https://doi.org/10.1016/j.ccst.2022.100041
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The Techno-Economic Assessment (TEA) is intended to determine the technical feasibility and economic impacts of implementing CO2 capture on Unit 3 at Hunter Station. Hunter Station is located in Castle Dale, Utah. Unit 3 is a 511 MWg boiler Unit 3 that is equipped with low-NOx burner technology and over fire air for NOx mitigation, a baghouse for particulate matter removal, and wet flue gas desulfurization (WFGD) for SO2 control Figs. 3.(a) and (b) present the current CO2 emissions rates from the facility, without CO2 capture technology.
Fig. 3. Daily rates of CO2 emission from Unit 3 at Hunter Station of PacifiCorp, Utah (a) rate in mass per year, mm ton/yr. (b) rate in mass per power generation, lbs/MWhg. Showing the average emission for 9000 hrs. Three design criteria as 90%, 60% and 1000 lbs/ MWh,g of CO2 capture for techno-economic analysis (McPherson et al., 2018)
As part of the TEA, the major balance of plant (BOP) impacts have been identified and quantified, including loss of power generation due to both the auxiliary power load and the required process steam to be supplied from the base unit. Other BOP impacts are identified, including cooling and process water consumption, wastewater generation rates, and solid waste generation rates.
The major inputs and assumptions used as the basis for the design of the Hunter 3 CO2 capture system are summarized in Table 2. These inputs were based on information provided by Hunter Station. Assumptions based on typical industry standards and engineering judgment were also used, where appropriate.
Table 2. Summary of design inputs and assumptions (McPherson et al., 2018)
| Variable | Units | Hunter Unit 3 |
|---|---|---|
| Fuel Composition | % (mass) | Carbon – 65.8Hydrogen – 4.60Nitrogen – 1.40Sulfur – 1.25Chlorine– 0.02Oxygen – 8.03Moisture – 7.00Ash – 11.90 |
| Boiler Sizing | MWgross | Full – 511Low –170 |
| Auxiliary Power Consumption | % | Full – 12.8Low – 5.9 |
| Heat Input | MMBtu/hr | Full – 4,806Low – 1,880 |
| Unit Capacity Factor* | % | 77 |
*Note: Future expected capacity factor information was provided by station personnel; 77% represents the expected average over the next decade of operation.
Table 3 summarizes the current properties of the Hunter 3 flue gas downstream of the WFGD system. The information is based on flue gas data provided by station personnel and recent stack test results, where available.
Table 3. Current flue gas properties based on mass balance (McPherson et al., 2018)
| Variable | Unit | Hunter Unit 3 |
|---|---|---|
| Flue Gas Concentration | vol % | N2 – 70.32 |
| O2 – 4.17 | ||
| H2O – 13.22 | ||
| CO2 12.29 | ||
| lb/TBtu | Hg – 0.09 | |
| lb/MMBtu | NOx – 0.31 | |
| SO2 – 0.14 | ||
| HCl – 0.002 | ||
| PM – 0.004 | ||
| ppm | SO2 – 56 | |
| SO3 – 3.5 | ||
| Total Volumetric Flow | acfm | 1,574,000 |
| Total Flue Gas Mass Flow | lb/hr | 5,248,000 |
| Temperature | °F | 123 |
| Pressure | psia / in. wc. | 12.063 / +1 |
SO2 flue gas data was provided by the station, and the highest average stack SO2 content was selected as the basis to be conservative. Associated utility consumption rates were estimated based on these facility parameters and CO2 quality requirements.
As part of this evaluation, three different CO2 capture rates were explored.
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The largest design was based on achieving 90% removal of the CO2 from the base facility, which sizes the capture system based on 100% of the Hunter 3 full load flue gas rate.
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The second-largest design assumed 65% capture from the base facility, which sizes the capture system based on approximately 72% of the Hunter 3 full load flue gas rate.
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The smallest design uses an equivalent capture rate to an emission rate of 1,000 lbs CO2/MWh-gross as the basis. Based on the Hunter 3-unit size and CO2 concentration, this results in a capture system sized for approximately 48 % of the Hunter 3 full load flue gas rate.
Table 4 summarizes the expected Hunter 3 CO2 capture facility requirements and estimated utility consumption for each of the three capture ranges. This information is estimated based on the team’s understanding of the MHI process, outputs from the mass balance, and pipeline standards for CO2 delivery.
Table 4. CO2 capture facility requirements and CO2 quality (McPherson et al., 2018)
| Variable | Unit | Case 1 (65% Capture) | Case 2 (90% Capture) | Case 3 (1,000 lbs/MWhg) |
|---|---|---|---|---|
| CO2 Capture | – | 65% | 90% | 48% |
| CO2 Stream Purity | % | ≥ 95 | ≥ 95 | ≥ 95 |
| CO2 Product Temperature | °F | 95 | 95 | 95 |
| CO2 Product Stream Pressure | psia | 2,215 | 2,215 | 2,215 |
| CO2 Production | lb/hr | 640,000 | 887,000 | 473,000 |
| ton/yr | 2,159,700 | 2,991,500 | 1,595,200 | |
| Capture Island Size | MWe | 370 | 511 | 273 |
| lb/hr | 3,790,000 | 5,248,000 | 2,799,000 | |
| acfm | 1,137,000 | 1,574,000 | 840,000 | |
| CO2 lb/hr | 712,000 | 985,000 | 526,000 | |
| CO2 Emissions | lb/MWh | 675 | 193 | 1,002 |
| Aux Power* | MW | Compressor – 18 Process–33 | Compressor –18 Process – 46 | Compressor – 13Process –25 |
| Steam | lb/hr | 788,000 | 1,000,000 | 617,000 |
| Raw Make Up Water | gpm | 2,600 | 3,600 | 1,900 |
| Demin Make Up Water | gpm | 20 | 28 | 15 |
*Note: Aux power requirement listed in the existing plant aux power requirements.
The capture facility at Hunter will consist of one (1) x 100% train for any of the three capture facility sizes. Multiple trains are typically necessary and would require an additional capital cost. In addition, as the operation of this unit is not critical to the operation of Hunter 3, complete train redundancy is not required. Redundancy on large complex pieces of equipment, such as the vessels and ID fans, is not necessary as this equipment is typically very reliable based on industry experience. In addition, heat exchangers, compressors, and other large components are expected to have very high availability, with regular inspections and maintenance of these pieces of equipment during scheduled outages.
Integration with Hunter Unit 3
The major process equipment and BOP systems needed for a complete CO2 capture system require a very large footprint. The Hunter property includes a relatively large open area directly adjacent to Unit 3, which was originally allocated to build Unit 4. This area is sufficiently sized to accommodate the CO2 capture facility and to be close-coupled to Unit 4. The proximity of the CO2 capture equipment reduces the costs of some BOP items by reducing the pipe and ductwork runs from the existing Unit to the new facility.
The ductwork to the Hunter 3 CO2 capture system will be tied in downstream of the existing WFGD system, prior to the stack breaching. A booster ID fan will be located in the CO2 capture facility pull the slipstream flue gas through the ductwork to the CO2 capture facility. MHI’s design includes locating the booster fan between the quencher and the absorber, where the gas is fully scrubbed and cooled.
The scrubbed flue gas will exit the absorber vessel through a new stack. This generates a secondary emission point that will have to be incorporated into the existing Hunter air permit. While the overall emissions are expected to be reduced based on the polishing scrubber and CO2 capture system, there is the potential for an increase in volatile organic compounds (VOC) or aerosol emissions. In order to minimize the release of these emissions, a second water wash is typically included in the absorber design.
The regeneration energy for the stripper comes from low-quality steam, which can be provided by the unit’s existing steam cycle or by a new steam generation unit. For this study, steam will be extracted from the existing steam turbine. Low-quality steam will be extracted from the crossover between the IP and LP sections of the turbine. The steam quality at the tie-in location is at a higher temperature and pressure than required by the boiler. Some pressure will be lost through the piping from the boiler island to the CO2 capture island, but pressure reduction and attemperation will be required once the steam reaches the CO2 island. The associated condensate from the reboiler will be pumped back to the base plant’s condensate system at the feedwater heaters.
Based on the size of the 2-capture facility, it is expected to be designed with 50% turndown capability. This is especially necessary for the 90% capture case, where the system is designed to treat 100% of flue gas at full load. When the base unit is dispatched at a lower load, the CO2 capture equipment will need to be turned down to account for the smaller flue gas flow.
As part of the study, the Hunter 3 steam turbine heat balances are reviewed to understand approximately how much the unit will be derated due to process steam extraction. In addition, the heat balances were reviewed to ensure that the extraction rates for the maximum steam consumption case (Case 2) will not detrimentally impact the steam turbine.
The addition of a new cooling tower is included to provide cooling to the integrated heat exchangers in the CO2 capture facility. The CO2 capture system consists of a large number of heat exchangers used for process cooling as well as intercoolers to maintain the temperature within the various process vessels. Process water will also be required for the operation of the CO2 island equipment for pump seals and intermittently for solvent regeneration or filtering purposes. Based on the station water balances, there is a sufficient margin on the demineralized system that can be supplied for consumption at the maximum treatment design capacity. The cooling tower consumes a large quantity of water; however, the quality of this fresh makeup water can be a standard lake or well water. Information provided by the station suggests there is a sufficient margin in the makeup water capacity of the reservoir on site. To minimize the amount of makeup water required for the cooling tower, water is reused from the process to the maximum extent possible. Blowdown from the new cooling towers will be reused at Hunter station, by means of the bottom ash system, where the existing cooling tower blowdown water is sent.
The CO2 capture and BOP systems include a significant quantity of pumps, compressors, fans, and other components which will result in significant auxiliary power consumption. The primary power consumer is the compressor, which pressurizes the CO2 stream to the required pipeline pressure. The auxiliary power can either be provided by the existing unit or a new power generation unit. For the purposes of this study, it is assumed that power will be supplied by the existing Unit, which will lower the net unit capacity. Based on the expected unit capacity factor over the next decade, it is expected that the unit will be dispatched at a full load less consistently which may accommodate the loads associated with the CO2 capture system without negatively impacting the plant.
There is additional integration with the facility based on the disposal or treatment of solid and liquid wastes. Wastewater generated from the caustic scrubber will be treated by a new physical/chemical wastewater treatment system; the product steam will be used for makeup water to the new cooling towers, while the sludge will be disposed of in a landfill. Blowdown from the new cooling towers will be reused by the existing facility or routed to the facility’s evaporation ponds. Other potential waste streams include the degradation products of the amine-based solvent. As part of MHI’s and other commercial solvent-based systems, the degraded solvent will be filtered out occasionally and disposed of separately as hazardous waste.
Makeup water, cooling tower blowdown water, demineralized water, steam supply, and condensate return piping will be routed together from the boiler building to minimize the overall plant impact, and for ease construction.
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