Turbine Combustion Technology Research Articles

Assessment of MDEA absorption process for sequential H2S removal and CO2 capture in air-blown IGCC plants

This work deals with pre-combustion CO2 capture by Methyldiethanolamine (MDEA) scrubbing in air-blown integrated gasification combined cycles (IGCCs). Two types of coal, with low- and high-sulphur content, are considered as fuel input in power plants, as well as two combustion turbines, with different turbine inlet temperature, representative of state-of-the-art and advanced technologies.The gasification section and the power island are simulated by means of the proprietary code GS. Acid gas removal (AGR), consisting in the sequential H2S removal and CO2 capture from the syngas by MDEA solvent, is calculated with Aspen Plus®. MDEA concentration and solvent circulation are varied in each of the assessed cases to comply with the target CO2 capture efficiency and with the CO2 and H2S purity specifications. The resulting heat duties for H2S and CO2 stripping, the consumption of the auxiliaries in the AGR plants, as well as the CO2 compression work are used to calculate the energy and mass balances of the integrated gasification combined cycles. Sensitivity analysis on the temperature approach in the recuperative heat exchanger of the CO2 capture section and on the pressure of the CO2 stripping column have been performed to assess potential energy savings. Results are compared with benchmark IGCC plants without CO2 capture.Net electric efficiencies between 36.6% and 40.4%, with 95% of CO2 capture efficiency, are achieved depending on the coal quality (i.e. the sulphur content), the combustion turbine technology and the MDEA regeneration pressure and heat exchanger temperature difference. Correspondingly, a specific primary energy consumption for CO2 avoided (SPECCA) between 2.85 and 3.2MJ/kgCO2 for the low-sulphur coal cases and between 3.2 and 3.7MJ/kgCO2 for the high-sulphur coal cases have been calculated.

Life-cycle comparison of greenhouse gas emissions and water consumption for coal and shale gas fired power generation in China

China has the world's largest shale gas reserves, which might enable it to pursue a new pathway for electricity generation. This study employed hybrid LCI (life cycle inventory) models to quantify the ETW (extraction-to-wire) GHG (greenhouse gas) emissions and water consumption per kWh of coal- and shale gas-fired electricity in China. Results suggest that a coal-to-shale gas shift and upgrading coal-fired power generation technologies could provide pathways to less GHG and water intensive power in China. Compared to different coal-fired generation technologies, the ETW GHG emissions intensity of gas-fired CC (combined cycle) technology is 530 g CO2e/kWh, which is 38–45% less than China's present coal-fired electricity. Gas-fired CT (combustion turbine) technology has the lowest ETW water consumption intensity at 960 g/kWh, which is 34–60% lower than China's present coal-fired electricity. The GHG-water tradeoff of the two gas-fired power generation technologies suggests that gas-fired power generation technologies should be selected based on regional-specific water resource availabilities and electricity demand fluctuations in China. However, the low price of coal-fired electricity, high cost of shale gas production, insufficient pipeline infrastructures, and multiple consumers of shale gas resources may serve as barriers to a coal-to-shale gas shift in China's power sector in the near term.

Stand Tall and Speak Up: Natural Gas - Image vs. Reality

We often lump oil and natural gas together, but in many ways they are very different products, which are used in different applications. While those of us in the petroleum industry view natural gas as an excellent, environmentally friendly energy alternative, our potential customers do not necessarily share that perspective. In some markets, natural gas has a bad image. From our perspective, natural gas is the most environmentally friendly fossil fuel and as such an excellent source of energy for electric power generation. Combustion of natural gas emits almost 30% less carbon dioxide than oil and about 45% less carbon dioxide than coal; virtually no sulfur dioxide; and up to 80% fewer nitrogen oxides than coal. Emissions of particulates from natural gas combustion are negligible. With all these advantages, we believe that customers should have a strong preference for natural gas. Nevertheless, electric utilities often see natural gas as an interim fix, with the long-term solution being clean coal technology. Many countries still depend on coal for power generation even though combustion of coal emits larger amounts of pollutants than alternatives. In the U.S., coal is used to generate 51% of the nation's electrical power. Natural gas is a distant third at about 17%, behind nuclear power with a 21% market share. Some other nations are even more dependent on coal-fired electrical generation. Poland is 97% coal dependent, while India is 78%, China 76%, and Australia 70%. Electrical generation facilities using efficient, natural gas-fired combustion turbine technology can be completed in far less time and with far less capital than other technologies. However, even as utilities are building gas-fired plants, they are looking to clean coal technologies as the preferred next-generation solution. This is reflected in the U.S. Energy Information Administration's Annual Energy Outlook 2005, which predicts that in the long term most new electric power plants will use clean coal technology rather than natural gas (Fig. 1). In a modern natural-gas-fired power plant, fuel accounts for almost 90% of the operating costs. In the last couple of years, U.S. natural gas prices have more than tripled (Fig. 2), reinforcing utilities' concerns about price volatility. When we look at natural gas, we see opportunities in the high prices and regional scarcity. With rising natural gas prices in North America and increasing demand in China, LNG projects have become some of the hottest games in town. Everyone is competing to sell LNG and build LNG terminals. Unfortunately, like so many other aspects of the oil industry, what is viewed as good for us is viewed as bad by the general public and our customers.

Ideas Generated for Transforming the Electric Infrastructure

Gellings and Yeager reply: We thank Wallace Brand and Richard Factor for providing additional insights about the electric infrastructure. A few points deserve clarification.Several electric ventures did, indeed, open in the US and the UK in the late 1870s and early 1880s before Thomas Edison’s Pearl Street Station. However, we highlighted Edison since his was the first true utility “system” of substantial size, serving multiple functions and users.The efficiency of the transmission system has increased over the years, largely through the use of higher-voltage AC transmission lines and, in a few selected situations, high-voltage DC transmission. Little has changed in transmission technology, though, except for a few applications of power electronics, and growth in demand continues to exceed the rate of capacity expansion.The cost of electricity steadily declined in real terms from the birth of the industry to about 1970. Most of that cost reduction came from increases in power-plant size and efficiency—a trend that has slowed over the past 30 years and has been more than offset by fuel cost increases and the cost of retrofitting coal-fired power plants with environmental controls such as selective catalytic reduction and flue gas scrubbers.The average fuel efficiency of central-station power does continue to increase, albeit slowly. The increase is mostly due to the recent addition of new plants, based on combustion turbine technology, that are only slightly more efficient than the average fleet of existing plants. Regrettably, the recent run-up in natural gas prices has rendered many of these plants uncompetitive. And so far, the costs of small generation devices such as fuel cells remain marginally competitive at best, despite their potential efficiency advantages, and they should be considered a complement to, not a replacement for, central-station generation.The solution to our electric energy needs may include fuel cells—but realistically it will also require increasing the utilization efficiency of electricity and use of advanced nuclear reactors, cleaner combined-cycle coal combustion, and renewable energy resources.Adapting hybrid vehicles to become plug-in hybrid vehicles is an exciting potential way to reduce overall energy needs even further, reduce emissions, and provide the lowest vehicle life-cycle costs to consumers. Several such vehicle configurations are being demonstrated in the US and Europe. Today’s power system remains the most complex machine ever invented by humankind. Adapting it to meet tomorrow’s needs will require a portfolio of solutions and renewed investment. No matter how well-intended, efforts to promote individual solutions outside the context of a robust portfolio only distract and delay the essential comprehensive effort.© 2005 American Institute of Physics.

Final Report on the Development of a Hydrogen-Fueled Combustion Turbine Cycle for Power Generation

Through its New Energy and Industrial Technology Development Organization (NEDO) the Japanese government is sponsoring the World Energy Network (WE-NET) Program. WE-NET is a 28-year global effort to define and implement technologies needed for hydrogen-based energy systems. A critical part of this effort is the development of a hydrogen-fueled combustion turbine system to efficiently convert the chemical energy stored in hydrogen to electricity when hydrogen is combusted with pure oxygen. A Rankine cycle, with reheat and recuperation, was selected by Westinghouse as the general reference system. Variations of this cycle have been examined to identify a reference system having maximum development feasibility, while meeting the requirement of a minimum of 70.9 percent low heating value (LHV) efficiency. The strategy applied by Westinghouse was to assess both a near-term and long-term Reference Plant. The near-term plant requires moderate development based on extrapolation of current steam and combustion turbine technology. In contrast, the long-term plant requires more extensive development for an additional high pressure reheat turbine, and is more complex than the near-term plant with closed-loop steam cooling and extractive feedwater heating. Trade-offs between efficiency benefits and development challenges of the near-term and long-term reference plant are identified. Results of this study can be applied to guide the future development activities of hydrogen-fueled combustion turbine systems.

Low-emission gas turbines using catalytic combustion

Gas turbines are being increasingly used for electric power generation and other applications. Gas turbines are efficient and clean-burning, but without emission controls they emit far more nitrogen oxides (NO x ) than regulations permit. Commercial NO x control techniques, such as dry low NO x (DLN), wet diluent injection (WDI), and selective catalytic reduction (SCR), are generally uneconomical for achieving NO x emissions of 10 ppm or less, which are, or will soon be, required in many industrialized regions of the world. In the thermal combustion of natural gas (methane), NO x emissions are very low up to about 1400°C, but increase sharply to more than 160 ppm at the typical flame temperature of about 1800°C. In catalytic combustion, which occurs at 1300–1400°C, NO x emissions can be as low as 2–5 ppm, which are one to two orders of magnitude less than the emissions from thermal combustion and are in compliance with current and foreseeable regulatory standards worldwide. Catalytic combustion turbine technology is at the field demonstration stage of development and is expected to be commercialized by the late 1990s. Catalytic combustion systems can be built in to new gas turbines and retrofitted to some existing turbines. Catalytic combustion turbines will initially be used primarily for electric power generation, including cogeneration and combined-cycle power generation. Subsequent major applications might also include aircraft, rail locomotives, motor vehicles, ships, and gas pipeline compressors.

Gas-Turbine Electric Locomotives

Gas turbines are being increasingly used for electric power generation and other applications. Gas turbines are efficient and clean-burning, but without emission controls they emit far more nitrogen oxides (NOx) than regulations permit. Commercial NOx control techniques, such as dry low NOx (DLN), wet diluent injection (WDI), and selective catalytic reduction (SCR), are generally uneconomical for achieving NOx emissions of 10 ppm or less, which are, or will soon be, required in many industrialized regions of the world. In the thermal combustion of natural gas (methane), NOx emissions are very low up to about 1400°C, but increase sharply to more than 160 ppm at the typical flame temperature of about 1800°C. In catalytic combustion, which occurs at 1300–1400°C, NOx emissions can be as low as 2–5 ppm, which are one to two orders of magnitude less than the emissions from thermal combustion and are in compliance with current and foreseeable regulatory standards worldwide. Catalytic combustion turbine technology is at the field demonstration stage of development and is expected to be commercialized by the late 1990s. Catalytic combustion systems can be built in to new gas turbines and retrofitted to some existing turbines. Catalytic combustion turbines will initially be used primarily for electric power generation, including cogeneration and combined-cycle power generation. Subsequent major applications might also include aircraft, rail locomotives, motor vehicles, ships, and gas pipeline compressors.