Search Results for CO2 capture

UltraGen is an initiative proposed by EPRI to accelerate the deployment and commercialization of clean, efficient, ultra-supercritical pulverized coal (USC PC) power plants that are capable of meeting any future CO 2 emissions regulations while still generating competitively-priced electricity. In addition to reducing CO 2 , these advanced systems will have to achieve near-zero emissions of criteria pollutants (SO 2 , NO X , and filterable and condensable particulate) and hazardous air pollutants such as mercury.

A recent engineering design study conducted by the Electric Power Research Institute (EPRI) has compared the cost and performance of an advanced ultra-supercritical (A-USC) pulverized coal (PC) power plant with main steam temperature of 700°C to that of conventional coal-fired power plant designs: sub-critical, supercritical, and current USC PC plants with main steam temperatures of 541°, 582°, and 605°C, respectively. The study revealed that for a US location in the absence of any cost being imposed for CO 2 emissions the A-USC design was a slightly more expensive choice for electricity production. However, when the marginal cost of the A-USC design is compared to the reduction in CO 2 emissions, it was shown that the cost of the avoided CO 2 emissions was less than $25 per metric ton of CO 2 . This is significantly lower than any technology currently being considered for CO 2 capture and storage (CCS). Additionally by lowering CO 2 /MWh, the A-USC plant also lowers the cost of CCS once integrated with the power plant. It is therefore concluded that A-USC technology should be considered as one of the primary options for minimizing the cost of reducing CO 2 emissions from future coal power plants.

As the demand for worldwide electricity generation grows, pulverized coal steam generator technology is expected to be a key element in meeting the needs of the utility power generation market. The reduction of greenhouse gas emissions, especially CO 2 emissions, is vital to the continued success of coal-fired power generation in a marketplace that is expected to demand near-zero emissions in the near future. Oxycombustion is a technology option that uses pure oxygen, and recycled flue gas, to fire the coal. As a result, this system eliminates the introduction of nitrogen, which enters the combustion process in the air, and produces a highly-concentrated stream of CO 2 that can readily be captured and sequestered at a lower cost than competing post-combustion capture technologies. Oxycombustion can be applied to a variety of coal-fired technologies, including supercritical and ultra-supercritical pulverized coal boilers. The incorporation of oxycombustion technology in these systems raises some new technical challenges, especially in the area of advanced boiler materials. Local microclimates generated near and at the metal interface will influence and ultimately govern corrosion. In addition, the fireside corrosion rates of the boiler tube materials may be increased under high concentration oxygen firing, due to hotter burning coal particles and higher concentrations of SO 2 , H 2 S, HCl and ash alkali, etc. There is also potential to experience new fouling characteristics in the superheater and heat recovery sections of the steam generator. The continuous recirculation of the flue gases in the boiler, may lead to increasing concentrations of deleterious elements such as sulfur, chlorine, and moisture. This paper identifies the materials considerations of oxycombustion supercritical and ultrasupercritical pulverized coal plants that must be addressed for an oxycombustion power plant design.

Increasing the steam temperature of a coal-fired pulverized coal (PC) power plant increases its efficiency, which decreases the amount of coal required per MW of electrical output and therefore decreases the emissions from the plant, including CO 2 . However, increasing the steam temperature requires that the materials for the boiler pressure parts and steam turbine be upgraded to high-nickel alloys that are more expensive than alloys typically used in existing PC units. This paper explores the economics of A-USC units operating between 595°C and 760°C (1100°F to 1400°F) with no CO 2 removal and with partial capture of CO 2 at an emission limit of 454 kg CO 2 /MW-hr (1000 lb CO 2 /MW-hr) on a gross power basis. The goal of the paper is to understand if the improved efficiency of A-USC would reduce the cost of electricity compared to conventional ultra-supercritical units, and estimate the economically “optimal” steam temperature with and without CO 2 removal.

With nearly half of the world's electricity generation fueled by coal and an increasing focus on limiting carbon dioxide emissions, several technologies are being evaluated and developed to capture and prevent such emissions while continuing to use this primary fossil energy resource. One method aimed at facilitating the capture and processing of the resulting carbon dioxide product is oxy-combustion. With appropriate adjustments to the process, the approach is applicable to both new and existing power plants. In oxy-combustion, rather than introducing ambient air to the system for burning the fuel, oxygen is separated from the nitrogen and used alone. Without the nitrogen from the air to dilute the flue gas, the flue gas volume leaving the system is significantly reduced and consists primarily of carbon dioxide and water vapor. Once the water vapor is reduced by condensation, the purification and compression processes otherwise required for carbon dioxide transport and sequestration are significantly reduced. As an introduction to and overview of this technology, the paper summarizes the basic concepts and system variations, for both new boiler and retrofit applications, and also serves as an organized review of subsystem issues identified in recent literature and publications. Topics such as the air separation units, flue gas recirculation, burners and combustion, furnace performance, emissions, air infiltration issues, and materials issues are introduced.

Oxyfuel combustion efforts to burn fossil fuels with oxygen, for easier post-combustion CO 2 capture, include schemes to use flue gas to drive turbines for power generation. The environment examined here is 10% CO 2 and 0.2% O 2 , with the balance being steam, with temperatures ranging from 630 to 821 °C. The relatively high C and O 2 activities of this environment, as compared to pure steam, may lead to changes in oxidation behavior and mechanical properties. Oxidation coupons of Ni- and Co-base superalloys, in both bare metal and TBC coated conditions, were exposed to this environment for up to 1000 hours. The results of these exposures, in terms of mass gain and scale morphology, are presented.

Oxyfuel combustion is considered as one of the most promising technologies to facilitate CO 2 capture from flue gases. In oxyfuel combustion, the fuel is burned in a mixture of oxygen and recirculated flue gas. Flue gas recirculation increases the levels of fireside CO 2 , SO 2 , Cl and moisture, and thus promotes fouling and corrosion. In this paper the corrosion performance of two superheater austenitic stainless steels (UNS S34710 and S31035) and one Ni base alloy (UNS N06617) has been determined in laboratory tests under simulated oxyfuel conditions with and without a synthetic carbonate based deposits (CaCO 3 - 15 wt% CaSO 4 , CaCO 3 - 14wt% CaSO 4 - 1 KCl) at 650 and 720°C up to 1000 hours. No carburization of the metal substrate was observed after exposure to simulated oxyfuel gas atmospheres without deposit, although some carbon enrichment was detected near the oxide metal interface. At 720°C a very thin oxide formed on all alloy surfaces while the weight changes were negative. This negative weight change observed is due to chromium evaporation in the moist testing condition. At the presence of deposits, corrosion accelerated and considerable metal loss of austenitic alloys was observed at 720°C. In addition, clear carburization of austenitic steel UNS S34710 occurred.

The development of oxy-fuel combustion technology for coal-based power generation may produce combustion products different from those typically found in traditional boilers. In particular, the enrichment of CO 2 and perhaps SO3 could alter the chemical equilibrium to favor the formation of certain carbonates and sulfates in the deposit. Higher concentrations of these gases would also increase the potential for condensation of carbonic and sulfuric acids in lower-temperature areas of the boiler. To address these concerns, B&W has instituted a comprehensive research program to better understand the effect of oxy-coal combustion on fireside corrosion. The scope of this program includes gas and deposit analyses of actual combustion products sampled from B&W's Clean Environment Development Facility (CEDF) during the oxy-coal combustion of three commercial coals. The sampling locations consist of regions representing the lower furnace, superheater bank, and pulverizer outlet. Following the gas and deposit analyses, a series of laboratory corrosion tests will be performed to expose candidate alloys and coatings to conditions simulating the oxy-coal combustion environments. The technical approaches and results of the fireside corrosion program obtained to date are discussed.

The EU NextGenPower-project aims at demonstrating Ni-alloys and coatings for application in high-efficiency power plants. Fireside corrosion lab and plants trials show that A263 and A617 perform similar while A740H outperforms them. Lab tests showed promising results for NiCr, Diamalloy3006 and SHS9172 coatings. Probe trials in six plants are ongoing. A617, A740H and A263 performed equally in steamside oxidation lab test ≤750°C while A617 and A740H outperformed A263 at 800°C; high pressure tests are planned. Slow strain rate testing confirmed relaxation cracking of A263. A creep-fatigue interaction test program for A263 includes LCF tests. Negative creep of A263 is researched with gleeble tests. A263 Ø80 - 500mm trial rotors are forged with optimized composition. Studies for designing and optimizing the forging process were done. Segregation free Ø300 and 1,000mm rotors have been forged. A263 – A263 and A293 – COST F rotor welding show promising results (A263 in precipitation hardened condition). Cast step blocks of A282, A263 and A740H showed volumetric cracking after heat treatment. New ‘as cast’ blocks of optimized composition are without cracks. A 750°C steam cycle has been designed with integrated CO 2 capture at 45% efficiency (LHV). Superheater life at ≤750°C and co-firing is modeled.

This paper examines the ongoing significance of pulverized coal-fired steam plants in global power generation, focusing on technological advancements and strategies for improving efficiency and reducing CO 2 emissions. It traces the development of Ultra-Supercritical (USC) plants with steam temperatures around 600°C and explores immediate opportunities for further efficiency enhancements, including the innovative Master Cycle. The potential for increasing steam temperatures to 650°C using new steels and to 700°C with nickel-based AD 700 technology is discussed. The paper outlines a comprehensive strategy for CO 2 emission reduction: maximizing plant efficiency, co-firing with CO 2 -neutral fuels, and integrating with district heating/cooling or industrial heat consumers. Carbon capture and storage techniques are presented as a final step in this multi-faceted approach to sustainable power generation.

Following the successful completion of a 14-year effort to develop and test materials which would allow advanced ultra-supercritical (A-USC) coal-fired power plants to be operated at steam temperatures up to 760°C, a United States-based consortium has started on a project to build an A-USC component test facility, (A-USC ComTest). Among the goals of the facility are to validate that components made from the advanced alloys can perform under A-USC conditions, to accelerate the development of a U.S.-based supply chain for the full complement of A-USC components, and to decrease the uncertainty for cost estimates of future commercial-scale A-USC power plants. The A-USC ComTest facility will include a gas fired superheater, thick-walled cycling header, steam piping, steam turbine (11 MW nominal size) and valves. Current plans call for the components to be subjected to A-USC operating conditions for at least 8,000 hours by September 2020. The U.S. consortium, principally funded by the U.S. Department of Energy and the Ohio Coal Development Office with co-funding from Babcock & Wilcox, General Electric and the Electric Power Research Institute, is currently working on the Front-End Engineering Design phase of the A-USC ComTest project. This paper will outline the motivation for the project, explain the project’s structure and schedule, and provide details on the design of the facility.

While the water vapor content of the combustion gas in natural gas-fired land based turbines is ~10%, it can be 20-85% with coal-derived (syngas or H 2 ) fuels or innovative turbine concepts for more efficient carbon capture. Additional concepts envisage working fluids with high CO 2 contents to facilitate carbon capture and sequestration. To investigate the effects of changes in the gas composition on thermal barrier coating (TBC) lifetime, furnace cycling tests (1h cycles) were performed in air with 10, 50 and 90 vol.% water vapor and in CO 2 -10%H 2 O and compared to prior results in dry air or O 2 . Two types of TBCs were investigated: (1) diffusion bond coatings (Pt diffusion or simple or Pt-modified aluminide) with commercially vapor-deposited yttria-stabilized zirconia (YSZ) top coatings on second-generation superalloy N5 and N515 substrates and (2) high velocity oxygen fuel (HVOF) sprayed MCrAlYHfSi bond coatings with air-plasma sprayed YSZ top coatings on superalloy X4 or 1483 substrates. In both cases, a 20-50% decrease in coating lifetime was observed with the addition of water vapor for all but the Pt diffusion coatings which were unaffected by the environment. However, the higher water vapor contents in air did not further decrease the coating lifetime. Initial results for similar diffusion bond coatings in CO 2 -10%H 2 O do not show a significant decrease in lifetime due to the addition of CO 2 . Characterization of the failed coating microstructures showed only minor effects of water vapor and CO 2 additions that do not appear to account for the observed changes in lifetime. The current 50°-100°C de-rating of syngas-fired turbines is unlikely to be related to the presence of higher water vapor in the exhaust.

The high-temperature oxidation of Fe-9Cr-1Mo steel in a CO 2 environment, with varying oxygen content (0.6-3%), was investigated at 700°C. While the steel heavily oxidized in pure CO 2 , the oxidation mass gain decreased significantly with increasing oxygen content. Microscopic analysis revealed the formation of Fe-rich nodules with an internal Cr-carbide layer beneath them. Notably, the number of nodules decreased with increasing oxygen content but remained independent of the oxidation time. To explain these observations, the authors propose that “intrinsic” defects within the initially formed protective Cr 2 O 3 scale facilitated gas permeation. This mechanism is believed to be responsible for the observed dependence of nodule formation on the oxygen content in the gas mixtures.

Supercritical CO 2 (sCO 2 ) is of interest as a working fluid for several concepts including the direct- fired Allam cycle as a low-emission fossil energy power cycle. Over the past 10 years, laboratory exposures at 300 bar sCO 2 have found reasonably good compatibility for Ni-based alloys at <800°C, including an assessment of the sCO 2 impact on room temperature mechanical properties after 750°C exposures. However, initial screening tests at 1 and 20 bar CO 2 at 900°-1100°C showed poor compatibility for Ni-based alloys. In an open cycle, the introduction of 1%O 2 and 0.1- 0.25%H 2 O impurities at 300 bar increased the reaction rates ≥2X at 750°C. At lower temperatures, steels are susceptible to C ingress and embrittlement. Creep-strength enhanced ferritic steels may be limited to <550°C and conventional stainless steels to <600°C. Two strategies to increase those temperatures are higher Ni and Cr alloying additions and Al- or Cr-rich coatings. Alloy 709 (Fe- 20Cr-25Ni) shows some promising results at 650°C in sCO 2 but reaction rates were accelerated with the addition of O 2 and H 2 O impurities. Pack aluminized and chromized Gr.91 (Fe-9Cr-1Mo) and type 316H stainless steel show some promise at 600°-650°C but further coating optimization is needed.

High-temperature solid particle erosion (SPE) is a major threat to efficiency in power plants and jet engines, potentially reducing turbine efficiency by 7-10% and causing significant CO 2 emissions. The sources of these particles vary widely, from volcanic ash in engines to fly ash in boilers and scale in turbines. While better surface engineering and coatings offer solutions, their development is hampered by a lack of standardized test methods and reliable models. To address this, the METROSION initiative aims to establish a comprehensive framework for characterizing the high-temperature SPE performance of new materials and coatings. This framework will require a step change in test methods and control, focusing on accurately measuring key parameters like temperature, flow rate, particle properties, and impact angles. This paper outlines the initiative’s goals, with a particular focus on the techniques used for in-situ measurements of temperature, particle velocity, and 3D shape/size.

In Europe and Japan, great efforts are currently being invested in the development of materials designed to increase the steam temperature in fossil power plants. In the steel segment, the COST program is concentrating on 10% Cr steels with the addition of boron with the aim of achieving a steam temperature of 650°C. With nickel-based materials, the goal is to achieve steam temperatures of 700°C and higher. Alloy 617 has proved to be a very promising candidate in this field and a modified version is currently being developed in Japan. Materials of this type are used in both the turbine and in parts of the boiler.

Using oxygen, rather than air, in coal-fired boilers has been studied for several years as a strategy to reduce NOx and concentrate CO 2 for capture. In combination with flue gas recirculation, higher levels of CO 2 are expected but increased H 2 O and SO 2 levels also may occur. In order to understand the role of substrate composition on corrosion, a combination of commercial and model alloys were investigated with synthetic coal ash and gas compositions simulating air- and oxyfiring environments. Exposure temperatures ranged from 600°-800°C to cover current operating temperatures up to advanced ultrasupercritical conditions. Using 500h exposures, no consistent negative effect was found for switching to the oxy-firing environment with the same synthetic ash. For model Fe-Cr alloys, 30%Cr was needed to form a thin protective reaction product across this temperature range. Among the commercial stainless steels, 310-type stainless steel showed low reaction rates with the maximum attack at 650°C. At higher temperatures, the depth of attack on Fe-base type 310 stainless steel was less than for Ni-base alloy 740. Initially, this difference was attributed to the Al and Ti additions in alloy 740. However, cast and hot rolled model Ni-18Cr and -22Cr alloys with various Al and Ti additions showed decreased metal loss with increasing Al and Ti additions in the oxy-firing environment at 700° and 800°C. As expected, metal loss was very sensitive to Cr content. A second set of model alloys also examined the effect of Co and Mo.

Long-term performance of high temperature alloys is critically linked to the oxidation behavior in power generation applications in wet air and steam. As power generation systems move towards higher efficiency operation, nextgeneration fossil, nuclear and concentrating solar power plants are considering supercritical CO 2 cycle above 700°C. Wrought solid solution strengthened and precipitations strengthened alloys are leading candidates for both steam and Supercritical CO 2 power cycles. This study evaluates the cyclic oxidation behavior of HAYNES 230, 282, and 625 alloys in wet air, flowing laboratory air, steam and in 1 and 300 bar Supercritical CO 2 at ~750°C for duration of 1000 -10,000h. Test samples were thermally cycled for various times at temperature followed by cooling to room temperature. Alloy performances were assessed by analyzing the weight change behavior and extent of attack. The results clearly demonstrated the effects of alloy composition and environment on the long-term cyclic oxidation resistance. The extents of attack varied from alloy to alloy but none of the alloys underwent catastrophic corrosion and no significant internal carburization was observed in supercritical CO 2 . The performance of these alloys indicates that these materials are compatible not only in oxidizing environments, but also in Supercritical CO 2 environments for extended service operation.

Preface for the 2010 Advances in Materials Technology for Fossil Power Plants conference.

A combined pilot-scale combustion test and long-term laboratory study investigated the impact of oxy-firing on corrosion in coal-fired boilers. Four coals were burned under both air and oxy-firing conditions with identical heat input, with oxy-firing using flue gas recirculation unlike air-firing. Despite higher SO 2 and HCl concentrations in oxy-firing, laboratory tests showed no increase in corrosion rates compared to air-firing. This is attributed to several factors: (1) Reduced diffusion: High CO 2 in oxy-firing densified the gas phase, leading to slower diffusion of corrosive species within the deposit. (2) Lower initial sulfate: Oxy-fired deposits initially contained less sulfate, a key hot corrosion culprit, due to the presence of carbonate. (3) Reduced basicity: CO 2 and HCl reduced the basicity of sulfate melts, leading to decreased dissolution of metal oxides and mitigating hot corrosion. (4) Limited carbonate/chloride formation: The formation of less corrosive carbonate and chloride solutes was restricted by low O 2 and SO 3 near the metal surface. These findings suggest that oxy-firing may not pose a greater corrosion risk than air-firing for boiler materials.