currently, the operator has only a bias feature to adjust how theindividual boilers respond to the plant steam master signal. The calculations made in the turbineoptimization program are based on the efficiency of power boiler #6 and the gas price, which is themain fuel for this boiler. The assumption is that power boiler #6 will be the last boiler used toincrease steam flow and the first boiler used to decrease steam flow. The reality of the current plantsteam master is that, each boiler responds equally to the plant master signal, and the operators onlyhave some limited bias for each boiler.

2. The steam flow to the condenser swings frequently to assist in meeting the plant steam demands. Toallow the system to respond faster and to maintain steam system stability in Mode 1, it was found

that the minimum condenser flow had to be set to a higher than expected value.

3. Because the tie-line controller is trying to control megawatts at the same time the demands on theplant steam headers is fluctuating, the turbines are adjusted frequently and at times appear to beoscillating. While this condition does not cause major problems, the constant movement of theturbines can be unsettling to some operators. The long-term effect of this constant movement of theturbine valves on the wear life of the hydraulic actuators should be monitored.

Menu Print

7/28/2019 0201.pdf

9/9

CONCLUSION

The Optimization Program successfully meets the objective of maintaining power across the tie-line atvarying setpoint levels based on purchase power pricing and powerhouse generation costs while

simultaneously providing a well regulated source of 165# and 65# steam to the paper mill. Bycontinuously adjusting the turbines to maximize purchased power in Mode 1, the powerhouse can nowtake full advantage of the demand periods with reduced purchase power costs. By continuouslyadjusting the turbines to minimize purchased power in Modes 2 & 3, the powerhouse can now keeppurchased power to a minimum during the demand periods with higher purchased power costs. Furthersavings can be realized if the plant master is modified to load allocate the boilers based on fuel costs andboiler efficiencies. The plant constraints and override conditions that are accommodated in the programgive the operators the confidence that the system will not adversely effect the powerhouse's ability tosupply steam while simultaneously satisfying tie-line megawatt objectives.

Menu Print