Richard D. Doctor

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.

STAR - H2 : the secure transportable autonomous reactor for hydrogen production and desalinization.

The Secure Transportable Autonomous Reactor for Hydrogen production is a modular fast reactor intended for the mid 21st century energy market wherein electricity and hydrogen are employed as complementary energy carriers and nuclear energy contributes to sustainable energy supply based on full transuranic recycle in a passively safe, environmentally friendly and proliferation-resistant manner suitable for widespread worldwide deployment.

Ocean Storage of Carbon Dioxide: Pipelines, Risers and Seabed Containment

Eight hundred tonnes of carbon dioxide (CO2 ) are dumped into the atmosphere every second. There has been a progressive rise in the CO2 content of the atmosphere, from 270 ppm in the pre-industrial era to more than 380 ppm now, rising by 15 ppm/decade. The overwhelming scientific consensus is that this is having a large effect on climate, and that as a result the Earth’s temperature will rise by 2°C or more before 2100 [1]. Agriculture, forestry, fisheries, the biosphere and human health will all be affected, though not all the impacts are negative. The level of the sea will rise by between 0.5 and 1 m, and there is a possibility of a much greater and catastrophic rise if warming should lead to a collapse of the Greenland or Antarctic ice sheets.Copyright

Chapter 6 – Clean Hydrogen from Coal with CO2 Capture and Sequestration

Publisher Summary This chapter discusses the opportunities for coal-derived hydrogen production technologies in the United States and their impact on environment. In the United States, the challenge to the continued use of natural gas creates an opportunity for coal-derived hydrogen. On a worldwide basis, approximately 18 percent of the worlds hydrogen is already derived from coal. Producing hydrogen from coal is more capital intensive than producing it from natural gas. Once the coal is converted to hydrogen, captured CO2, and electricity, the CO 2 must be transported to the site of sequestration. CO 2 can be transported as a compressed gas, a liquid, a solid, or in a high-pressure supercritical state. Furthermore, the US Department of Energys (DOE) Office of Fossil Energy is soliciting industrial interest in the FutureGen plant, a near-zero emissions coal-fed plant that will produce power and hydrogen. Unlike current coal-to-hydrogen technologies, FutureGen plants would employ integrated CO 2 management. The anticipated

- CO 2 capture for PC-boilers using oxy-fuels—A transition strategy

1.0 billion budget will support the design, construction, and operation of a 275 megawatt (MW) prototype plant to serve as a large-scale engineering laboratory for testing new clean power, carbon capture, and coal-to-hydrogen technologies.

Carbonate sequestration and CO2 pipeline logistics for the PJM region

This chapter discusses the fundamental concept that involves replacing combustion air with oxygen diluted by recirculated CO 2 from the flue gas. This eliminates N 2 -CO 2 separation, permitting more economical CO 2 recovery than competing amine systems. A CO 2 /O 2 molar ratio of ∼3 is necessary to preserve the heat-transfer performance and gas-path temperatures. In a site specific study retrofitting a low-sulfur coal-fed boiler, CO 2 recycle shows competitive, operating, and environmental release advantages when compared to amine scrubbing systems. Anticipated breakthroughs in O 2 production will further improve the advantages. For oxy-fuels high-sulfur operation using flue gas desulfurization (FGD) should be practical, and in a related experimental study, it is found that high CO 2 partial pressures from oxy-fuels have a negligible impact on SO 2 -reagent use although FGD solids handling will require redesign. One of the special opportunities afforded by CO 2 /O 2 recycle is that it should prove very attractive at sites considering repowering and converting to an integrated-gasification-combined-cycle (IGCC) to produce H 2 and electricity.

Capture of Geothermal Heat as Chemical Energy

Publisher Summary CO2 sequestration using carbonate mineralization and employing locally available sources for ultramafic rock was investigated for 300-MW and larger pulverized-coal fired power plants in the U.S. EPA Region II network known as PJM. PJM could deliver up to 147 × 10–3 Metric tons of CO2 daily and using nearby ultramafic resources it is technically feasible to provide all the resources for sequestering this volume of CO2 through mineralization. A Pennsylvania-based central carbonate formation facility located near Allentown, PA would be an appropriate host site for a central carbonate formation plant since Allentown is near the weighted geographical epicenter for the CO2 sources and is accessible to nearby zones in which the carbonates could be stored after formation. The proposed pipeline routes will follow existing right-of-way corridors and permission will need to be secured for 800 km of pipeline ranging in size from 10 to 48 inches. All but 135 km of this right-of-way will be subject to the rigorous administrative safety reviews now mandated by the U.S. Department of Transportation. The capture was considered to be

Prediction of physical properties of trans-critical CO2 mixtures

42 per metric ton of CO2 using an oxy-fired fuel approach. These costs could come down significantly with success in ongoing research.

Gasification combined cycle: Carbon dioxide recovery, transport, and disposal

Fluids that undergo endothermic reactions were evaluated as potential chemical energy carriers of heat from geothermal reservoirs for power generation. Their performance was compared with that of H2O and CO2. The results show that (a) chemical energy carriers can produce more power from geothermal reservoirs than water and CO2 and (b) working fluids should not be selected solely on the basis of their specific thermo-physical properties but rather on the basis of the rate of exergy (ideal power) they can deliver. This article discusses the results of the evaluation of two chemical energy carrier systems: ammonia and methanol/water mixtures.

Life-Cycle Analysis of a Shell Gasification-Based Multi-Product System with CO2 Recovery

Efforts to mitigate greenhouse gas emissions show that the CO 2 must be captured, compressed, transported, and injected into a suitable reservoir such as depleted oil-bearing strata. This chapter explores the complex behavior of CO 2 and its mixtures during transport and at the severe conditions that exist when crossing the critical fluid transition during injection. The selection of equation sets for the prediction of the physical properties of acid gas CO 2 and its mixtures (SO 2 , H 2 S, H 2 O, CH 4 , and N 2 ) in pipelines was documented by comparing simulated properties with published data for the supercritical fluid transition at pressures up to 30 MPa. The multi-parameter equation of state (EOS) sets that proved most accurate was the Peng–Robinson with Boston–Mathias upgrade (PRBM) and the Swartzentrube–Renon Polar (SR Polar) EOS. Regarding the data relevant to Oxy-Fuel compositions, the PRBM predictions for CO 2 with 3,000 ppm SO 2 showed that the most significant impact on pipeline performance was not from the SO 2 , but rather from the presence of diluents.