During initial client discussions held at the schematic design phase on an unusual multi-use, multi-building application, our client expressed a preference for reducing the greenhouse emission (GHG) eco-footprint of both their planned Phase 1 and 2 building projects. That is, provided it could be demonstrated to be cost-effective on a life-cycle-cost (LLC) basis along with equivalent operational benefits and demonstrable annual energy cost-savings.
CASE STUDY
DBS decided to compare three alternatives investigated for powering the proposed Phase 1 industrial building facility:
• Alternative #1: Purchase electricity and natural gas (NG) from existing public utilities.
• Alternative #2: Construct conventional TG plant supplemented by electricity and NG purchased, as needed, from existing public utilities.
• Alternative #3: Construct a hybrid combined TG and TES, the latter to serve the needs of a subsequently planned Phase 2 adjacent office building HVAC also to be supplemented by electricity and NG purchased, as needed, from existing public utilities.
During our initial evaluation of the program requirements, DBS determined that the local electric power plant (EPGS) used a 30% efficient coal-fired facility and that the local gas utility could supply us directly with up to 125 psig NG if needed for the operation of the Phase 1 combustion gas turbine (CGT). We then determined that the optimum size for either the above referenced TG alternatives would require a 3.5-MW CGT after determining the Phase 1 design criteria summarized in Table 1.
We next explored using a TES system alternative to reduce the need to purchase power from local EPGS for the planned adjacent office building, which would enable peak load trimming (Figure 1).
COMPARING ALTERNATIVE TG SYSTEMS
Two comparative alternative approaches were developed to meet the electric, cooling, and heating requirements. Table 1 provides a breakdown of the building loads. Comparative CGT alternative configurations are shown in Figures 2 and Figure 3. Notice that they differ principally in the manner in which CGT exhaust heat is extracted and utilized.
Alternative # 2 employs a conventional CGT arrangement with a heat-recovery-steam-generator (HRSG), as illustrated in Figure 2.
Alternative # 3 employs a heat exchanger utilizing a non-volatile high-temperature resistant heat transfer fluid (HTHTF) to remove and transfer heat from CGT exhaust gas stream as illustrated in Figure 3.
Refer to Figure 4 for a schematic diagram of proposed Alternative # 3 trigeneration (ITG)/CGS plant.
Schematic diagram of Alternative # 1 conventional TG plant configeration (not shown).
Both Alternative #2 and Alternate #3 plants were sized to meet the average base electric load of the initial Phase 1 industrial facility (approximately 3.5 MW). However, the 3.5-MW CGT will turn down minimally on weekends and other periods of relatively low occupancy to match electric demand. Exporting energy to the serving utility was found to be uneconomical, since the cost to produce the electricity is typically greater than the amount that the utility pays for exported electricity. Electric, cooling, and heating loads used in the analysis are based on actual campus data and averaged into four seasonal 24-hr profiles. The CGT utilized in both alternatives require fuel consumption (at 3.5-MW electric output) of 42.7 × 106 Btuh (12.5 × 106 W). The HRSG utilized in Figure 2 was assumed to have an efficiency of 80%.
ALTERNATIVE SYSTEM DESCRIPTIONS
Having identified HRSG cyclic failure issues and related potential maintenance costs, DBS decided to seek an alternative, lower-cost means of extracting turbine exhaust waste heat without sacrificing overall cycle efficiency.
CGT back-pressure performance effects were investigated when attempting to select HRSGs for the preselected 3.5-MW power requirement. DBS found that the associated HRSG pressure drops ranged from 4.5 to 6.5 in. w.g. (1,121 to 1,619 Pa) depending upon the manufacturer. This corresponded to a 0.75% to 1.5% loss at rated CGT turbine power output. In selecting the CGT exhaust coil illustrated in Figure 3, it was determined that the turbine back pressure could be significantly reduced by control of CGT exhaust gas velocities and appropriate fincoil spacing, thereby improving delivered CTG power performance.
The proposed CGT configuration shown in Figure 3 utilizes the waste heat from the gas turbine driver exhaust at approximately 950°F passing through the Industrial Heat Transfer, Inc.’s (IHT) coil on its way to ambient at approximately 350° (or lower, depending upon condensation constraints). This heat is captured by recirculating the HTHTF.
The 300° HTHTF leaving the Broad direct HTF-fired absorption chiller (not shown) still had sufficient heat to generate several hundred gpm of hot water, depending upon the entering and leaving oil temperatures (e.g., if the absorption chiller is not being utilized, the HTHTF inlet temperature could rise to 350°, and lowering HTHTF temperatures below 250° increases the LMTD of the turbine exhaust heat extraction coil utilized in Figure 3, for example.
The inherently self-regulating ITG /GCS shown in Figure 4 met the nominal 1,040-ton (3,658-kW) cooling requirement of our 3.5-MW industrial project by employing more efficient, commercially available low-mass hybrid steam generators and utilizing a commercially available, nominal 1,040 ton (3,658-kW) adapted two-stage HTHTF heated absorption chiller with an assumed heat rate of 10,600 Btuh/ton (COP = 1.13).
The ITG/GCS plant portion can be functionally integrated with controls, plate-and-frame heat exchangers, turbine inlet cooling coil, pumps, interconnecting piping, CGT waste heat extraction coil, and prefabricated (for minimal on-site erection) water-type absorption chiller. The ICHP/GCS plant uses an exhaust-to-HTHTF heat exchanger (HEX) to recover the exhaust heat by heating the HTHTF from approximately 250° to as high as 600° (316°C).
The HTHTF is then used to drive a two-stage absorption chiller followed by a plate-and-frame HEX to produce HHW. Note that domestic hot water can also be produced to further utilize the recovered heat. However, in the specific case analyzed here, the majority of recovered heat was used for campus heating and cooling demands, and dumping of recovered heat was minimal. Thermal utilization is arranged in this order due to the heat temperature and quality requirements of the various system components.
For example, the two-stage absorption chiller has a maximum HTHTF inlet temperature of 425° (218°C). Therefore, some of the recovered heat may need to be used prior to the two-stage absorption chiller, depending on the HTHTF supply temperature. Other commercially available HTHTF fluids, e.g., Santotherm –60, -66, -75, -VP1, or Bayer – KT 10, can also be used but differ in toxicity, and their use may result in reduced total heat recovery due to pinch point issues; they can also be used directly, provided its “temperature glide can be matched to a heating system or an absorption chiller as illustrated in Figure 4.
Proposed Alternative #3 uses an environmentally safe, non-volatile hydrocarbon oil heat transfer fluid within the modified CTG driven generator unit illustrated in Figure 3.
The proposed Alternative #3 CGT driven ITG/GCS illustrated in Figure 4 is capable of powering either an electric generator, screw, or centrifugal chiller (not shown) and operates through a manufactured coil located in the ducted turbine exhaust also shown entering the coil at approximately 250° (or below) and discharging at approximately 600°.
The ITG/GCS and CTG exhaust heat extraction system being developed by DBS, circulates a HTHTF as shown in Figure 4. Heat is extracted from the turbine exhaust via a heat exchanger similar to IHT fintube exhaust heat exchanger extraction coils. The heat is transferred to the HTHTF and can be used first to generate steam, which can be used for steam injection, independently determined to improve CGT driven electrical generator efficiencies by 10% to 15%.
The conventional TG plant uses a HRSG to produce high-pressure steam (HPS), which is used to drive a two-stage absorption chiller with an assumed steam consumption of 9 lb/ton (1.2 kg/kW) before being reduced to low-pressure steam (LPS). The LPS is then used to make heating hot water for distribution to the Phase 1 industrial building. Any energy not utilized by the conventional TG plant is rejected to a dump condenser (also shown in Figure 4) to be rejected to the atmosphere by either a cooling tower or radiator. The balance of heating and cooling loads that are not served by the cogeneration plant is served with gas-fired boilers and electric driven-centrifugal chillers.
In Figures 4 and 5, our proposed ITG/CGS and companion (future) TES system alternative involving a two-stage indirect (CGT waste heat) fired LiBr absorption chiller illustrated in Figure 5. In addition the following two ice TES options were also evaluated; namely:
• Option #1: Employ a low-temperature DEMTEC brine chiller illustrated in Figure 1, or
• Option #2: Employ a single-shaft, combination-induction motor/steam turbine driven low-temperature vapor compression cycle as illustrated in Figure 5.
Due to client budgetary constraints, these additional alternatives were not included in out Phase 1 design development project stage. However, it was decided that Option #2 will become part of our subsequent planned Phase 2 construction program, and adequate future space was provided in the Phase I mechanical equipment room to accommodate its installation, along with associated piping to a future POC. The ice storage tank (BAC) portion of the TES plant section illustrated in Figure 5 will be utilized in the future Phase 2 mechanical equipment room, along with interconnecting piping, pump, controls, and associated appurtenances.
It has a planned maximum operating temperature of 600°. This feature combines with the fluid’s characteristic low pressure drop to provide the TG building plant designer considerable latitude in being able to choose lower overall cost equipment, as opposed to employing conventional slow-reacting and costly HRSGs.
SUMMARY AND CONCLUSIONS
In terms of direct life-cycle costs, the economic impact of the CCP option was found to be significantly lower than the remote EPGS purchased power alternative. Furthermore, after including the difference in generating efficiencies employing available energy accounting, the ITG/TES alternative was found to be significantly more cost effective than the EPGS option. The LLC as outlined above for the ITG/TES plant (Figure 4) was also determined to be $101,752,000 U.S. vs. $108,752,000 U.S. for the alternative conventional TG plant system.
The two-stage absorption chiller illustrated in Figure 4 was able to produce 1,040 tons employing CTG waste heat and a ton-hour TES was required to meet the above referenced future Phase 2 office building design day 2,240 ton cooling load.
Accordingly, we reported to our client that the TG/TES option was preferable. It is our understanding that the subject industrial building complex is awaiting the approval of outside funding. Should the cost of natural gas and electricity continue to rise, we also reported to our client that the time required to amortize the additional TG/TES capital investment can be expected to drop.
The balance of the conventional TG plant system remains the same. As discussed above referenced claimed advantages of the ITG/GCS include smaller thermal mass of hybrid steam generator permitting quick response to varying building HVACR loads, and elimination of the need for 24/7 stationary engineers due to the low pressure operation of the HTHTF recirculation loop. Additionally, the reduced CGT exhaust extraction coil pressure drop improves CGT power performance.
The above analysis demonstrates that the approximate differential material cost for major equipment is the same for either alternative plant is not included in the estimate. The cost for major equipment for the conventional plant is approximately $150,000 higher than for the ITG/GCS plant, its differential annual energy cost was $59,000 lower, and its LCC cost savings after considering significant O&M cost differentials amounted to $6,986.000 U.S., after taking into account differences in smaller overall ITG/TES equipment footprint. ES
references
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2. Meckler, Milt, L. Hyman, and K. Landis. “Comparing the Eco-Footprint of On-Site CHP vs. EPGS Systems.” Proceedings ASME 2nd International Conference on Energy Sustainability. 2008.
3. Meckler, Milt and L. Hyman, eds. Sustainable On-Site CHP Plants: Design, Construction, Operations. New York, McGraw-Hill Book Company. 2010
4. US 6,651, 443 B1.
5. Meckler M., and L. Hyman. “Thermal Tracking CHP and Gas Cooling.” Engineered Systems. May, 2005.
