Feb 27, 1995 - Abstraet--A steam power plant thermodynamic model developed using the ASPEN Plus shell is presented. The model is validated using field ...
~
Applied Thermal Engineering Vol. 16, No. 3, pp. 263-271, 1996 Copyright © 1995 Elsevier Science Ltd 1359-4311 (95)00071-2 Printed in Great Britain. All rights reserved 1359-4311/96 $15.00 + 0.00
Pergamon
THERMODYNAMIC SIMULATION AND EVALUATION A STEAM CHP PLANT USING ASPEN PLUS
OF
Alfred Ong'iro,* V. Ismet Ugursal,*t A. M. A1 Taweel:~ and G. Lajeunesse§ *Department of Mechanical Engineering; and SDepartment of Chemical Engineering, Technical University of Nova Scotia, P.O. Box 1000, Halifax, Nova Scotia, Canada, B3J 2X4; and §Nova Scotia Power Inc., Halifax, Nova Scotia, Canada
(Received 27 February 1995) Abstraet--A steam power plant thermodynamic model developed using the ASPEN Plus shell is presented. The model is validated using field data from two units, one with a capacity of 105 MWe and the other 150 MWe. The model is then modified and used to evaluate the thermodynamic feasibility of servicing a small (less than 20 MWt) thermal load in addition to generating electricity. Keywords--Power plant, thermal load, performance, modeling, simulation, ASPEN Plus.
NOMENCLATURE AP
fm F~
rhi rht MWt MWe OUF a Qin
THR THL UHR W
x,
xmu
auxiliary power (SI units) efficiency factor for non-isentropic expansion efficiency factor for mechanical and generation losses mass flow rate of steam (SI units) mass flow rate of in branch i (SI units) total mass flow rate (SI units) MW thermal MW electric overall unit energy utilization factor heat input (SI units) heat input at the boiler (SI units) turbine heat rate (Btu/kWh) thermal load (SI units) unit heat rate (Btu/kWh) electrical power output (SI units) mass flow rate ratio for the branch i (SI units) percent make-up
Greek letters Ah specific enthalpy change (SI units) qb boiler efficiency qs isentropic efficiency glm mechanical efficiency (generation losses included) /1thermal thermal efficiency
1.
INTRODUCTION
The prospect of servicing thermal loads (such as a district heating system) from existing power plants can be an attractive option for utility companies and other power generators if the economic and operational feasibility can be demonstrated. Since a utility has to supply the power demand from the grid, the effect of integrating a thermal load on the power output needs to be quantified. Depending on the generation capability of the utility, this effect can be a major concern and has to be addressed before conducting a detailed economic feasibility and design study. Similarly, the improvement, if any, in the overall thermal efficiency, and the variations in key operating parameters (such as fuel consumption, steam flow rates, turbine loadings, etc.) have to be accurately determined to facilitate an economic feasibility study. #Author to whom correspondence should be addressed. Ate
16/r-v
263
264
A. Ong'iro et al.
When an existing power plant is modified to service a thermal load in addition to power generation, some changes will be necessary in the plant configuration, resulting in off-design conditions for some components. In addition, the plant may often be operated at part-load conditions due to reduced electrical and/or thermal load. Such changes in the configuration and operation of a plant have significant effects on performance, which are difficult to predict using manual calculations. Therefore, a flexible and accurate power-plant simulation model capable of predicting part-load, as well as off-design, performance would be necessary to conduct an in-depth thermodynamic analysis, and to quantify the effect of the modifications and operating modes on performance. Here, a steam power plant simulation model developed using the ASPEN Plus shell [1] is presented and it is validated using field data. The model is then modified to predict the performance of the plant retrofitted to accommodate a small thermal load. 2. S I M U L A T I O N IN A S P E N PLUS S H E L L The ASPEN Plus environment provides a flexible input language for describing power plant components, connectivity and computational sequences. Its use leads to an easier way of model creation, maintenance and updating, since small sections of complex and integrated systems can be created and tested as separate modules before they are integrated. It has an extensive physical property database, where the diverse stream properties required to model the material streams in a power plant are all available with an allowance for addition of in-house property data. Additionally, ASPEN Plus has many built-in model blocks (such as heaters, pumps, stream mixers, stream splitters, compressors, etc.) which can directly be used in power plant simulation. Where more sophisticated block ability is required, additional information may be added to the block in the form of F O R T R A N subroutines, or entirely new user blocks may be created. In this work, the existing ASPEN Plus blocks were used with minor modifications to develop the power-plant model. However, in more complex models, it may be necessary to develop new models and use them in the ASPEN Plus flow sheet as shown by Ong'iro et al. [2, 3], Phillips [5] and Stone [4]. Also, ASPEN Plus provides a flexible and robust calculation framework that ensures convergence of material and energy calculations in the multi-loop feed-back connectivities encountered in conventional and advanced power cycles, and it has a versatile economic analysis package. 3. M O D E L L I N G OF T H E P O W E R P L A N T F L O W S H E E T AND T H E P E R F O R M A N C E OF V A R I O U S C O M P O N E N T S 3.1. Description o f the power plant
A typical, single reheat Rankine cycle steam power plant was simulated. Steam is raised in a boiler to an initial pressure of 12.4 MPa and 538°C. Reheat pressure and temperature are 2.8 MPa and 538°C, respectively. The steam turbine consists of a high-pressure (HP) section, an intermediate-pressure (IP) section and a double-flow low-pressure (LP) section. There are a total of five closed and one open (deaerator) feed-water heaters. The condenser is sea-water cooled and it is maintained at a pressure of 3.4 kPa Abs. 3.2. Simulation o f steam turbine
Compressors, fans and turbines can all be simulated in ASPEN Plus by a block called COMPR. C O M P R models polytropic and positive displacement compressors, isentropic compressors and turbines, as well as fans. C O M P R calculates the power required (or produced) given the pressure ratio, isentropic, polytropic, and mechanical efficiencies and, for positive displacement compressors, the clearance volume. The accuracy of the results depends on the efficiencies specified. C O M P R block in isentropic mode calculates the net work output from the change in enthalpy for isentropic expansion, then translates this to net work output using isentropic and mechanical efficiencies: w = ~mhh.
(1)
ASPEN Plus evaluation of a steam CHP plant
265
In the models used here, steam turbine stages in the HP and [P sections and the first two stages of the LP section are modeled using C O M P R blocks. As an example, the schematic layout for the IP turbine, and the corresponding ASPEN Plus flowsheet, are given in Fig. 1. For each section of the turbine, steam inlet and exit pressures and temperatures were available from field data. Thus, the polytropic efficiency of the whole section was first calculated iteratively from the known steam inlet and exit conditions assuming constant polytropic efficiency throughout the section, as proposed by Erbes and Eustis [6]. Then, using this constant polytropic efficiency and reheat factors [7], the expansion line for the section and the isentropic efficiency for each stage was calculated. The overall mechanical efficiency for the turbine was estimated using equations given by Spencer et al. [8]. Because of the presence of wet vapor at the exhaust, the C O M P R block cannot be used to simulate the final stages of the LP section, since this block is not capable of dealing with wet vapor with a substantial liquid content. Therefore, the H E A T E R block, which is normally used to simulate heaters, is modified to simulate these stages. The modified H E A T E R block calculates and sets the H E A T E R block exit temperature to that obtained if the expansion were isentropic through the same pressure ratio. The net work output is then set equal to the product of the heat output from the H E A T E R block and two 'efficiency factors'. One of these efficiency factors is to correct for irreversible expansion and it is the same as the stage isentropic efficiency, whereas the other is to correct for mechanical and generation losses and it is the same as turbine mechanical efficiency. They are calculated as described above.
IP Section I
(9 O3
03
Steam
¢9 O3
N
,,~
cn I
1I I
FHt
I
F
FH3___I ~
Feed water Condensate
ASPEN PLUS FLOWSHEET Stage 1 Steam
Stage 3
Stags 2
COMP1
COMP2
~
4 COMP4
Stage
COMP3
FSPLIT2
"--~HEATER2 "--~HEATER2
Hot side ~ I
~
It, ~
I HEATER3 ' - Condensatev | ("~
Feed water
Cold side HEATER4 FH1
HEATER5 FH2
HEATER6 FH3
Fig. 1. Schematic of IP section and feed heater arrangement.
266
A. Ong'iro et al.
Thus, the electrical power output from the final stages of the LP section is calculated from: W = fsfm rn Ah.
(2)
The calculated C O M P R block isentropic efficiency and the H E A T E R block efficiency factor are assumed to remain fixed at part-load operation, despite the change in pressure ratio in cases where field data is not available. 3.3. Feed heaters
The two closed feed heaters are each modeled using two H E A T E R blocks referred to as 'hot' and 'cold', as shown in Fig. 1. The 'cold' side raises the temperature of boiler feed water to the temperature set equal to that from the test data. The steam mass flow-rate on the hot side is calculated by conducting an energy balance. In some feed heaters, the total mass flow-rate through the hot side is the sum of bleed steam and the drain from the previous feed heater. The cold-side water temperatures and mass flow-rate data from the plant are available for various part loads. For part loads for which no data are available, the cold-side water temperatures and mass flow-rates were estimated by linear interpolation, and the mass flow-rate of bleed steam was calculated in each case by conducting an energy balance. The pressure drop through the feed heaters is assumed to be uniformly distributed. The open feed heater (deaerator) is simulated by the M I X E R block. The mass flow-rate of bleed steam is calculated from mass and energy balances so that predictions match the test data. The exit conditions from the heater are adjusted for part-load operation using field data, and the mass flow-rate of bleed steam is recalculated accordingly. To simulate the steam bleeds from the various points in the turbine for feedwater heating and for the gland seals, F S P L I T blocks are used. F S P L I T block is used to split the flow into different branches as shown below: rni = XirhT.
(3)
3.4. Steam generator
The evaporator (economizer and radiant sections), superheater and reheater are modeled using H E A T E R blocks. The heat duty of each section of the steam generator is calculated by conducting a heat balance using test data for mass flow-rates and conditions of the streams. M I X E R blocks, which can simulate mixing of two streams, are used to introduce the streams such as superheater and reheater attemperating sprays. F S P L I T blocks are used to introduce the steam leakage from the steam generator and piping system, as reflected in the test data. A F O R T R A N statement is included to translate the value enthalpy increase across the H E A T E R block to the net heat required using the equation below: Q = (ff/Ah)Evaporato r q- (//'/ Ah )superheater q- (r/'/Ah)Reheater,
(4)
where Q = heat input (SI units), rh = mass flow-rate of steam (SI units), Ah = specific enthalpy increase across the H E A T E R block (SI units). 3.5. Condenser
The condenser used in the power plant is a cross-flow, sea-water cooled heat exchanger. The heat exchanger block in A S P E N Plus, called H E A T X , was modified to reflect the three-dimensional flow pattern within the condenser. This was done by implementing a finite difference procedure that calculates the temperature field and the overall heat transfer coefficient for the condenser. 3.6. Pumps
Both condensate return and boiler feed pumps are modeled using the P U M P block. The inlet and outlet pressures are set equal to those in the test data. The pressures are calculated for part-load operation from a pressure ratio equation obtained by curve-fitting to the performance test data. This equation is introduced into the model by means of a F O R T R A N statement.
A S P E N Plus e v a l u a t i o n o f a s t e a m C H P plant
267
Table 1. Predicted and measured steam conditions and mass flow-rates Measured mass flow-rate Point
LP inlet FH 6 FH 5
FH 3
(kg/h)
(°C)
(°C)
242,650 (+0.02%) 21,620 ( - 0.04%) 16,490 (-0.2%) 8,600 (-1.6%) 14,470 ( - 0.02%) 13,570 (-0.05%) 9,982 (0.04%)
233.9
234.5 (+0.2%) 353.3 (+ 0.4%) 447.8 (+0.8%) 327.8 (+0.8%) 234.4 ( - 0.1%) 155.0 (-0.2%) 72.8
21,630 16,530 8,750 14,500 13,640
bleed
FH 1
Predicted temperature
(kg/h)
bleed
FH 2
Measured temperature
242,600
bleed bleed Deaerator
Predicted mass flow-rate
9,945
bleed
352.0 443.9 324.9 234.8 155.4 72.8
3. 7. Heat rate and thermal efficiency
The turbine and unit heat rates and thermal efficiencies are calculated using equations (5)-(7), respectively. Boiler efficiency, as determined from the test data, is used to give the required heating duty used in heat-rate calculations. The boiler efficiency is assumed to be fixed at part-load operation. The auxiliary power from test data at full load and at given part loads are used in the calculations. At part loads not available from field data, linear interpolation is used to estimate the auxiliary power. THR =
3413(Q/W),
(5)
THR
UHR
~th . . . . I =
(6)
3413/UHR.
(7)
4. M O D E L V A L I D A T I O N The field data used in the validation of the model were obtained from performance tests carried out on two oil-fired steam cycle units, one with a capacity of 105 MWe and the other 150 MWe. The data used were from tests conducted in accordance with ASME code procedures with test quality instrumentation to determine turbine heat rates, unit heat rates and the performance of the associated equipment like the boiler, feed water heaters, condensers, etc. Table 2. Predicted and measured steam conditions and mass flow-rates-150MWe unit Measured mass flow-rate Point
LP inlet FH 6
(kg/b)
(°C)
(°C)
255,955 (+0.01%) 32,561 (-0.01%) 22,593 (-0.1%) 20,549 ( - 1.6%) 21,967 (-0.02%) 12,157 (-0.01%) 24,183 (+ 0.03%)
233.9
233.8 (-0.4%) 361.7 (-0.6%) 457.2 (-0.2%) 232.2 ( - 0.4%) 356.7 (-0.7%) 255.6 ( - 1%) 78.9 ( - 0.6%)
32,605
FH 5
22,327 20,690
FH 4
22,009
bleed
12,168
bleed
FH 1
Predicted temperature
(kg/h)
bleed Deaerator
bleed
Measured temperature
256,128
bleed
FH 2
Predicted mass flow-rate
24,104
363.9 458.3 233.3 353.9 258.3 79.4
268
A. Ong'iro et
al.
6
6~
s.s o 5 • n-
,-r
~
4,5
Predicted
[] Actual •
4
E3
•[3
~ 3.5 3 55
i
i
P
t
i
i
i
r
I
60
65
70
75
80
85
90
95
100
% Power
Fig. 2. Actual and predicted boiler feed-water mass flow rates. Comparisons of predicted and actual steam flow-rates and temperatures at key locations of the cycle for the two units operating at design conditions are shown in Tables 1 and 2. The overall agreement is very good, considering the complexity of actual turbine expansion and the simplifying assumptions made in modeling these processes. The maximum difference in flow-rate prediction is 1.6%, while that of temperature is 1%. The predicted and actual boiler feed-water mass flow-rates for the 105 MWe unit at full- and part-loads are plotted in Fig. 2. The small margin of error in the predictions can be attributed to the departure of the actual expansion process from the calculated expansion line, leading to errors in stage isentropic efficiencies and underestimation of bleed steam temperature. This, in turn, leads to overestimation of mass flow-rates of bleed steam and feed-water stream. Comparisons of unit heat rates for both units are shown in Figs 3 and 4. The overall agreement is good across the normal operation range. The small margin of error can be attributed to the uncertainties in stage isentropic efficiencies, mass flow-rates of bleed steam, predictions of auxiliary power requirement, boiler efficiencies and boiler make-up water flow-rate. It can be concluded from these comparisons that the model can predict the performance of steam power units with reasonable accuracy. It can, therefore, be used as a tool to study the impact of off-design conditions imposed by the integration of a thermal load in addition to electrical generation.
5. I N T E G R A T I O N OF A T H E R M A L L O A D The thermal load that will be serviced from the plant is assumed to be hot-water generated in a steam-water heat exchanger (such as would be used in a district heating system). The proposed approach for integration is that of drawing steam required for the heat exchanger from the cross-over pipe between the intermediate-pressure (IP) and low-pressure (LP) sections of the steam 10.4
~
10.3
[]
~, 10.2
v n-
z c
10,1
[]
•
Actual
[ ] Predicted
10 9.9
DI []
l D
9.8 I
9.7 55
6O
I 65
I
I
70
75
r~
l•
I
I
f
I
80
85
90
95
% Power
Fig. 3. Actual and predicted unit heat rates for the 105 MWe unit.
I I
100
ASPEN Plus evaluation of a steam CHP plant
269
9,9 9.8 m 9.7 8 ~ II
9.6
•
Actual
9.5
[]
Predicted
~
9.4
~ c
9.3 9.2
55
i
i
i
i
i
i
r
P
i
60
65
70
75
80
85
90
g5
100
%
Power
Fig. 4. Actual and predicted unit heat rates for the 150 MWe unit. 4 o = 4
a.s
g~
2.5
._~ ~
•
2
100% 75%
~ - -
60%
1 .J
0.5
2
4
6
8
10
12
14
16
18
Thermal Load (MWt)
Fig. 5. Variation of lost electric generation capacity with thermal load and power generation--105 MWe unit. turbine, since this provides the best arrangement for operational flexibility and thermal load growth. Essentially, sufficient steam is to be tapped from the cross-over pipe to affect the required thermal load. To model the steam extraction, two extra A S P E N plus blocks were added to the power-plant model: 1. A H E A T E R block was incorporated to simulate the thermal load. 2. An F S P L I T block was introduced to split the stream linking the blocks simulating the last IP turbine stage and the first LP turbine stage into two streams. One stream from the FSPLIT was connected to the H E A T E R block simulating the thermal load and the other stream to the block simulating the first LP turbine stage. The fraction of steam diverted to supply the H E A T E R block representing the thermal load was calculated based on the magnitude of the load. Clearly, the mass flow-rate through the LP section would decrease with the thermal load. As the steam mass flow-rate is reduced, the expansion line of the LP section will change, resulting in a different isentropic efficiency. In the simulations carried out here, the change in LP section isentropic efficiency with steam mass flow-rate was neglected. This, however, does not introduce a significant error, since the thermal load is less than 20% of the total load, resulting in a small change in the steam mass flow-rate. In large-scale thermal-load integration simulations, corrections should be incorporated into the LP turbine model to account for the reduced steam mass flow-rate, and the change in the IP section exhaust conditions.* 6. S I M U L A T I O N R E S U L T S W I T H T H E R M A L L O A D After modifying the model to incorporate the extraction of steam for the thermal load, simulation runs were carried out to predict the performance of the power plant at full- and part-loads *The authors are currently working on large-scale DH system integration modeling and the results will be published at a later date.
270
A. Ong'iro
et al.
42 •
40 38
100% (Thermal eft.) 100% (OUF)
%36
--*--
34
75% (Thermal
eff.)
75% (OUF)
32
A
30
i
i
i
i
i
i
i
i
¢
2
4
6
8
10
12
14
16
18
Thermal
Load
60% (Thermal eft.) 60% (OUF)
(MWt)
Fig. 6. Variation of thermal efficiencyand OUF with thermal load and power generation--105 MWe unit.
as the thermal load was varied from 0 to 18 MWt in steps of 2 MWt. To evaluate the improvement in the overall power-plant energy utilization efficiency, an overall energy utilization factor is defined which takes into account both the electrical power output and thermal load:
(8)
O U F = (W + THL)/Q~..
The results of the simulations are presented in Figs 5-8. It is clear that integrating a small-scale D H system will improve the overall energy utilization factor significantly with negligible effect on the electrical power output of these units. For the 105 MWe unit operating at 100% load, integration of an 18 MWt D H load increases the overall energy utilization factor from 34.8 to 39.8%, which represents an improvement of 14.4%. The associated loss in power dispatched from the unit is only 3.5 MWe, or only 3.5%. At part-load operation, the benefits of thermal load integration are even better; for example, at 60% load with an 18 MWt D H load, the overall energy utilization factor improvement is 23.9%, while the loss in electric power dispatched is only 5.4%. Similar results can be seen for the 150 MWe unit. Another approach for improving the overall energy utilization factor is to utilize the excess boiler capacity (if available) at full- or part-load operating conditions. This would allow maintenance of the electrical output of the power plant while servicing a certain thermal load. To study the implications of such a scenario, the model was used to simulate a 10 MWt load while maintaining the amount of power dispatched. To accomplish this objective, it would be necessary to increase the thermal load on the boilers to generate more steam. The model was used to estimate the additional boiler thermal load required, assuming that the turbine section efficiencies, pressure ratios and boiler efficiencies remain essentially constant, and using scaling for parameters such as auxiliary power and water make-up, and perturbing the steam mass flow-rate through the boiler. It was found that the additional boiler thermal load required is 4.9 MW. Thus, by increasing the fuel input at the boiler by 4.9 MW, it will be possible to generate the same amount of electricity at full load, while satisfying a thermal load of 10 M W and improving the overall energy utilization factor. 4.5 4 3.5 3 •
~ ~-~ 2.5 '~'
2 * -
~
100% 75% 50%
1 0.5 0 0
2
4
6
8 Thermal
10 Load
12
14
16
18
(MWt)
Fig. 7. Variation of lost electricity generation capacity with thermal load and power generation--150 MWe
unit.
ASPEN Plus evaluation of a steam CHP plant
271
42
• 38 ¸
100% (OUF) *
34; J"
0
75% (Thermal eft.)
75% (OUF)
32 30
100% (Thermal eft.)
q
i
i
i
i
i
p
i
i
2
4
6
8
10
12
14
16
18
50% (Thermal eft.)
50% (OUF)
Thermal Load (MWt)
Fig. 8. Variation of thermal efficiency and OUF with thermal load and power generation--150 MWe unit.
7. C O N C L U S I O N A thermodynamic model of a steam power-plant was developed using the ASPEN Plus shell to study the effects of integrating a small-scale D H system on power-plant performance. The accuracy of the predictions of the model was validated using field data from an existing power plant, and it was found that the model could simulate the power-plant performance with very good accuracy. A series of simulations were carried out using the model to evaluate the effect of integrating various thermal loads to the power plant under full- and part-load conditions. The largest thermal load modeled was equivalent to 18% of the unit electrical output. The results of the simulations clearly indicate that while improving the overall energy utilization factor of the plant, integration of a small thermal load does not affect the power-plant electrical output significantly. Thus, there may be significant advantages in considering servicing thermal loads, such as a district heating system, from power plants as substantial improvements in the energy utilization efficiency of the power plant is possible with little, if any, change in the electrical output. Acknowledgements--The authors gratefully acknowledge the financial support provided by the Natural Sciences and Engineering Research Council of Canada (Operating Grant OGPOO41739), Canadian Commonwealth Scholarship and Fellowship Plan, and Nova Scotia Power Inc.
REFERENCES ASPEN Plus, A S P E N Plus User Guide. Aspen Technology, Cambridge, Massachusetts (1988). A. O. Ong'iro, V. I. Ugursal, A. M. AI Taweel and G. La Jeunesse. Using the ASPEN Plus shell to simulate the performance of gas turbines. Proc. A S M E 1994 Engineering Systems Design and Analysis Conf., 4 7 July 1994, London, pp. 57-64 (1994). A. O. Ong'iro, V. 1. Ugursal, A. M. A1Taweel and K. Blamire. Simulation of combined cycle power plants using the ASPEN Plus shell. Heat Recovery Systems & CHP 15 (2), 105-113 (1995). J. N. Phillips. A study of the off-design performance of IGCC power plants, Ph.D. thesis, Stanford Univ., California (1986). K. R. Stone. ASPEN simulation of fluidized bed and entrained flow integrated gasification combined power plants. Technical Note, DOE/METC-85/4027. US DOE, Morgantown Energy Technology Center, Morgantown, West Virginia (1985). M. R. Erbes and R. H. Eustis. A computer methodology for predicting design and off-design performance of utility steam turbine generators. Proc. American Power Conf., Chicago, Illinois (1986). R. B. Smith. The calculation of steam-turbine reheat factors. Trans. A S M E (1938). R. C. Spencer, K. C. Cotton and C. N. Cannon. A method of predicting the performance of steam turbine-generators... 16,500 kW and larger. A S M E J. Engng Power, October (1963).
