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Факультет: электротехнический (ЭТФ)

Кафедра: электротехнических станций (ЭС)

Специальность: «Электрические станции» (ЭС)

Тема магистерской работы:

Автоматизачия проектирования электрической части тепловых электростанций работающах на органическом топлве в условиях Нигерии.

Научный руководитель: Павлюков Валерий Александрович

Библиотека по теме выпускной работы

Собственные публикации и доклады

COST EFFICIENT AMINE PLANT DESIGN FOR POST COMBUSTION CO2 CAPTURE FROM POWER PLANT FLUE GAS

Author: Daniel Chinn1, Gerald N. Choi2,*, Robert Chu2 & Bruce Degen3
1ChevronTexaco Energy Technology Company, Richmond, California, USA
2Nexant, Inc., San Francisco, California, USA
3Bechtel, Inc., San Francisco, California, USA

COST EFFICIENT AMINE PLANT DESIGN FOR POST COMBUSTION CO2 CAPTURE FROM POWER
PLANT FLUE GAS
Daniel Chinn1, Gerald N. Choi2,*, Robert Chu2 & Bruce Degen3
1ChevronTexaco Energy Technology Company, Richmond, California, USA
2Nexant, Inc., San Francisco, California, USA
3Bechtel, Inc., San Francisco, California, USA

ABSTRACT

Nexant, Inc., an affiliate of Bechtel Corporation, was contracted by the CO2 Capture Project (CCP) to evaluate engineering options to reduce the cost of amine-based CO2 capture from an onshore, 400-MW natural gas combined cycle (NGCC) power plant in Norway. The initial phase of the work involves the design of a baseline NGCC and a 30-wt% monoethanolamine (MEA) retrofit plant designed to refinery/API standards. The second phase was a value-engineering exercise, where changes in equipment and design standards were implemented to create a low-cost retrofit MEA plant. In the final phase of the work, the NGCC and value-engineered MEA plant was redesigned as a new, integrated system. The CCP had developed capital and operating costs for the various design options, and have concluded that there are significant opportunities through value engineering and process integration to reduce the $/CO2 avoided cost of post-combustion CO2 capture.

INTRODUCTION

The CO2 Capture Project (CCP) is a major industrial/government collaboration developing new technology for the capture and geological storage of CO2. Industrial partners in this 3-year, $50 million (cash and in-kind support) effort are BP, ChevronTexaco, EnCana, ENI, Norsk Hydro, Shell, Statoil, and Suncor. Government funders include the U.S. Department of Energy, Norway (Klimatek program) and the European Union. CCP initiated three engineering studies with Nexant, Inc., to design a 30-wt% monoethanolamine (MEA) plant to capture CO2 from the exhaust gas of an onshore, 400-MW natural gas combined-cycle (NGCC) power plant located in Norway. Initially, a baseline plant design was established for the NGCC and the retrofit capture plant. The baseline capture plant was based on open-art, refinery/API equipment and design standards, using 30-wt.% MEA with oxygen inhibitors. Secondly, a value-engineering exercise was conducted where a number of cost-saving ideas pertaining to equipment, design, and operation were evaluated. Through process simulation and consultation with equipment vendors, a new, low-cost retrofit capture plant was developed. In the third and final phase of the project, a new-build concept was proposed for operating the NGCC and the low-cost capture plant as an integrated unit. CCP used the findings from Nexant to develop capital, operating, and avoided CO2 costs for the various processes.

Design Basis

All of the capture plants in this work are designed to accept the flue gas leaving the outlet of the heat recovery steam generator (HRSG) of the 400-MW NGCC. The NGCC produces roughly 1584 MMSCFD (1,769,500 Nm3/hr) of flue gas containing: 3.98 vol% CO2, 12.4 vol% O2, 8.34 vol% H2O, 74.39% N2, 0.89% Ar, and <1 ppm SOX and <10 ppm NOX. A total of 2850 tonne/day CO2 (representing 86% capture) is recovered from the MEA plant, dehydrated using heatless (adsorbent based) dryers to 50 ppmv moisture, and then compressed and pumped to 220 barg for transport to an enhanced oil recovery (EOR) site. The capture plant imports electric power and low-pressure steam from the NGCC, and uses locally available 11oC seawater (with 22oC return temperature) for process cooling. Both the baseline and low-cost retrofit plants were designed to have an on-stream factor of 94%, based on a NGCC on-stream factor of 96%. For these plants, a single, feed-bypass seal drum is provided to divert the flue gas to the vent stack in case the back pressure exceeds 10 inches (18 mm Hg).

BASELINE RETROFIT PLANT

The baseline capture plant is designed to open-art, refinery/API standards. Flue gas from the NGCC is processed in two parallel trains of 30-wt% MEA plant, heatless dryers, and compressors. Figure 1 below shows a simplified process flow drawing of the amine CO2 capture facility of the baseline plant. Note that flue-gas seal drum, details of the amine reclaiming system, filters, and other auxiliaries, as well as the CO2 dehydration and compression equipment are not shown.

Figure 1: Baseline retrofit capture plant
Each of the two trains in the baseline plant has the following equipment and design features:
1. Stainless-steel gas blower to overcome the pressure drop in the feed gas cooler and amine absorber, without raising the back-pressure on the NGCC plant.
2. Direct-contact, horizontal co-current humidifier, which reduces the flue-gas temperature entering the plant from 80oC to 47oC.
3. 37-foot (11.3m) diameter, 91-foot (27.9m) tall killed carbon steel absorber with two beds of random packing (304SS Pall Rings) for CO2 removal, and a water-wash section at the top of the unit to reduce the MEA in the clean flue gas from 500 ppmv to 3 ppmv.
4. 18-foot (5.5m) diameter, 86-foot (26.3m) tall stripper with two packed stripping (304SS Pall Rings) sections and a wash section. The top 6m of the vessel is clad with 304SS, while the remaining material is killed carbon steel. Each stripper is equipped with four kettle reboilers.
5. All heat exchangers are shell-and-tube, and all pumps are API-type.
6. Three-stage centrifugal, motor-driven compressors and a supercritical CO2 pump for the final compression stage.
7. Packaged, heatless-drying unit is used to meet the 50-ppm water specification in the CO2 product. It is placed after the second stage of CO2 compression.

LOW-COST RETROFIT PLANT
The low-cost retrofit plant is designed for less stringent specifications and equipment standards that are more suitable for non-critical services such as flue-gas CO2 capture. A comprehensive, value-engineering exercise and review of practices from other industries were used to generate a list of promising, technically-feasible ideas for a more cost effective design. Out of a total of 64 cost-cutting ideas, 8 were selected for the low-cost retrofit design. The criteria used to select an idea were (1) combined capex and four-years opex savings over the baseline plant, and (2) technical achievability. Figure 2 shows a simplified process drawing of the low-cost retrofit plant.

NGCC-CO2 capture plant
The key feature of the integrated plant is that 50% of the NGCC exhaust is recycled back to the front-end air compressor. The recycle halves the flow (1580 to 740 MMSCFD), reduces the feed oxygen content (12.4 to 4.7 vol.%) and increases the feed CO2 content (4.0 to 8.5 vol.%) of the gas entering the amine plant. For this study, it is assumed that the gas turbine could be designed for sustained operation at a 13% oxygen content in the combustor. It is known that oxygen content below 13% in the air-flue gas mixture could lead to flame stabilization problems in the combustor. The flue-gas cooler (which was eliminated in the low-cost retrofit case), is now required since the recycle flue gas (80oC) is much hotter than ambient air (15oC). If not cooled, it could adversely impact the NGCC performance. The integrated plant uses a HRSG-like indirect cooler with 11oC seawater to reduce the recycle gas temperature to 27oC. When mixed with fresh air, the combined feed to the air compressor is 22oC, which helps minimize the power losses from the gas turbine. Another feature of the integrated plant is the novel amine reboiling cycle. A portion of the stripper bottoms is pumped through the HRSG reboiling tubes in the NGCC to pick up heat before returning to the stripper. By relocating 75% of the stripping duty in the HRSG (a separate reboiler still needed for process control), only 25% of the duty needs to be supplied by the steam-heated kettle reboilers in the stripper. Therefore, three out of four kettle reboiler shells from the stripper could be eliminated. The other benefit is that heat is only transferred once instead of twice when steam is used as the heat carrier for stripping. The flue gas recycle makes it possible for the integrated plant to have a single-train absorber, with column diameter under 40-foot in diameter. The integrated reboil cycle enables a single-train stripper as well, since in previous designs stripper capacity was limited by the geometry of positioning four large reboilers around each column.

SUMMARY OF COST AND PERFORMANCE
The CCP is responsible for combining the many cost (capex, opex) and performance (net power output, efficiency) results from the technology providers into a common basis. The price assumptions were: $3.00/MMBTU for natural gas and $34/MWh for electricity from an uncontrolled NGCC. The basis capital charge rate applied in the CO2-cost calculations is set to 11%, corresponding to a pretax discount factor of 10% over a 25-year lifetime. Table 1 summarizes the cost and performance results in this work. All costs are quoted on a U.S. Gulf Coast (USGC) basis. Costs for transportation and geologic storage of CO2 are excluded.
TABLE 1: SUMMARY OF COST AND PERFORMANCE
For the three plant designed discussed in this work, the avoided-CO2 cost has contributions from: capital costs, operating and maintenance costs, and costs for energy and parasitic energy loss. All three factors are approximately of equal importance to the avoided-CO2 cost, although the contribution from energy costs is slightly higher than the other two. As shown in Table 1, the low-cost retrofit to a NGCC plant can reduce the CO2 avoidance cost by approximately 25% when compared with the baseline technology. With the low-cost integrated plant, the avoidance cost can be reduced by as much as 40%. Table 1 also shows how CO2 capture affects the cost of electricity for NGCC. The retrofit plant built to refinery/API standards would increase the electricity cost by 56%, while the low-cost retrofit plant would increase the cost by 41%. The integrated plant has the smallest incremental increase of electricity cost at 32%. The current study is based on the use of a generic 30-wt% MEA solvent. It is known that sterically hindered amine such as Mitsubishi’s KS-1 solvent [1,2] can offer significant reduction in operation costs (e.g., lower heat of regeneration and solvent circulation rate, low solvent degradation). Other solvents, such as those reported by Praxair [3] and Amit Chakma et al [4], appear to have lower energy requirements than commercial MEA. Thus, it is conceivable that even greater reduction in CO2 avoidance cost can be achieved by combining a superior CO2 -removal solvent with value-engineering and process integration.

CONCLUSIONS
This paper highlights engineering options for reducing the cost of a conventional, amine-plant retrofit to a NGCC power plant. Value-engineering (equipment changes, design standard changes), energy integration (ejector-assisted steam stripping), and process integration (flue-gas recycle, integrated reboiler cycle) can lead to significant reductions in the avoided-CO2 costs relative to the baseline technology.
There is significant future work and risk required for development of the integrated capture plant. The CCP recommends further work with gas-turbine and HRSG vendors to test the feasibility of flue-gas recycle and integrated reboiling. A low-energy CO2 solvent, such as Mitsubishi’s KS-1 should be seriously considered as an alternative to MEA, since it can reap additional benefits from the cost-cutting ideas proposed in this paper. Many of the equipment and design changes reported here were proven in other industrial applications; however, pilot testing would still be needed. The success of the integrated capture plant requires cooperation between the solvent, power plant, and process equipment/technology vendors.

ACKNOWLEDGEMENTS
The authors thank Nils Eldrup and Dag Eimer of Norsk Hydro for help with CO2 avoidance economic cost analysis, and to the CCP Post-Combustion team for their support. We also thank the many equipment vendors who have provided us with their valuable input: Alfa Laval, Sulzer Chemtech USA, Sulzer Pumps, Elliott Turbomachinery, SDS Spray Drying Systems, General Electric, PSB Industries, Inc., Howden Buffalo, and ATB Riva Calzoni, SpA. Lastly, the authors wish to thank the Norwegian Klimatek program for funding significant portions of this work.

REFERENCES
1. Iijima, M. 1998. Society of Petroleum Engineers. SPE39686.
2. Iijima, M. April 27, 2004. “Flue Gas CO2 Capture Technology of KS-1” Global Climate & Energy Project (GCEP) Workshop, Stanford University.
3.Chakravarti, S., Gupta, A., Hunek, B. 2001. First National Conference on Carbon Sequestration. Washington D.C.
4. Chakma, A., Tontiwachwuthikul, P. 1999. Greenhouse Gas Control Technologies. Elsevier Science Ltd.