CONTROL PERFORMANCE OF LARGE SCALE STEAM POWER PLANTS AND IMPROVEMENTS

IFAC Symposium on Power Plants and Power Systems Control, Kananaskis, Canada, 2006

CONTROL PERFORMANCE OF LARGE SCALE STEAM POWER PLANTS AND IMPROVEMENTS T. Weissbach*, M. Kurth* and E. Welfonder* D. Haake** and R. Gudat** *

Department of Power Generation and Automatic Control, IVD, University of Stuttgart Pfaffenwaldring 23, 70569 Stuttgart, Germany Tel.: +49 711 685 66209, Fax: +49 711 685 66590 [email protected] **

Vattenfall Europe Generation AG & Co.KG

Abstract: Current energy market developments stimulate a dual electric power supply, which correspondingly increases the demands concerning flexibility and manoeuvrability of large-scale steam power plants. For these purposes, a joint research project between the University of Stuttgart and Vattenfall Europe Generation1 has been initiated with the objective of creating an improved unit control concept, using advanced control techniques like nonlinear model-based and flatness-based feed-forward control. In a first step, however, the dynamic behaviour of existing large-scale generating units had to be analysed, which not only included an isolated analysis of each considered unit, but also the novel approach of a comparing analysis. Discrepancies in the control behaviour even between structurally identical units were detected. Considering the mentioned background, the overall results show that the currently dominating linear unit control concepts have several dynamic and static restrictions, especially when a unit is participating in the network frequency control. Copyright © 2006 IFAC Keywords: steam power plants, power plant control, control performance, model-based control, flatness-based control, network frequency control, feed-forward control. 1. INTRODUCTION

generators feed one turbine, see Fig. 1b – this can lead to an unsmooth transition between duo- and mono operation with a power output of not more than P*G,min= 35% of the nominal power, see Fig. 1a, during extreme constellations. An alternative unit scheduling, including the temporary shut-down of some of the already in off-peak mode operated power plants, is often not possible, since the large scale lignite-fired units need several hours for the shutdown and start-up processes. Additionally, the system load increases significantly after 6 a.m., especially on working days. The units have then to be able to react correspondingly to the rising power demand immediately.

The increasing amount of electricity generation based on a mix of renewable energy sources, mainly wind power and heat-load-dependant combined cycle units result in a dual electric power supply (Welfonder, et al., 2004). If it comes to the worst case, especially during off peak times with simultaneously high wind intensities, not only the large scale lignite-fired 900-MW-units in the eastern German part of the Vattenfall Europe Generation1 power system have to be operated at their minimum load level, but also their older 500-MW units. Since the latter are designed as duo-plants – two steam a)

b)

600 500

duooperation

P [MW]

400

st.-g. 1

duo

300 200

unit 1-3

100

st.-g. 2

~ ~

0

mono

monooperation

unit 4-6 Block 4-6

-200

-100

0

100 Q [MVar]

200

300

400

500

Fig. 1: Generator power diagram of 500-MW-duo-units (Welfonder, et al., 2004) 1

Vattenfall Europe is the 5th largest energy company in Europe

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IFAC Symposium on Power Plants and Power Systems Control, Kananaskis, Canada, 2006 Another aspect is a possible drop of the feed-in by wind power units caused by a sudden decrease of the wind intensities, or by a sudden shut-down of entire wind parks in case of too high wind speeds exceeding 25 m/s to 30 m/s. In case of such feed-in drops the conventional generating units have to increase their generator output instantaneously.

Most promising, however, appears a combination of the two approaches where possible. Apart from ensuring a secure steady operation, the main task of the unit control is the handling of the set point setting for the generator output, provided by the dispatcher and, in case the unit participates in the network control, by the network primary and secondary controller. In any case, the compliance with the unit design parameters has to be ensured.

Due to the above mentioned reasons, large scale steam power plants must be able to be operated flexibly in all load conditions to compensate the feed-in fluctuations, a challenge which has led to the initiation of a joint research project between the University of Stuttgart and Vattenfall Europe Generation. However, before developing a unit control concept, the current control performances of the considered large scale steam power plants had to be analysed first. For this purpose, a methodology was designed following a novel approach, which is not only based on an isolated analysis of one single unit, but on a direct comparison between different units in different operation modes. The advantages of this approach and some of the results, which partially can also be used for other related questions, are also shown in this paper.

The difference between a “classic” process control concept, which can be found in most units today, and a model-based process control concept is shown in Fig. 2. In the classic process control concept, see Fig. 2a, the feed-back controller has the function of both controlling the process according to the set point inputs and compensating disturbances on the process. A partial decoupling between these two functions can be achieved by an additional feed-forward controller which takes over the process open-loop control to some extend. The model-based control concept, see Fig. 2b, contains a superimposed process model, which computes a reference process output yref. If the process model is accurate enough, then the reference process output yref complies with the real process output y if no disturbances occur (z=0), and the error variable Δy becomes very small. In that case, the process openloop control and closed-loop control for compensating disturbances can be designed separately.

2. NONLINEAR MODEL-BASED UNIT CONTROL CONCEPT For the development of a control concept, which not only enables the large scale steam power plants currently in the planning phase to meet the above listed requirements, but also the already existing older units, the project aims at a dual approach. The new control concept is designed in such a way, that the already existing and optimised unit control structures largely can be kept. The advantage of this approach is not only an uncomplicated integration into the unit control and communication system in the end, but also the possibility of continuous testing during the development phase without major disturbance of the scheduled unit operation. The chosen dual approach consists on the one hand of a nonlinear, model-based feed-back control (Pitscheider, et al., 2000), and on the other hand of a flatness-based feed-forward control (Rothfuss, et al., 1997), whereas the more suitable method has to be determined for each special case.

The process model used in the desired unit control concept, which also is the basis for the flatnessbased feed-forward control, originates from nonlinear modelling of the entire power plant process. The University of Stuttgart has already developed and published the models and a nonlinear model-based unit control concept, which thanks to its white-box-design has also been included into the new guideline VDI/VDE 3508 “Unit control of thermal power stations” (VDI, 2004). However, to adapt the theoretical model to the control of the considered large-scale lignitefired steam generating units, the dynamical behaviour of these units has to be analysed first, which was done in the first part of the research project.

a) „classic“ process control concept with feed-forward control feed-forward control

uref

disturbance z

w -

feed-back control

u

process

y

b) model-based process control with feed-forward control w

feed-forward uref control

disturbance z

process model

yref

Δy -

feed-back Δu control

u

process

Fig. 2: “classic” and model-based process control

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y

IFAC Symposium on Power Plants and Power Systems Control, Kananaskis, Canada, 2006 3. CONTROL PERFORMANCE

3.1. Steady operation

The VDI/VDE-guideline 3508 deliberately states only imprecise general information on the topic of control performance of thermal power stations. The reason for that is the dependency of the control performance on a variety of influence factors, which not only include the type, design, operation mode and control concept of the generating unit, but also the size and resulting system frequency noise of the interconnected or part power system the plant feeds in. This led to the fact, that momentarily the control performance of a power generating unit is not a precise defined parameter, but rather fuzzy and based very much on experience and personal assessment.

Fig. 3a shows plots of the generator output of the three units A, B and C during steady operation in comparison to each other. For a consistent and clear representation in one single diagram, a time period of 3.5 h has been chosen. Since all of the units are participating in the network primary control during the considered time period, a relevant part of the observed oscillations in the generator output can be assumed to be caused by the network frequency noise. From the corresponding measured frequency plot, see Fig. 3b, a frequency bandwidth of approximately ± 30 mHz was derived in all three cases. With the frequency bandwidth known, the influence of the network frequency noise on the generator output was estimated using the proportionality δ of the primary controller, which in this case is δ = 13 for all three units:

However, a more precise determination of the control performance is possible if well defined operation states are considered, including process and test conditions. The composition of the Vattenfall Europe power plant fleet offered the opportunity not only to determine the control performance of single units, but also to compare the control performance of several structurally identical units, since the during the 90s built 900-MW lignite-fired generating units are almost of the same type and control structure. Together with Vattenfall Europe Generation, initially three 900-MW-units have been selected, which are denoted with the letters A, B and C in the following.

ΔPG* =

The above calculation results in an estimated generator output noise with a bandwidth of ± 0.5% of the respective nominal generator output, which originates from the participation of the unit in the network primary control. This generator output bandwidth is also shown in Fig. 3a. The comparison of the generator outputs of the units A, B and C (see Fig. 3a) points out, that the units show a highly varying control performance. Unit C shows the most balanced generator output, which practically never leaves the generator output bandwidth of ± 0.5%. The generator output of unit A is more disquiet; however, violations of the generator output bandwidth only occur at few specific moments and are related to outside influences. Therefore, its overall control performance can still be rated as acceptable.

Since the nominal power outputs of the selected units are not identical, all analyses issue variables in the “per-unit-system”, which are denoted with a “*” (i.e. x*(t) = x(t) / xNominal). That way, variables can be compared more easily, even if they originate from different units. The following details focus – as does the guideline 3508 – on the variable “generator output”, since it is the most important control variable for power generating units. a)

PG* [pu]

1.00

100 Δf 100 ±30 ⋅ 10-3 Hz ⋅ = ⋅ = ±0.5% δ f0 13 50 Hz

1.00

unit B unit A

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unit C

1%

±0.5%

0.95 0.95

A

b)

C 0.95

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f [Hz ] 50.04

3

time [h]

±30 mHz

50.02

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50.00 49.98 49.96

0

1

2

3

time [h]

Fig. 3: System frequency and generator output of the units A, B and C during steady operation

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IFAC Symposium on Power Plants and Power Systems Control, Kananaskis, Canada, 2006 The most disturbed progression of the generator output shows unit B. Here, particularly a superposed periodic oscillation stands out, which can be observed during the entire considered time period. The periodic oscillation can not be traced back to any outside influence and can also be detected in variables of the subordinate unit control circuits. This outcome indicates a considerable optimisation potential for unit B and has prompted further-going investigations, including the use of more sophisticated tools for signal processing and analysis like for instance spectral analysis.

like output change, with the same oscillation characteristics than in the case of steady operation. Also noticeable is the generator output of unit C, which reacts much slower to the ramp-like set point value trajectory than the other units, although the overall ramp gradient of 1.2 %/min is less high compared to the ramp gradients of the units A and B which is 2 %/min. 3.3 Step-like output changes Fig. 5 shows the generator output of the units A, B and C after a step-like change of the corresponding set point value. The data results from the corresponding pre-qualification procedure for the participation in network primary control (VDN TransmissionCode, 2003), namely for the operating mode “modified floating-pressure operation” with a turbine valve throttling rate of 3% and activated condensate retention control near the maximum load. The step-like change of the set point value for the generator output is generated by a virtual steplike change of the system frequency set point by Δfset = 200 mHz, which corresponds to a step-like change in the generator output set point by ΔP*G,set = 3%. The most important indicators for the step response of the generator output of the units A, B and C, the overshoot ym and the response time TA, are illustrated comprehensively by using bar charts in Fig. 6. These indicators are also included in Fig. 5.

3.2. Ramp-like output changes P*G [pu] unit A

actual value desired value

ΔP*G

0.9

(≈ 24%) 0.7

unit B

0.9

ΔP*G (≈ 24%)

0.7 unit C 0.9

ΔP*G (≈ 21%)

0.7 0

30

The comparison of the step responses of the three selected units in all load situations enables an overall evaluation of the corresponding control performance for the given conditions. Unit C shows the lowest value for TA in each evaluated load situation; hence it is the fastest reacting unit. However, unit C is also the unit with the biggest overshoot. Unit A is well balanced compared to unit C; its response time is slightly higher but the overshoot much lower. The evaluation for unit B again points out a considerable potential for optimisation, especially because of the too long response time TA during minimum load.

t [min] 50

Fig. 4: Generator output of the units A, B and C during ramp-like output changes Fig. 4 shows the control performance of the units A, B and C during negative ramp-like output changes of -21% and -24% respectively. Because of the partly stepped progression of the set point value trajectories, which normally is different for each unit, the conclusions derivable by a direct comparison of the generator outputs are rather limited. However, one point to emphasize is the occurrence of periodic oscillations in the generator output of unit B after the completion of the ramp1

unit B: ym = 0.8% (7.4 MW)

P*G [pu]

unit A: ym = 0.6% (5.6 MW) unit C: ym = 1.1% (9.9 MW)

0.94 1 3% 0.95

0.90 0.95

≈ A

unit A: TA = 21s unit B: TA = 14 s

≈ B

Fig 5:

≈ C

actual value

unit C: TA = 13 s

desired value

0 t [min] 10 5 Generator output of the units A, B and C during step-like output changes

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IFAC Symposium on Power Plants and Power Systems Control, Kananaskis, Canada, 2006 4. SIMULATIONS

a) overshoot ym 1.2

C

y m [% ]

Based on the results from the evaluation of the dynamic behaviour of the considered units, a nonlinear model was parameterised, which is intended to be used in a model-based controller. Before implementing and testing a model respectively modelbased control concept under real conditions, the behaviour of the model has to be investigated in numerous simulations.

C

1 B

0.8

A

C

A A

0.6

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0.4

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0.2

4.1. Simulation of step response

0 peak load

medium load off-peak load

The first simulations focus on the control performance during network primary and secondary control. Therefore, the simulation model also includes a simple model of the European power system and its interaction with the power generating unit under consideration. Basic condition for the simulation is an off-peak system load situation already addressed in the introduction.

b) response time TA 60

B

T A [s] 50 40 maximum limit (VDN-Transmission Code)

30

A A

20

B

C

A

The activation of the network primary and secondary control is evoked by a sudden drop in the system power feed-in by 2% of the system off-peak load of 150 GW (VDN TransmissionCode, 2003), which in reality might be caused by an emergency shut-down of a large power plant, and which causes a respective drop in the network frequency. Hence, the basic condition for the simulation is, apart from the size of the disturbance and the take-over by the network secondary control, similar to the conditions during the certification procedure mentioned in section 3.3. The result of the simulation is the step response of the modelled unit under realistic conditions.

C

B C 10 0 peak load

medium load off-peak load

Fig. 6: Overshoot and response time generator outputs of units A, B and C

of

Beside the process variable “generator output” as the most important variable for power generating units, other process and control variables have been analysed similarly with a special focus on their interaction, like thermal power, live steam pressure, or live steam flow. These analyses revealed needs for optimisations also in the area of the subordinated control structures.

Fig. 7 shows the control behaviour of the simulated generating unit model with activated condensate retention control and turbine valve throttling of initially D* = 1% to minimize throttling losses. d) fuel mass flow (0s – 2000s)

a) system frequency (100s – 300s) 50 f [Hz] 49.75

±0 mHz

1.00

49.5 t [s] 300 100 b) turbine output, generator output (100s – 300s) 1.04 30 s P* [pu] 1.00 ±0%

0.96 0 e) condensate flow (0s – 2000s) 1.2  c* [pu] m

±0%

t [s] 2000

1.0

0.8

0.96 100 c) turbine valve position (0s – 2000s) 1.04 y*T [pu] 1.00

0.96 0

Fig. 7:

1.04  B* [pu] m

t [s] 300

0

t [s] 2000

f) level feed-water tank (0s – 2000s) 0.5 L*fwt [pu] ±0%

0.48

t [s] 2000

0.46 0

t [s] 2000

Simulated control behaviour of the nonlinear model of a large-scale generating unit after a feed-in drop by 2% of the off-peak load of the European power system (150 GW)

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IFAC Symposium on Power Plants and Power Systems Control, Kananaskis, Canada, 2006 A throttling of 1% proves to be necessary, but also enough, to compensate the chaotic grid frequency oscillations. The condensate retention is only activated after frequency drops of |Δf| > 30mHz. As can be seen in Fig. 7d and e, the activation of the immediate-reserve capacity is evoked both by the very fast opening of the 1%-throttled turbine valve and by the reduction of the condensate flow. The latter causes an emptying of the feed water tank by approximately 2%, while the replenishing of the tank already starts after about 250s and is finished after 800s, compare Fig. 7f. The almost step-like increase of the generator output during the first seconds, see Fig. 7c, can be traced back to the release of rotational energy after the frequency drop, compare picture 7b. After 30s, the entire immediate-reserve power is activated, as is demanded by the TransmissionCode, see Fig 7c. After the complete take-over by the network secondary control, all process variables return to their initial values as they were before the load disturbance. The characteristic of each simulated process or control variable is as expected, and the model performance shows a good agreement with the real unit performance.

based unit control concept, including a nonlinear process model and a model-based feed-forward controller. Before designing the control concept, the control performance and dynamic behaviour of the considered large-scale generating units had to be determined. Therefore, a comparing and comprehensive analysis including three existing similar generating units has been carried out. The results show considerable discrepancies in the control behaviour, even though type and control concepts of the considered units are structurally identical. The outcome also highlights optimisation potentials and needs for action, especially for the operation near the minimum load level, which is particularly important to prepare the units for the rising requirements following the increasing dual electric power supply. This fact can be seen especially from the high response time of unit B during off-peak load operation. Beside dynamic issues, problems were also identified during steady operation of the plants. Each considered unit shows an oscillating behaviour of its generator output and also subordinate process variables, which cannot be traced back to oscillations in the system frequency. Therefore, their cause can be found in control- or plant-related issues.

4.2. Planned future proceeding The present simulations show the behaviour of the nonlinear unit model and its interaction with the power system. However, the set point values resulting from the model have to be assessed carefully with regard to their compliance with the unit design parameters; so that it is ensured that no technological system boundaries are violated. Additionally, the flatness-based feed-forward control has to be parameterised and tested.

As for the controller design, first simulations have been carried out to test the dynamic behaviour of the considered nonlinear process model after a step-like input function. The model performance shows a good agreement with the real unit performance. 6. BIBLIOGRAPHY Pitscheider, K. and Welfonder, E. (1996). Modelbased Online Minimization of NOxemission in Power Plants with pulverized coal Combustion. 13th IFAC World Congress, San Francisco, USA. Pitscheider, K., Meerbeck, B. and Welfonder, E. (2000). Robust model-based unit control concept with regulated deactivation of preheaters and heat condensers. IFAC Symposium on Power Plants & Power Systems Control 2000, Brussels Rothfuss, R., Rudolph, J. and Zeitz, M. (1997). Flatness: A new approach to control of nonlinear systems, at-Automatisierungstechnik 45, R. Oldenburg Verlag, p. 517-525 VDI/VDE: Guideline 3508 (2003). Unit control of thermal power stations, VDI, Beuth Verlag, Berlin VDN: Transmission Code (2003). Network and System Rules of the German Transmission System Operators, Verband der Netzbetreiber e.V. beim VDEW Welfonder, E., Kurth, M., Tillmann, H.-B., Hodurek, C. Radtke, H. and Nielsen J. (2004). Dual Electric power supply with increasing wind power generation, requirement for an advanced secondary control concept, CIGRE 2004 Session, Paris

Therefore, a detailed dynamic model library for power generating systems developed by the University of Stuttgart can be used to represent the real plant, including the air/fuel-side of the process on the one hand and the water/steam side on the other hand. To simulate the control performance comprehensively, the control concept is applied on the detailed dynamic model of the considered unit. Starting from the network primary control, the control concept will be tested for every operation mode. The planned time horizon for the design of the entire unit control concept in the joint research project is 2 years (2006-2007). 5. CONCLUSION Due to the rising demands concerning manoeuvrability and efficiency of large-scale power generating units, improved control concepts are required, which allow the units to be flexibly operated in a wide range of load conditions. For this purpose, the range between the process-related boundaries has to be utilised entirely and expanded, if applicable, especially with regard to a lowering of the minimum possible load. For this purpose, a “classical” linear control concept, which can be found in most units today, proves to be not sufficient. The aim is the design of a comprehensive nonlinear model-

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