Oxygen-blown Integrated Gasification Combined Cycle Research Articles

Performance evaluation of air-blown IGCC polygeneration plants using chemical looping hydrogen generation and methanol synthesis loop

Three chemical processing units by the integrated intermittent chemical-looping air separation (IICLAS), the chemical-looping hydrogen generation (CLHG), and the methanol synthesis loop (MSL) are integrated to retrofit the integrated gasification combined cycle (IGCC) system configuration. Four designs are presented and their performances are evaluated according to net efficiency, energy storage ratio (ESR), water saving ratio (WSR), and carbon emission rate (CER). An oxy-fuel IGCC power plant using IICLAS (Design 1) achieves 45.19% of net (thermal) efficiency. An oxygen-blown IGCC polygeneration plant with an integration of IICLAS and CLHG (Design 2) produces electricity and pure hydrogen simultaneously, and its net efficiency is up to 54.04%. An air-blown IGCC polygeneration (power/H2) plant without Brayton cycle and IICLAS (Design 3) ensures its net efficiency with 59.43%. An air-blown IGCC polygeneration plant with an integration of CLHG and MSL (Design 4) produces electricity, hydrogen, and methanol simultaneously, and its net efficiency could be as high as 60.42%. In addition, it is verified that Design 4 not only ensures the higher ESR due to hydrogen and methanol as storable fuels, but also it has an inherently lower environmental impact due to the lower CER, the higher WSR, and very low NOx emissions.

CO2-selective membranes for hydrogen production and CO2 capture – Part II: Techno-economic analysis

Syngas processing often requires separation of CO2 and hydrogen for hydrogen production, and the resulting CO2-enriched stream presents an opportunity for simultaneous CO2 capture. For example, syngas-based integrated gasification combined cycle (IGCC) power plants are envisioned as an efficient means of producing power from coal where CO2 capture technologies can be applied relatively easily. Membrane technology is an attractive approach for CO2 capture because of inherent process advantages such as simplicity, reliability, compactness and modularity. This paper (Part II of a two-part study) performs techno-economic analysis for CO2-selective membranes in three hydrogen production or utilization applications: methane reformer/pressure swing adsorption processes, oxygen-blown coal-fired IGCC power plants using GE gasification technology, and air-blown coal-fired IGCC power plants using Transport Integrated Gasification (TRIG) technology. These processes require membranes with CO2/H2 selectivities of 10–20, which can be provided using PolarisTM membranes. Hybrid approaches using a combination of membrane and cryogenic processes are evaluated for the production of high-pressure liquid CO2 ready for utilization or sequestration. The optimal membrane CO2/H2 selectivity and influence of CO2 capture rate on the cost of CO2 capture are determined, providing general guidelines for future membrane development. The cost of CO2 capture with these membrane processes depends not only on the feed CO2 partial pressure, but on the feed CO2 concentration as well.

Costs and performance of an oxygen-blown IGCC plant with CCS on a first-of-a-kind basis in Japan

The Japanese government recently funded the feasibility study (FS) on conceptual designs for oxygen-blown Integrated Gasification Combined Cycle (IGCC)+carbon capture and storage (CCS) systems. This paper presents the results of the economic evaluations conducted in the FS. The systems are first-of-a-kind (FOAK) bases with a net output power of 300MWe. It also illustrates a design for a post-demonstration brownfield plant to be constructed in Japan in the 2020s. The study assesses transportation and storage technologies, and site-specific characteristics for transportation by ship and pipeline (PL). With CCS, the construction cost for transportation is the highest (40–60%), closely followed by separation and recovery costs. CCS raises the cost of electricity (COE), of which 30–60% is due to CO2 transportation. The costs of CO2 avoided and CO2 captured show a trend similar to the construction cost. Ship transport is more promising given the flexibility in CO2 storage sites along Japan's coastline and the high unit cost of PL transportation. The overnight cost and levelized COE of the IGCC+CCS plant in the FS (FOAK plant) are relatively higher than those for the plants evaluated in other studies (commercial plants).

Gas Turbine Combustion Technology Reducing Both Fuel-NOx and Thermal-NOx Emissions for Oxygen-Blown IGCC With Hot/Dry Synthetic Gas Cleanup

Abstract In order to improve the thermal efficiency of the oxygen-blown integrated gasification combined cycle (IGCC) and to meet stricter environmental restrictions among cost-effective options, a hot/dry synthetic gas cleanup is one of the most hopeful choices. The flame temperature of medium-Btu gasified fuel used in this system is high so that NOx formation by nitrogen fixation results to increase significantly. Additionally, the gasified fuel contains nitrogenous compound, as ammonia, and it produces nitrogen oxides, the fuel NOx, in the case of employing the hot/dry gas cleanup. Low NOx combustion technology to reduce both fuel-NOx and thermal-NOx emissions has been required to protect the environment and ensure low cost operations for all kinds of oxygen-blown IGCC. In this paper, we have demonstrated the effectiveness of two-stage combustion and nitrogen injection techniques, and also showed engineering guidelines for the low-NOx combustor design of oxygen-blown gasified, medium-Btu fuels. The main results obtained are as follows: (1) Based on the basic combustion tests using a small diffusion burner, we clarified that the equivalence ratio at the primary combustion zone has to be adjusted according to the fuel conditions, such as methane concentration, CO∕H2 molar ratio, and calorific values of gasified fuels in the case of the two-stage combustion method for reducing fuel-NOx emissions. (2) From the combustion tests of the medium-Btu fueled combustor, two-stage combustion with nitrogen direct injection into the combustor results in reductions of NOx emissions to 34ppm (corrected at 16% O2) or less under the gas turbine operational conditions of 25% load or higher for IGCC in the case where the gasified fuel contains 0.1% methane and 500ppm of ammonia. Through nitrogen direct injection, the thermal efficiency of the plant improved by approximately 0.3% (absolute), compared with the case where nitrogen was premixed with gasified fuel. The CO emission concentration decreased drastically, as low as 20ppm, or combustion efficiency was kept higher than 99.9%. The above results have shown that a two-stage combustion method with nitrogen direct injection is very effective for reducing both fuel-NOx and thermal-NOx emissions at once in IGCC, and it shows the bright prospects for low NOx and stable combustion technology of medium-Btu fuel.

Medium-Btu Fueled Gas Turbine Combustor for Use in IGCC (3rd Report, Combustion Technology for Reducing both Fuel-NOx and Thermal-NOx Emissions)

In order to improve the thermal efficiency of the oxygen-blown IGCC (Integrated Gasification Combined Cycle) and to meet stricter environmental restrictions among cost-effective options, a hot/dry synthetic gas cleanup is one of the most prospective choices. The flame temperature of medium-Btu gasified fuel used in this system is relatively high, so that NOx formation by nitrogen fixation increases significantly. Additionally, the gasified fuel contains fuel nitrogen in the form of ammonia mostly and it produces nitrogen oxides, the fuel-NOx in the case of employing the hot/dry synthetic gas cleanup. Low NOx combustion technology to reduce both fuel-NOx and thermal-NOx emissions has been required to protect the environment and ensure low cost operations for all kinds of oxygen-blown IGCC. In this paper, we have demonstrated effectiveness of two-stage combustion and nitrogen injection technique, and also showed useful engineering guidelines for the low-NOx combustor design of oxygen-blown gasified, medium-Btu fuels.

00/00464 Low-grade coal improves the burnability of cement raw meal

This project emphasizes CO2-capture technologies combined with integrated gasification combined-cycle (IGCC) power systems, CO2 transportation, and options for the long-term sequestration of CO2. The intent is to quantify the CO2 budget, or an “equivalent CO2” budget, associated with each of the individual energy-cycle steps, in addition to process design capital and operating costs. The base case is a 458-MW (gross generation) IGCC system that uses an oxygen-blown Kellogg-Rust-Westinghouse (KRW) agglomerating fluidized-bed gasifier, bituminous coal feed, and low-pressure glycol sulfur removal, followed by Claus/SCOT treatment, to produce a saleable product. Mining, feed preparation, and conversion result in a net electric power production for the entire energy cycle of 411 MW, with a CO2 release rate of 0.801 kg/kWhe. For comparison, in two cases, the gasifier output was taken through water-gas shift and then to low-pressure glycol H2S recovery, followed by either low-pressure glycol or membrane CO2 recovery and then by a combustion turbine being fed a high-hydrogen-content fuel. Two additional cases employed chilled methanol for H2S recovery and a fuel cell as the topping cycle, with no shift stages. From the IGCC plant, a 500-km pipeline takes the CO2 to geological sequestering. For the optimal CO2 recovery case, the net electric power production was reduced by 37.6 MW from the base case, with a CO2 release rate of 0.277 kg/kWhe (when makeup power was considered). In a comparison of air-blown and oxygen-blown CO2-release base cases, the cost of electricity for the air-blown IGCC was 56.86 mills/kWh, while the cost for oxygen-blown IGCC was 58.29 mills/kWh. For the optimal cases employing glycol CO2 recovery, there was no clear advantage; the cost for air-blown IGCC was 95.48 mills/kWh, and the cost for the oxygen-blown IGCC was slightly lower, at 94.55 mills/kWh.

99/01990 Temperature measuring device inside coal gasifier: Yoshida, K. et al. Jpn. Kokai Tokkyo Koho JP 10 237,466 [98 237,466], (Cl. C10J3/48), 8 Sep 1998, Appl. 97/45,504, 28 Feb 1997, 6 pp. (In Japanese)

This project emphasizes CO2-capture technologies combined with integrated gasification combined-cycle (IGCC) power systems, CO2 transportation, and options for the long-term sequestration of CO2. The intent is to quantify the CO2 budget, or an “equivalent CO2” budget, associated with each of the individual energy-cycle steps, in addition to process design capital and operating costs. The base case is a 458-MW (gross generation) IGCC system that uses an oxygen-blown Kellogg-Rust-Westinghouse (KRW) agglomerating fluidized-bed gasifier, bituminous coal feed, and low-pressure glycol sulfur removal, followed by Claus/SCOT treatment, to produce a saleable product. Mining, feed preparation, and conversion result in a net electric power production for the entire energy cycle of 411 MW, with a CO2 release rate of 0.801 kg/kWhe. For comparison, in two cases, the gasifier output was taken through water-gas shift and then to low-pressure glycol H2S recovery, followed by either low-pressure glycol or membrane CO2 recovery and then by a combustion turbine being fed a high-hydrogen-content fuel. Two additional cases employed chilled methanol for H2S recovery and a fuel cell as the topping cycle, with no shift stages. From the IGCC plant, a 500-km pipeline takes the CO2 to geological sequestering. For the optimal CO2 recovery case, the net electric power production was reduced by 37.6 MW from the base case, with a CO2 release rate of 0.277 kg/kWhe (when makeup power was considered). In a comparison of air-blown and oxygen-blown CO2-release base cases, the cost of electricity for the air-blown IGCC was 56.86 mills/kWh, while the cost for oxygen-blown IGCC was 58.29 mills/kWh. For the optimal cases employing glycol CO2 recovery, there was no clear advantage; the cost for air-blown IGCC was 95.48 mills/kWh, and the cost for the oxygen-blown IGCC was slightly lower, at 94.55 mills/kWh.

99/01178 Oxidative conversion of hydrocarbons into synthesis gas and unsaturated hydrocarbons assisted by gliding electric arcs : Czernichowski, P. and Czernichowski, A. PCT Int. Appl. WO 98 30,524 (Cl. C07CS/32), 16 Jul 1998, FR Appl. 97/364, 13 Jan 1997, 31 pp.

Syngas processing often requires separation of CO2 and hydrogen for hydrogen production, and the resulting CO2-enriched stream presents an opportunity for simultaneous CO2 capture. For example, syngas-based integrated gasification combined cycle (IGCC) power plants are envisioned as an efficient means of producing power from coal where CO2 capture technologies can be applied relatively easily. Membrane technology is an attractive approach for CO2 capture because of inherent process advantages such as simplicity, reliability, compactness and modularity. This paper (Part II of a two-part study) performs techno-economic analysis for CO2-selective membranes in three hydrogen production or utilization applications: methane reformer/pressure swing adsorption processes, oxygen-blown coal-fired IGCC power plants using GE gasification technology, and air-blown coal-fired IGCC power plants using Transport Integrated Gasification (TRIG) technology. These processes require membranes with CO2/H2 selectivities of 10–20, which can be provided using PolarisTM membranes. Hybrid approaches using a combination of membrane and cryogenic processes are evaluated for the production of high-pressure liquid CO2 ready for utilization or sequestration. The optimal membrane CO2/H2 selectivity and influence of CO2 capture rate on the cost of CO2 capture are determined, providing general guidelines for future membrane development. The cost of CO2 capture with these membrane processes depends not only on the feed CO2 partial pressure, but on the feed CO2 concentration as well.

Oxygen-blown gasification combined cycle: Carbon dioxide recovery, transport, and disposal

This project emphasizes CO2-capture technologies combined with integrated gasification combined-cycle (IGCC) power systems, CO2 transportation, and options for the long-term sequestration of CO2. The intent is to quantify the CO2 budget, or an “equivalent CO2” budget, associated with each of the individual energy-cycle steps, in addition to process design capital and operating costs. The base case is a 458-MW (gross generation) IGCC system that uses an oxygen-blown Kellogg-Rust-Westinghouse (KRW) agglomerating fluidized-bed gasifier, bituminous coal feed, and low-pressure glycol sulfur removal, followed by Claus/SCOT treatment, to produce a saleable product. Mining, feed preparation, and conversion result in a net electric power production for the entire energy cycle of 411 MW, with a CO2 release rate of 0.801 kg/kWhe. For comparison, in two cases, the gasifier output was taken through water-gas shift and then to low-pressure glycol H2S recovery, followed by either low-pressure glycol or membrane CO2 recovery and then by a combustion turbine being fed a high-hydrogen-content fuel. Two additional cases employed chilled methanol for H2S recovery and a fuel cell as the topping cycle, with no shift stages. From the IGCC plant, a 500-km pipeline takes the CO2 to geological sequestering. For the optimal CO2 recovery case, the net electric power production was reduced by 37.6 MW from the base case, with a CO2 release rate of 0.277 kg/kWhe (when makeup power was considered). In a comparison of air-blown and oxygen-blown CO2-release base cases, the cost of electricity for the air-blown IGCC was 56.86 mills/kWh, while the cost for oxygen-blown IGCC was 58.29 mills/kWh. For the optimal cases employing glycol CO2 recovery, there was no clear advantage; the cost for air-blown IGCC was 95.48 mills/kWh, and the cost for the oxygen-blown IGCC was slightly lower, at 94.55 mills/kWh.