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Car assembly plant cogeneration system.

A cogeneration power plant was designed to efficiently meet electric peak capacity of about 4.4 MW and peak cooling capacity of about 1,400 tons (4924 kW) for a car assembly plant. The project uses a combination of combustion turbine and gas engine-generators, with waste heat recovery for high temperature hot water absorption chiller from combustion turbine and gas engine exhaust and for low temperature hot water absorption chiller from engine jacket water circuit and economizer circuit of waste heat recovery boilers (WHRB).

While upgrading car painting facilities from manual control to robotic reciprocators, a major car assembly plant in Pakistan decided to install a cogeneration system to meet large air-conditioning requirements for its central paint booth, as well as supply the electric power requirement for most of the car assembly facilities. The car manufacturer's decision was partly based on frequent utility power failures, as well as a recent steep increase in the power tariff.

Existing equipment installations included natural gas-fired boilers (three boilers, each with a peak 12 MMBtu/h [3517 kW] capacity) that provided 90[degrees]C (194[degrees]F) hot water to the central paint booth facilities to provide heating of paint booth areas in winter and keep paint tanks at a controlled temperature. Heating of paint tanks is required throughout the year, and hot water requirements are met by one hot water boiler in summer and by all three boilers for a few hours during peak winter mornings. Typically, one hot water boiler is redundant and is on standby in case one operating boiler needs to be shut down for service.

Since the air-conditioning requirements of the central paint booth were pressing, it was decided to use existing 90[degrees]C (194[degrees]F) hot water boilers for absorption chillers that could be installed in a shorter time span of eight months (Phase 1), and to continue with development of the cogeneration power plant (Phase 2) for installation in 18 months.

To meet the additional hot water requirements for absorption chillers in Phase 1, it was decided that available capacities of two hot water boilers would be used to meet both paint booth heating (for paint tanks) and air-conditioning requirements of paint booth areas during expected mild summer season periods. Since this Phase 1, with high operating costs due to gas-fired hot water boilers for single-stage absorption chillers, was to cover only initial requirements of air-conditioning, selection of absorption chillers was based on the following total capacity parameters:

* Peak load of 1,400 tons (4924 kW) cooling for the central paint booth would be met by a chilled water storage system in such a way that with peak chiller cooling capacity of 1,000 tons (3517 kW), nighttime and partial daytime thermal storage would provide peak-shaving during the peak load time (about seven hours during the day), meeting cooling requirements of the facilities as per the cooling load profile in Figure 1.

* The combustion turbine-generator at a 1,450 kW rating would require about 110 tons (387 kW) cooling for inlet air to meet full load requirements during peak summer conditions. The combustion turbine and gas engine-generator schematic is shown in Figure 2.

* For 1,110 ton (3903 kW) cooling capacity, absorption chillers were selected for both 120[degrees]C (248[degrees]F) high temperature hot water from combustion turbine and gas engine exhaust heat recovery and for 95[degrees]C (203[degrees]F) low temperature hot water from engine jacket water heat recovery at 90[degrees]C (194[degrees]F), plus additional heating through 120[degrees]C (248[degrees]F) hot water in the heat exchanger for peak load operation. This peak cooling capacity would be available from waste heat recovery from one 1,450 kW combustion turbine-generator and two 1,450 kW gas engine-generators.

* With available 120[degrees]C (248[degrees]F) hot water from the previously described exhaust waste heat recovery, an economical single-stage absorption chiller was selected to provide 700 tons of cooling at peak load operation as per the piping schematic shown in Figure 3.

* With the available 90[degrees]C (194[degrees]F) hot water from the previously described jacket water heat recovery and from additional heating capacity obtained from economizers in both exhaust heat recovery boilers for the combustion turbine and gas engines, with further heating to 95[degrees]C (with 120[degrees]C [248[degrees]F] hot water), an economical single-stage absorption chiller also was selected for this application to provide 410 ton (4924 kW) of cooling during peak load operation as per the piping schematic shown in Figure 4.


To maintain the central paint booth at 27[degrees]C (81[degrees]F) and 70% relative humidity (for reciprocators) with all-outside air cooling, the air-conditioning system design required a peak cooling load of 1,400 ton (4924 kW) under high-humidity monsoon conditions, normally prevalent for approximately eight to 10 weeks per year in July, August and September. Cooling loads during hot summer conditions in Karachi (40[degrees]C [104[degrees]F]) are much lower due to less air moisture and related lower enthalpies.

Under peak cooling load requirements, the central air-conditioning system capacity is used for the main central paint booths and for combustion turbine inlet air cooling. However, under reduced cooling load periods at the central paint booths (which last for most of the year except the monsoon period as described), the central cooling capacities, based on the thermal storage system, are extended to the bumper paint booth (with a peak cooling load of 200 ton (703 kW), which is to be met by air-cooled chillers if a central chilled water source is not available) and air-conditioning for offices where ten 20 ton air-cooled packaged air-conditioning units have now been installed with chilled water cooling coils on the return air duct connections. The chilled water cooling source, available from the thermal storage system, ensures that packaged unit compressors do not operate for most of the year, saving up to 400 kW of power during that period, in addition to similar 400 kW saving due to central chilled water source for the bumper paint booth.

With the plant expansion plans, the total peak electrical load is expected to increase above 6 MW, so it was decided to install a cogeneration power plant for about 4.4 MW base load and to exclude power requirements for welding areas and variable loads of press shops from the cogeneration power plant, which would continue to be fed by the utility, with a diesel engine-generator as backup.

The central power plant, as detailed in Figure 2, based on use of one dual-fuel 1,450 kW combustion turbine-generator and three 1,450 kW gas engine-generators, is capable of meeting peak 4,350 kW gross load (including power load of plant auxiliaries), with one 1,450 kW generator (either combustion turbine or gas engine) on standby to provide load should one of the previously mentioned generators be out of commission for service. A 1,500 kW diesel generator is installed to supply black-start service for the power plant and also to provide additional standby power requirements as needed. If gas supply is disrupted to the 1,450 kW gas engines, the standby 1,450 kW diesel generator, in addition to diesel fuel operation of the combustion turbine, will serve to provide essential loads.

While the combustion turbine-generator provides high temperature waste heat recovery from the exhaust flue, gas engine-generators provide both high temperature waste heat from engine exhaust and low temperature waste heat from engine jacket water circuits. Piping for the gas engines' jacket waste heat recovery circuits were based on typical details for such applications with plate-type heat exchangers.

Energy Management System

The energy management system (EMS) is based on a cogeneration power plant consisting of the previously described 1,450 kW combustion turbine, three 1,450 kW gas engines and one 1,500 kW diesel engine-generators, with thermal load-following mode to help ensure the highest cogeneration efficiency. The EMS has been installed to provide:

* Monitoring of various data through a central system onto a computer;

* Calculations for the optimum pieces of equipment that should be used based on highest cogeneration efficiency use and energy capable of being produced;

* High level interface to combustion turbine, diesel and gas engines and operating parameters to cover their display onto the computer; and

* Assurance that both thermal and electrical energy requirements would be met with maximum cogeneration plant efficiency by the EMS designating an optimal combination of installed operational generating equipment.



The EMS covers the combination of generating equipment required to be operated and is displayed on the control room computer console so an operator manual-informed decision can be made to either start or stop various CHP plant equipment.

The EMS also monitors various key parameters of the engines, gas turbine and waste heat recovery boilers. Data can be provided, based on time of day, week, month, year and past history, recommending the use of various options via indicators on the computer console.

Thermal Load-Following Mode

Off-Time Operation. The factory and office off-time load is expected to be handled by either the combustion turbine-generator or one gas engine-generator (depending on season), with the option of using waste heat recovery. The standby diesel generator set is always available on an "auto mains failure basis" as per facility requirements.

Normal Production-Time Operation. The factory's air-conditioning load for the central paint booths would dictate which equipment to operate. The primary indicator to determine the performance of air-conditioning and resulting thermal loads (from waste heat recovery of the cogeneration power plant) is the supply chilled water temperature to cooling coils located in the central paint booth areas.

The EMS also confirms the desired selection of equipment to the operator so that the combined operation of CHP plant equipment ensures electric power requirement with optimal use of absorption chillers serving air-conditioning and also the thermal energy requirements of the paint tanks' temperature control.

The hot water supply and return water temperatures together with flow are continuously measured, and the thermal energy being exported to the absorption chillers for air-conditioning and the thermal energy for paint booths supplied by the CHP plant equipment are also recorded. Electricity meters are used to measure the amount of electricity being exported by the CHP plant equipment.


Based on the heat load being provided, the EMS designates the use of various CHP plant equipment as described later. Also included is the option for the operator to use existing direct-fired boilers provided they are required to supplement thermal energy (possibly due to reduced waste heat recovery) to meet the absorption chiller requirements.

Season Selection

Seasonal selection is performed manually by operator and transmitted as an input to the EMS. The three modes of seasonal selection provided are: winter, spring/autumn, and summer. These selections are used to dictate typical thermal and electrical peak load profiles, which are determined as follows:

* Winter (about two months) December/January;

* Spring/Autumn (about three months) November/February/March; and

* Summer (about seven months) April to October.


The electrical online meters are used to compare the projected typical electrical load with the actual electrical load. Similarly, air-conditioning and thermal energy demands are compared to meet the facility loads at the highest CHP plant efficiency when possible. The EMS only provides recommendations of equipment to be operated and the control room operator manually ensures compliance as per actual working conditions.

Seasonal Recommendations

Off Time (10 p.m. to 6 a.m.) One gas engine-generator of 1,450 kW operates in typical winter mode and gas turbine-generator operates in typical summer mode.

On Time (6 a.m. to 10 p.m.) The following sequence is to be followed for operation of further generators (covering gas turbine or gas engine).

The EMS advises the optimal start time based on the previous day's start-up log. The recommended start time is displayed on the computer screen via "time to start" or "recommended start time" in front of the equipment that is being recommended by the EMS.

In winter mode, three gas engine-generators are used to meet power requirements and cooling for the factory and offices, with engine waste heat being used for absorption chiller operation and for thermal loads (heating in paint booth areas).

In spring and autumn mode, waste heat from three gas engine-generators is used to provide absorber cooling for the factory and offices and also hot water for heating in the paint booth areas. Depending on thermal load demand, if both absorption chillers need to be operated, the EMS recommendation may include combustion turbine-generator operation in addition to the three gas engine-generators in operation (all under predetermined proportional load sharing scenarios to match the required power-heat ratio) to meet the required facility power and thermal load requirements at high cogeneration efficiency. All four generators would be operating at part load, to match the waste heat use for the power demand and therefore, maintain high cogeneration efficiency.

In summer mode, waste heat from the combustion turbine-generator and from the two 1,450 kW gas engine-generators provide factory air-conditioning and thermal energy requirements for the central paint booth areas. Depending on thermal load demand, the EMS recommendation may include combustion turbine operation with either two or three gas engine-generators for correct power and thermal load requirements, (all under proportional load sharing to match the required power-heat ratio) with full waste heat recovery for air-conditioning and thermal loads as explained above.

The EMS continuously monitors exhaust flue temperatures from each waste heat recovery boiler (including separate monitoring of each gas engine exhaust flue) to help ensure the highest CHP plant efficiency. Manual selection of combustion turbine and gas engine-generators operate in accordance with EMS recommendations and their operations are tracked to provide optimum waste heat recovery to meet thermal and air-conditioning loads at the highest CHP plant efficiency.

If the combustion turbine cannot be operated due to maintenance shutdown, three 1,450 kW gas engines are operated so that essential absorption chiller air-conditioning load is met by operating standby direct-fired boilers together with gas engine waste heat recovery boilers for both 120[degrees]C (248[degrees]F) and 90[degrees]C (194[degrees]F) hot water circuits.

During the day, thermal energy demand and air-conditioning load is compared for 60 minutes or more. If the average load during the occupancy period demands absorption chiller operation, then starting the next day, an absorption chiller is selected to be operational prior to the anticipated peak cooling load during afternoon hours. For recommended cooling, one or both absorption chillers will be operated as per requirements.


To monitor equipment and plant efficiencies, various parameters of equipment are calculated and used to provide indices (all efficiencies and parameters are based on 845 Btu/ cft lower calorific value of gas). These indices are:

For gas turbine and gas engines:

Gas fuel consumed/electrical energy produced = cubic feet of gas (cft)/kWh

Efficiency of electrical generation =

Electrical Load in kW x 3,413 Btu/ Gas flow rate in cft x 845 Btu/cft

For hot water boiler:

Thermal energy gas input/thermal energy hot water output = cft/Btu

Efficiency of Hot Water Boiler = Thermal Energy Output (Hot Water)/ Thermal Energy Input (Gas)

Produced Heat (Heat Recovery Boiler) ([PH.sub.HRB]) = Flow in gpm x 500 x Temp. Diff. [degrees]F, Btu

To obtain this heat, the conventional gas-fired boiler with 80% efficiency would have consumed:

[PH.sub.Boil] = [PH.sub.HRB],/0.8 Btu

Efficiency of cogeneration system =

[PH.sub.Boil] + (Elec. Load in kW x 3,413 Btu)/ Total Gas Flow Rate in cft x 845 Btu

Using the above information, the EMS calculates fuel chargeable to power (FCP) where the FCP corresponds to the net consumption of gas to be charged to the CHP cost of power delivered to the facility.

FCP = (Total Gas Flow in cft/h x 845 Btu) - [PH.sub.Boil],/ Total kWh Produced (by GT and Gas Engines) Btu/kWh

Cost of FCP is then calculated at the latest natural gas tariff.

The above indices are recorded and maintained in an archive. It is possible to view the status of any equipment efficiency for extended periods, to find out how the performance has improved or deteriorated over the span of time for the particular subsystem.

Each index is provided with an alarm option, such that an alarm is produced when it drops below a specific pre-set limit. This limit setting cannot be changed without suitable authorization.

The energy management system provides cost of operation of main prime-movers. This is based on current fuel rates, operating and manpower costs (all of these are constantly upgraded by the owners to be fed into costing algorithms). This cost is then compared to a "virtual" utility power cost (provided by the owners) and cost saving is displayed on the screen.

This saving is calculated through the following: Total power produced in kWh x (tariff)/kWh (rate if bought from the utility), to be compared with following:

[Fuel Chargeable to Power (FCP) + Operation Cost] x Total Generated kWh units + Labor Cost

The difference of cost of power saved and actual cost of power generated provides the savings. All the previous cost savings are totaled and can be reset only when authorized.


The original screening analysis, based on electric and natural gas tariffs as detailed under the sidebar "Commissioning Tests," had projected a payback period of four years. Since the cogeneration power plant has been operating efficiently (providing cogeneration efficiency consistently in excess of 100% during summer operation, as explained previously) and as the comparable electric utility tariff has increased at a much higher rate (presently about $0.14/kWh), the actual payback period is estimated at less than four years if the cogeneration power plant is operated as originally foreseen for 350 days in a year, with part-load during weekends.

Commissioning Tests

Performance data during peak plant operation, certified during commissioning tests.

* Gas turbine-generator, 1,450 kW rating (with inlet cooling to 59[degrees]F)

--kWh generated in one hour = 1,450 kWh

--Gas consumption in one hour = 24,400 cft

--Electrical efficiency = 24%

* Gas engine-generators, two in operation, each 1,450 kW rating

* kWh generated in one hour = 1,450 kWh, for two sets

= 2,900 kWh

--Gas consumption in one hour = 15,400 cft, for two sets = 30,800 cft

--Electrical efficiency = 38%

* Total for above power generation, kWh generated in one hour = 4,350 kWh

--Gas consumption in one hour = 55,200 cft

* Waste heat recovery from gas turbine exhaust (from Btu meter in high temperature hot water circuit):

--Waste heat recovery in one hour = 10.5 MMBtu

* Waste heat recovery from WHRB economizer circuits (from Btu meter in low temperature hot water circuit):

--Waste heat recovery in one hour = 5.8 MMBtu

* Waste heat recovery from gas engine exhaust (from Btu meter in high temperature hot water circuit):

--Waste heat recovery in one hour = 2.85 MMBtu; for two sets = 5.70 MMBtu

* Waste heat recovery from gas engine jacket water (from Btu meter in low temperature hot water circuit), to supply to both 410 ton absorption chiller and paint heating circuit:

--Waste heat recovery in one hour = 3 MMBtu; for two sets = 6 MMBtu

* Total waste heat recovery hot water =

(10.5 + 5.8 + 5.7 + 6) = 28 MMBtu

* Conventional boiler input with 80% efficiency = 35 MMBtu

* Efficiency of cogeneration system:

35 MMBtu + (4,350 kW x 3,413 Btu)/55,200 cft x 845 Btu = 106.9%

* Fuel chargeable to power (FCP),

(55,200 cft/h x 845 Btu) - 35 MMBtu/4,350 kWh = 2,676 Btu/kWh

* Cost of fuel ($4.70 per MMBtu) = $0.013/kWh

* Estimated cost of operation and maintenance and financial depreciation = $0.037/kWh

* Utility tariff = $0.11/kWh

* Saving = $0.06/kWh

Note: [degrees]C = [degrees]F - 32 x 5 9; 1 MMBtu = 1.06 GJ; 1 cft = 0.028 cubic meters; 1 Btu = 1.06 kJ; 1 ton = 3.517 kW

By Ainul Abedin, Fellow/Life Member ASHRAE

Ainul Abedin is owner/principal, Ainul Abedin Consulting Engineers, Karachi, Pakistan. He is an international member of TC 1.10, Cogeneration Systems.
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Author:Abedin, Ainul
Publication:ASHRAE Journal
Article Type:Reprint
Geographic Code:9PAKI
Date:Jan 1, 2011
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