(This article describes retrofit options of single-purpose electric generating power plants to combined heat and power/district energy operation).
Many cities are prioritizing modern district energy as the integrated solution needed for sustainable heating and cooling of the inhabitants.
In Quito, Ecuador (at the United Nations Conference on Housing and Sustainable Urban Development, 2016) 197 nations adopted a New Urban Agenda that recognizes modern district energy as a key solution to achieving decarbonization. District energy systems can reduce primary energy consumption for heating and cooling of cities by up to 50 percent. Such systems create synergies between the production and supply of heat, cooling, domestic hot water and electricity and can be integrated with existing single purpose electric generating plants converted to combined heat and power (CHP) operation.
Fossil steam and combined-cycle power plants generating electricity can be retrofitted to supply thermal energy for district heating and cooling (DHC) systems that deliver district energy (steam, hot water, or chilled water) to nearby customers. This type of CHP plants boosts the utilization of fuel energy considerably, increasing its competitiveness in both electricity and thermal energy markets. Such DHC retrofits can be especially beneficial to fossil steam turbine-based plants with high fuel prices or relatively low thermal efficiency. New thermal energy sales provide added revenue. By retrofitting plants located near customers in a downtown area, industrial park, or university, utilities can enhance energy services, helping to retain existing customers, attract new thermal energy customers, and provide new business opportunities for the community. Such DHC systems also reduce overall emissions by replacing multiple heating and cooling units with a single more efficient central system. Regulators may even allow utilities to apply emissions reductions as offsets to expand other generating facilities.
DHC cogeneration also provides electric system utilization benefits. For utilities with winter-peaking loads, district heating can offset electrical heating loads, reducing the need for new generating capacity or purchased on-peak power while retaining utility revenues. Plants used for peaking loads in the summer, but little-used in the winter, can be retrofitted to provide relatively high heat steam output and low-power output in the winter, improving year-round plant utilization. Further, DHC can be used to diversify loads through such strategies as providing chilled water for cooling in place of electricity, which flattens peak capacity needs.
District heating systems serving commercial, residential and industrial customers have been common in Europe for 80 years, particularly in Finland, Denmark, the Russian Republic and other states of the former USSR. Originally developed for fuel conservation, DHC cogeneration systems are now also widely recognized for their emissions-reduction capability.
Power Plant Retrofit Options
In order to put the retrofit options in perspective, let’s review the features of a CHP plant with a specially designed district heating turbine:
Figure 1: Principal Diagram of a CHP plant with a specially designed district heating turbine
• Suitable openings in the turbine cylinders for extraction of large amounts of low-pressure steam.
• Capability to control concurrently and independently electrical load and the steam extractions over a wide range of load
• Capability to operate in the condensing mode.
• Heating of the district water in stages, in series extraction heat exchangers.
• Minimum throttling of extraction steam to ensure optimal operation of the bleed system over a wide range of parameters.
Heating the district return water in two stages allows the production of additional work by the steam used for the first heating stage, improving overall plant efficiency. Note that the extracted steam does not supply the peak heat demand. For the short periods of peak requirements it is more economical to use a peaking boiler.
Based on the above information it is obvious that retrofit of electricity-only fossil steam plant to DHC involves diverting steam from the turbine cycle for direct use or to feed specially designed heat exchangers that condense the steam to raise the temperature of water supplied to a district heating system. Chilled water for district cooling can be generated by steam-driven chillers.
In a single-purpose power plant steam for DHC can be extracted at existing feed water heating extraction points, at new extraction points made in the turbine casing, or at crossovers between turbine sections. It is also possible to convert a low-pressure turbine to back-pressure mode by eliminating or bypassing the last stages and exhausting the total steam flow to a DHC condensing heat exchanger.
Retrofitting electric generating plants to provide thermal energy can increase total plant energy utilization efficiency to 70 percent or more, as much of the heat previously rejected to the condenser becomes marketable. Only in back-pressure mode operation is electricity production appreciably reduced. The greatest overall fuel efficiency can be achieved in applications where a large fraction of the turbine steam flow is extracted for district heating and cooling purposes. The quantity of steam that can be extracted is limited by minimum low-pressure turbine cooling requirements.
District heating system designs can vary widely. Some—mostly older—systems supply steam to the customers and do not return the condensate because there are no condensate piping (corroded during long term operation) or the condensate quality is unacceptable without extensive treatment. Modem DHC systems designed to provide commercial and residential space heating generally employ medium and low temperature closed loop hot water. Maximum temperatures are about 2500F, allowing the system to be designed with low-pressure equipment throughout. The low DHC temperatures also allow the use of relatively low-pressure steam to provide heat to the system, which in turn enables the greater part of the available enthalpy of the steam to be converted to electric power before extraction from the cycle.
During district heating load operation, the reduced steam flow to the condenser will:
Reduce the condenser heat load which must be removed by the circulating water.
Reduce the stage pressure at the lowest extraction which accounts for the lower condensate temperature to the deaerator.
Reduce the electric output.
Turbine retrofits can be accomplished in many different ways, depending on the nature of the plant and its role in the utility’s operations. The retrofit may be performed using a minimum-cost approach or done as a turbine cycle upgrade where every effort is made to maximize the power and efficiency of the cycle. The modifications to the turbine cycle may be as simple as piping a previously unused steam extraction point to the DHC system and modifying the operating mode. Conversely, for a large plant with a long projected useful life, the retrofit may include re-blading the entire turbine, altering the diaphragms and nozzles, changing the number of stages to be used, adding or altering feedwater heaters, and upgrading or replacing the control system. In general, however, minimal disturbance of the turbine casing is the recommended design approach. In cases involving an old and under-performing turbine in a plant with a useful projected life, such a wholesale renovation may be justified.
Some significant turbine modifications may be required just to permit reliable operation with greater steam extraction. For example, drawing steam for the DHC system can result in reduced pressures at the extraction points, which can produce unacceptable stresses on the original blades and diaphragms of the stages upstream of the extraction points. Reduced flows in the low-pressure stage downstream of the extraction points can produce unacceptable temperature distributions. These problems generally can be overcome with minor modifications.
There are several proven methods to retrofit steam turbines to feed DHC heat exchangers. Both steam extraction and use of a back-pressure cycle have been successful. However, converting to a back-pressure cycle generally entails major modifications to the low-pressure section of the turbine, which prevents the turbine from generating the original rated electrical output. The use of steam extraction allows more flexible operation and permits the electrical output to approach the original MW rating when extraction for district heating is not required.
In extraction-type designs, the number and location of points from which steam is drawn can vary widely, depending on the original cycle and equipment design, the required DHC temperature, anticipated power and heat loads, and economic considerations. In smaller and older plants, equipment limitations may govern extraction point selection. For example, configuration choices may be dictated by the availability of existing unused extraction connections or by the observation that some stages are relatively inefficient (these are good candidates for extraction points as less power is then lost by reducing steam flow to these stages). Where there are no external crossovers, the use of existing extraction points is strongly favored. If needed, these points may even be enlarged. Figure 2 illustrates a typical configuration using existing extraction points for heating district steam/hot water supply.
Figure 2: District Heating Configuration for a Turbine with Internal Crossover, Using Modified Existing Extraction Points
1-Boiler, 2-HP Turbine, 3- IP Turbine, 4-LP Turbine, 5-condenser, 6-DH Stage One heat Exchanger, 7-DH Stage Two Heat Exchanger, 8-Return from DH System, 9-Supply to DH System, 10-Bypass
Figure 3 shows a typical configuration for large plants with external crossovers and no design limitations that would restrict extraction point selection. The two-stage heaters are both supplied with extraction steam from the exhaust from the intermediate-pressure sections. The connections are made in the crossover lines between the intermediate- and low-pressure sections. Note that the intermediate pressure sections are asymmetrical, with the section having more stages supplying the lower-temperature heater. This permits the maximum amount of energy to be extracted from the steam before it is diverted to the DHC system. Such a configuration reflects the design of specially built DHC turbines being offered by major manufacturers. For retrofits to existing electricity-only turbines, this approach could require substantial modifications.
Another alternative, shown in Figure 4, provides steam from a low-pressure extraction point to the first-stage DHC heat exchangers and steam from the intermediate-pressure exhaust crossover to the second-stage heat exchanger. This configuration maximizes the extraction of useful energy, while providing greater steam flow to a portion of the low-pressure section. Such a configuration requires an available extraction point of sufficient size at a suitable pressure. Typically, in the configurations shown in Figures 3 and 4, the two DHC heat exchanger stages are approximately the same size, which yields the best overall efficiency.
Figure 3: District Heating Configuration with Extractions from Intermediate-Pressure Crossovers
1-Boiler, 2-HP Turbine, 3- IP Turbine, 4-LP Turbine, 5-condenser, 6-DH Stage One heat Exchanger, 7-DH Stage Two Heat Exchanger, 8-Return from DH System, 9-Supply to DH System, 10-Butterfly Valves, 11-Bypass
Figure 4: DH Configuration with Extractions from Intermediate-Pressure Crossover and Low-Pressure Stage
1-Boiler, 2-HP Turbine, 3- IP Turbine, 4-LP Turbine, 5-condenser, 6-DH Stage One heat Exchanger, 7-DH Stage Two Heat Exchanger, 8-Return from DH System, 9-Supply to DH System, 10-Butterfly Valves 11-Bypass
The proper apportioning of steam between the DHC heat exchangers and turbine stages downstream of the extraction points requires an active control system to meet the varying electric power and DHC loads. The butterfly valves in the crossovers from the intermediate pressure sections close with increasing demand for DHC and are equipped with stop points to maintain a minimum flow to the low-pressure turbines. The control network also ensures that the valves maintain sufficient pressure in the intermediate-pressure section to prevent unacceptable temperatures in the low-pressure section. Bypass valves around the DHC heat exchangers allow the system to maintain proper district heating system flow and temperature conditions during periods of reduced heating demand. In cases where external crossovers are not available, valves in the extraction lines to the heat exchangers represent the simplest control alternative, although internal valving arrangements may provide better performance.
Cycle Efficiency Effects
DHC retrofits reduce steam flow to the stages downstream of extraction points and decrease the feedwater heating. The associated mechanical and thermodynamic effects resulting from these changes must be evaluated when selecting a retrofit configuration.
The principal thermodynamic effect of DHC retrofits is the dramatic decrease in the waste heat rejected from the cycle. Because efficiency is most sensitive to the ratio of extracted heat to power generated, when only a small portion of the steam is extracted, the overall efficiency improvement will be minor. Of course, much greater efficiency improvements can be obtained when a significant portion of the steam flow is extracted for DHC.
The loss of generating capacity from reduced flow in downstream stages is inevitable. To minimize capacity loss and maximize generating efficiency, extractions should be made at the point where steam conditions closely match those required by the DHC heat exchangers. This maximizes power generation by the steam before it leaves the turbine. However, the ideal extraction points are not always accessible, and steam may have to be extracted at higher temperatures and pressures than necessary for district heating. For example, the intermediate-pressure/low-pressure section crossover lines are often the most convenient point for extraction, but the temperatures and pressures may be well above those required by the DHC heat exchangers.
This mismatch can be mitigated by passing the steam through depressurizing and de-superheating equipment, which makes the steam better suited for the heat exchangers but does not recover the energy that would otherwise be available for power generation. Alternately, it may be more economical to install an additional back-pressure turbine between the extraction points and the heat exchangers.
Diverting steam for DHC can reduce the amount available for feedwater heating. However, this reduction is partially offset by the higher enthalpy condensate returned from the DHC heat exchangers relative to the condensate from the main condenser. Nevertheless, modifications to the feedwater system may be required. If so, such modifications could range from a simple heater bypass to the installation of additional heaters. Factors affecting the necessary modifications include design objectives (e.g., minimizing first cost versus maximizing fuel efficiency), plant size, expected load patterns, remaining plant life, fuel costs, and plant design details. An important design consideration is the incorporation of energy from the heat exchanger condensate. EPRI recommends that drain coolers and heat exchanger condensate return points downstream of the main condensers be used judiciously.
The reduced steam flows and altered pressure profiles resulting from mechanical modifications required for reliable operation and alterations to the feed water system generally have only minor effects on the cycle efficiency. As a result, most plants retrofit for DHC cogeneration can still essentially match their pre-retrofit electrical outputs and efficiencies at zero extraction. If the retrofit is accompanied by upgrading or repair, an overall improvement in turbine performance may be achieved.
In addition to providing for steam extraction points, a DHC retrofit design must accommodate the mechanical effects of reduced flows, altered pressure differentials, and unbalanced thrusts. Turbine internals may have to be modified to both address these effects and maintain reliable service. For example, the extraction of additional steam for DHC generally produces higher than normal pressure differentials across the blades and diaphragms upstream of the extraction point, potentially requiring replacement of these components. Reduced flow to the low-pressure stages can raise operating temperatures, therefore added provisions for expansion may be needed even if the control system maintains the requisite minimum flow. Steam extraction for district heating can also lead to increased asymmetrical thrust loads, necessitating adjustments at bearings. Fortunately, these modifications can normally be made at a moderate cost.
Changes in the feed water system may be needed to achieve optimum performance and accommodate reduced extraction steam for feed water heating, as well as to provide for efficient condensate return from the DHC heat exchangers to the feed water system. Designers should also review the consequences of contamination by heat exchanger leaks and the need for any additional treatment equipment.
Reduced steam flow to the condenser can also necessitate mechanical changes. For example, with lower flow rates it may be possible (and usually advantageous) to operate at reduced back pressure. Such operation may create a need for additional vacuum pumping capacity to accommodate the higher specific volumes and increased in-leakage resulting from lower-pressure operation.
In developing a retrofit design for supplying steam to a DHC system, physical plant layout is also of prime importance. Not only must space be available for the new extraction lines and heat exchangers, but the spatial relationships must be appropriate. Locations and arrangements must allow for drain flows to be gravity-assisted where possible. Adequate net positive suction head (NPSH) must be provided for the various condensate return pumps. Any additions to the feed water heating system must still allow adequate plot space for tube-pulling and turbine lay-down areas.
Overall performance of a turbine cycle retrofitted for district heating can be quantified by comparison of before and after gross heat rates, and dimensionless ratio of district thermal power extracted to the reduction in generator electric output due to retrofitting. The larger the ratio, the greater the benefits are for retrofitting the turbine.
District heating system reliability depends largely upon the retrofit turbine allowable loadings and turbine modifications implemented. The installation of new, wider buckets and thicker nozzle diaphragms are often specified to enhance reliability and availability.
Examples of Power Plant Retrofit to District Heating Operation
Extraction of steam from the turbine results in a reduced steam flow to the low pressure end of the turbine. Sufficient steam must pass through the low pressure turbine section to cool the last stages of blades. While specially designed district heating turbines can operate with a minimum of 5% cooling steam for their last stages, retrofits of existing single purpose typically use 15-20% of the throttle flow for cooling these stages. During maximum district heating load operation, the reduced steam flow to the condenser will:
Reduce the condenser heat load which must be removed by the circulating water.
Reduce the stage pressure at the lowest extraction which accounts for the lower condensate temperature to the deaerator.
Reduce the electric output.
In order to demonstrate the technology of retrofitting electricity-only power plants to provide steam for DHC, two examples of such retrofits are presented below:
The original turbine was nominal 80,000-kW, 1800 r/min, 17-stage condensing unit designed to operate at 850 psig and 925°F.Makeup to the cycle was provided by an evaporator and demineralizer. The district heating water was to be heated from 120°F to 230°F at maximum heat load conditions. In addition, the following retrofit criteria were used:
• The 100 percent electrical output capability of the unit must be retained during pure condensing mode operation.
• The selected alternative should provide the maximum thermal efficiency at the lowest capital and operating costs.
• Thermodynamic constraints, including parameters such as steam flow and pressure changes in turbine elements, blade loading as a result of increased extraction, extraction line pressure drop limitations, windage loss in LP elements, etc., must be considered.
• Mechanical limitations such as the design of the turbine casing, physical arrangements, thrust loads, and space availability for extractions must be considered.
• The cogeneration system should reliably supply both heat and electricity.
• Other limitations, such as arrangements of other existing equipment and equipment removal and installation space during the construction phase, must be considered.
The four options considered for the retrofit included:
1. Bypassing of low-pressure feed water heaters
2. Modification of the low-pressure end of the turbine
3. Use of existing condenser for district heating
4. Conversion to backpressure operation.
Options 3 and 4 were eliminated as they involved a permanent reduction in electrical capability. Options 1 and 2 were developed as follows:
Option 1—the 9th and 14th stage feedwater heaters were removed from service and used in series to heat water for district heating. The disadvantage of this option is that the thermal output is limited compared with option 2. Option 2—this option was originally conceived as enlarging the existing extraction pipes or increasing the number of extraction pipes at some stages in order to remove a substantially increased quantity of extraction steam. However, since any modification to the casing was to be done at the factory, this concept was very expensive. Therefore, option 2 evolved into taking increased amounts of extraction steam at the 6th and 9th stages and replacing affected diaphragms in the turbine casing. The modified turbine cycle is shown in Figure 2 where the numbers in parentheses indicate the parameters after the retrofit.
The maximum heat extracted with option 2 is 42.3 MWt at the expense of 10.4 MWe. This option provides higher heat load and also results in a final feedwater temperature closer to the original. While both options required internal turbine modifications due to redistribution of extraction steam flows, the turbine manufacturer indicated that option 2 would be less costly. Thus, option 2 was used.
Implementation of this option necessitated the following internal changes to the turbine:
• Replacing the 7th and 10th stage diaphragms to decrease velocity in steam passages.
• Changing the 4th stage diaphragm because of nozzle passing frequency and bucket loading consideration.
• Changing the 3rd stage diaphragm because of higher loading.
• Thrust compensation was achieved by routing the leakoff from the balancing drum to a lower pressure without major modification.
Figure 5: Modification of Single Flow Turbine
This turbine was nominal 100,000-kW, 3600- r/min, 23-stage, tandem-compound, double-flow, reheat, condensing unit designed to operate with steam conditions of 1800 psig and 1050°F/1000°F.
Five major options were considered for unit retrofit. They included the four original options for single-flow unit described above, plus an option of using extraction steam from the crossover. The latter option is particularly attractive for a reheat turbine with external crossover, but it was rejected because the turbine has internal crossovers and the retrofit would necessitate a new hood. After screening, the following options received detailed attention:
Option 1—the 18th and 21st/22nd stage feedwater heaters are removed from service.
Option 2—in this option extraction flow from the 15th and 18th stages is increased and the affected diaphragms are replaced. The modified turbine cycle is shown in Figure 6.
Option 3—this option is similar to option 2, but uses increased extraction flows from the 15th, 18th and 20th stages. The low-pressure district heating condenser receives steam from the 20th stage and the high-pressure district heating condenser receives extraction steam from the 18th and throttled steam from the 15th stages. This option provides the most heat output.
Final feedwater temperatures for all options are about the same. Due to redistributions of extraction flows, all options need replacement of diaphragms and machining of inner shell rings. Turbine modifications for option 1 are the most costly and for option 3 the second most costly. In addition, option 3 requires a more complicated control and protection system than the other alternatives. Therefore, due to its lowest turbine modification costs and simpler control system, retrofit option 2 was used for implementation. This alternative yields a maximum district heat output of about 21.3 MWt at a corresponding electrical output loss of 5.8.MWe.
Implementation of option 2 requires the following internal turbine modifications:
• Replace the 16th stage diaphragm in the HP/IP shell.
• Replace the No. 4 inner shell and machine the outer shell to get proper inner shell to outer shell fit.
• Replace the 14th and 15th stage diaphragms due to nozzle passing frequency considerations.
• No thrust problems are anticipated. However, they could be compensated for by machining the rotor at the packings.
Single-purpose electric generating power plants located in relative proximity to heating and cooling loads can be economically retrofitted to combined heat and power operation.
Figure 6: Modified Two-Flow Turbine
About the author: Ishai Oliker is president of Joseph Technology Corporation and has been involved in Combined Heat and Power/District Energy development in the U.S., former U.S.S.R, Korea and China for 30 years. He is the former president of the International District Energy Association and the recipient of the honorable Norman R. Taylor Award. He is the author of 170 technical papers, 7 books and 15 patents, and numerous technical presentations to national and international conferences in the U. S., Europe and Asia.