A novel carbon-based process for flue-gas cleanup. Final report

Selective catalytic reduction (SCR) technology increasingly is being applied for controlling emissions of nitrogen oxides (NOx) from coal-fired boilers. Some recent field and pilot studies suggest that the operation of SCR could affect the chemical form of mercury (Hg) in coal combustion flue gases. The speciation of Hg is an important factor influencing the control and environmental fate of Hg emissions from coal combustion. The vanadium and titanium oxides, used commonly in the vanadia-titania SCR catalyst for catalytic NOx reduction, promote the formation of oxidized mercury (Hg2+). The work reported in this paper focuses on the impact of SCR on elemental mercury (Hg0) oxidation. Bench-scale experiments were conducted to investigate Hg0 oxidation in the presence of simulated coal combustion flue gases and under SCR reaction conditions. Flue gas mixtures with different concentrations of hydrogen chloride (HCl) and sulfur dioxide (SO2) for simulating the combustion of bituminous coals and subbituminous coals were tested in these experiments. The effects of HCl and SO2 in the flue gases on Hg0 oxidation under SCR reaction conditions were studied. It was observed that HCl is the most critical flue gas component that causes conversion of Hg0 to Hg2+ under SCR reaction conditions. The importance of HCl for Hg0 oxidation found in the present study provides the scientific basis for the apparent coal-type dependence observed for Hg0 oxidation occurring across the SCR reactors in the field.

A new semidry flue gas desulfurization (FGD) process is proposed. The process uses a magnetically fluidized bed (MFB) as the reactor in which ferromagnetic particles are fluidized with simulated flue gas under the influence of an external magnetic field. A slurry of lime is continuously sprayed into the reactor by an atomizer fixed at the top of the bed. As a consequence, the desulfurization reaction and slurry drying take place simultaneously in a same reactor. Experiments with a laboratory‐scale apparatus were carried out to investigate the roles of the ferromagnetic particles and the magnetic field applied in the desulfurization reaction. The results show that when ferromagnetic particles are used as the fluidization material, both sulfite (SO32–) salts and sulfate (SO42–) salts are found in the desulfurization products. When quartz particles are used, only sulfite (SO32–) salts are found. This suggests that the Fe(III) ions and Fe(II) ions result from the ferromagnetic particles dissolving in the liquid phase. In addition, the ions act as catalysts in the oxidation of S(IV) to S(VI) and react with SO2 producing FeSO3 and Fe2(SO4)3 as the products. On the other hand, the level of the sulfate (SO42–) salts in the products increases with increasing intensity of applied field intensity, which suggests that the oxidation of S(IV) can be enhanced by the applied magnetic field. The oxidation of S(IV) can increase the solubility of SO2, and therefore, intensify the reaction between SO2 and Ca(OH)2, leading to an increased SO2 removal efficiency.

Nanostructured copper sulfide synthesized with the assistance of surfactant with nanoscale particle size and high Brunauer-Emmett-Teller surface area was for the first time applied for the capture of elemental mercury (Hg0) from coal combustion flue gas. The optimal operation temperature of nano-CuS for Hg0 adsorption is 75 °C, which indicates that injection of the sorbent between the wet flue gas desulfurization and the wet electrostatic precipitator systems is feasible. This assures that the sorbent is free of the adverse influence of nitrogen oxides. Oxygen (O2) and sulfur dioxide exerted a slight influence on Hg0 adsorption over the nano-CuS. Water vapor was shown to moderately suppress Hg0 capture efficiency via competitive adsorption. The simulated adsorption capacities of nano-CuS for Hg0 under pure nitrogen (N2), N2 + 4% O2, and simulated flue gas reached 122.40, 112.06, and 89.43 mgHg0/g nano-CuS, respectively. Compared to those of traditional commercial activated carbons and metal sulfides, the simulated adsorption capacities of Hg0 over the nano-CuS are at least an order of magnitude higher. Moreover, with only 5 mg loaded in a fixed-bed reactor, the Hg0 adsorption rate reached 11.93-13.56 μg/g min over nano-CuS. This extremely speedy rate makes nano-CuS promising for a future sorbent injection technique. The anisotropic growth of nano-CuS was confirmed by X-ray diffraction analysis and provided a fundamental aspect for nano-CuS surface reconstruction and polysulfide formation. Further X-ray photoelectron spectroscopy and Hg0 temperature-programmed desorption tests showed that the active polysulfide, S-S dimers, and copper-terminated sites contributed primarily to the extremely high Hg0 adsorption capacity and rate. With these advantages, nano-CuS appears to be a highly promising alternative to traditional sorbents for Hg0 capture from coal combustion flue gas.

Activated carbon has been used commercially to remove SO2 from coal combustion flue gas. However, the role of inherent CaO in activated carbon is uncertain. In this study, the adverse effects of inherent CaO in the activated carbon derived from coconut shell (CSAC) on its desulfurization performance were systematically studied at the temperature range of 60-100 °C in a fixed-bed reactor. The solid sorbent samples were analyzed using scanning electron microscopy, X-ray diffraction, X-ray fluorescence, Fourier transform infrared spectroscopy, and Brunauer-Emmett-Teller analysis. The flue gas compositions were analyzed by using an online flue gas analyzer. The experimental results showed that the inherent CaO had a profoundly adverse influence on the desulfurization capacity and efficiency of CSAC at all of the temperatures studied. This adverse influence was clearly identified by a comparison of the desulfurization performance of the raw CSAC to those of the acid-washed CSAC samples. It was found that the removal of the inherent CaO from CSAC using a pretreatment of HCl aqueous solution led to an increase in the desulfurization capacity of 41.7%. The adverse effects were attributed to the conversion of CaO into dihydrate calcium sulfate whiskers which formed solid crystals that blocked the micropores of the CSAC particles.

Mercury (Hg) control technologies were evaluated at Minnkota Power Cooperative's Milton R. Young (MRY) Station Unit 2, a 450-MW lignite-fired cyclone unit near Center, North Dakota, and TXU Energy's Monticello Steam Electric Station (MoSES) Unit 3, a 793-MW lignite--Powder River Basin (PRB) subbituminous coal-fired unit near Mt. Pleasant, Texas. A cold-side electrostatic precipitator (ESP) and wet flue gas desulfurization (FGD) scrubber are used at MRY and MoSES for controlling particulate and sulfur dioxide (SO{sub 2}) emissions, respectively. Several approaches for significantly and cost-effectively oxidizing elemental mercury (Hg{sup 0}) in lignite combustion flue gases, followed by capture in an ESP and/or FGD scrubber were evaluated. The project team involved in performing the technical aspects of the project included Babcock & Wilcox, the Energy & Environmental Research Center (EERC), the Electric Power Research Institute, and URS Corporation. Calcium bromide (CaBr{sub 2}), calcium chloride (CaCl{sub 2}), magnesium chloride (MgCl{sub 2}), and a proprietary sorbent enhancement additive (SEA), hereafter referred to as SEA2, were added to the lignite feeds to enhance Hg capture in the ESP and/or wet FGD. In addition, powdered activated carbon (PAC) was injected upstream of the ESP at MRY Unit 2. The work involved establishing Hg concentrations and removal rates across existing ESP and FGD units, determining costs associated with a given Hg removal efficiency, quantifying the balance-of-plant impacts of the control technologies, and facilitating technology commercialization. The primary project goal was to achieve ESP-FGD Hg removal efficiencies of {ge}55% at MRY and MoSES for about a month.

A review on mercury in coal combustion process: Content and occurrence forms in coal, transformation, sampling methods, emission and control technologies

99/01170 Interaction of carbon dioxide with methane on oxide catalysts : Krylov, O. V. et al. Catal. Today, 1998, 42, (3), 211–215

This Topical Report summarizes progress on Cooperative Agreement DE-FC26-04NT42309, ''Field Testing of a Wet FGD Additive.'' The objective of the project is to demonstrate the use of a flue gas desulfurization (FGD) additive, Degussa Corporation's TMT-15, to prevent the reemissions of elemental mercury (Hg{sup 0}) in flue gas exiting wet FGD systems on coal-fired boilers. Furthermore, the project intends to demonstrate that the additive can be used to precipitate most of the mercury (Hg) removed in the wet FGD system as a fine TMT salt that can be separated from the FGD liquor and bulk solid byproducts for separate disposal. The project will conduct pilot and full-scale tests of the TMT-15 additive in wet FGD absorbers. The tests are intended to determine required additive dosage requirements to prevent Hg{sup 0} reemissions and to separate mercury from the normal FGD byproducts for three coal types: Texas lignite/Power River Basin (PRB) coal blend, high-sulfur Eastern bituminous coal, and low-sulfur Eastern bituminous coal. The project team consists of URS Group, Inc., EPRI, TXU Generation Company LP, Southern Company, and Degussa Corporation. TXU Generation has provided the Texas lignite/PRB co-fired test site for pilot FGD tests, Monticello Steam Electric Station Unit 3. Southern Company is providing the low-sulfur Eastern bituminous coal host site for wet scrubbing tests, as well as the pilot and full-scale jet bubbling reactor (JBR) FGD systems to be tested. A third utility, to be named later, will provide the high-sulfur Eastern bituminous coal full-scale FGD test site. Degussa Corporation is providing the TMT-15 additive and technical support to the test program. The project is being conducted in six tasks. Of the six project tasks, Task 1 involves project planning and Task 6 involves management and reporting. The other four tasks involve field testing on FGD systems, either at pilot or full scale. The four tasks include: Task 2 - Pilot Additive Testing in Texas Lignite Flue Gas; Task 3 - Full-scale FGD Additive Testing in High Sulfur Eastern Bituminous Flue Gas; Task 4 - Pilot Wet Scrubber Additive Tests at Yates; and Task 5 - Full-scale Additive Tests at Plant Yates. This topical report presents the results from the Task 2 and Task 4 pilot-scale additive tests. The Task 3 and Task 5 full-scale additive tests will be conducted later in calendar year 2006.

To evaluate mercury partitioning in a coal-fired power plant and to investigate the influence of the configuration of gas treatment facilities on mercury emission, data sets of mercury concentration in coal, coal combustion residues, wastewater, and stack gases were collected from 44 coal-fired power plants in Japan from 2001 to 2014. The mean mercury concentration in coal, measured from 1224 samples, was 0.039 mg/kg, while the mean emission rate, measured from 259 samples, was 3.63 μg/kWh. The total annual mercury emission from coalfired power plants in Japan, which was calculated using the mean emission rate, was 1.0 t. The mercury removal efficiency was found to be improved by decreasing the electrostatic precipitator (ESP) operation temperature and by implementing selective catalytic reduction (SCR). The combination of SCR, advanced low-temperature ESP, and flue gas desulfurization (FGD) showed a high mercury removal efficiency of 87.4% on average.

SOxemissions from coal‐fired plants cause harmful impacts on the environment and human being health. To limit SOxemissions, air pollution control regulations have been established on international and national levels, and industrially relevant SOxmitigation technologies have been rapidly developed and applied over the past few decades. In this article, fluidized bed combustion (FBC) for in‐furnace DeSOx, dry sorbent injection (DSI), spray drier absorber, circulating dry scrubber (CDS), and wet scrubber processes are comprehensively discussed.The wet scrubber process is the most widespread SO2mitigation technology around the world and is reviewed in detail. The chemistry of wet scrubber processes is analyzed. Four typical wet scrubber configurations are presented. Wet scrubber operational challenges are shortly discussed. The DSI process is comprehensively discussed as well. In this process, fine and dry sorbents are directly injected into flue gas to capture SOxand other acid gases. In the CDS process, flue gas flows upward through a fluidized bed of sorbents to create a long contact time and have good mass transfer conditions. The spray drier process uses an atomizer to generate fine droplets to contact and react with SO2. The regenerable processes are presented, in which sorbents are regenerated. The absorbed SO2is further processed to sealable elemental sulfur or sulfuric acid products. Finally, an outlook of recent and future developments and challenges for SOxmitigation technologies is given.Even though different effective SOxmitigation technologies are available, the economics of their application are dominated by many factors, such as emission limits, fuel quality, sulfur content, size of plant, firing system, availability of sorbents, and utilization of by‐products. Therefore, a case‐by‐case evaluation is recommended to find the most suitable flue gas desulfurization (FGD) process for a particular application.

As a new environmental-protection technology, large-scale ammonia-based Flue Gas Desulfurization (FGD) requires high control and process technology. The process of FGD almost includes all the operation units in chemical industry. In order to make the equipment adapt to some complex changes of original flue gas and operate on better work conditions like low energy consumption, optimum liquid/gas ratio, minimum water consumption, completely nitrites oxidization, the multivariable predictive control and soft sensor based on mechanism model are studied in this paper. And the results show that these problems of variables correlation, large delay and variables coupling of FGD are resolved. In addition, ammonia consumption is lower, by-products quality is improved, Besides, the process operation is more smooth and safe, so the equipment can run effectively and economically after carrying on advanced process control.

Evaluation of SO 2 oxidation and fly ash filtration by an activated carbon fluidized-bed reactor: The effects of acid modification, copper addition and operating condition

A 500 actual cubic feet gas per minute (acfm) pilot‐scale SO2 control study was undertaken to investigate flue gas desulfurization (FGD) by dry sodium sorbents in 400°F (204.5°C) flue gases emitted from a coal fired boiler with flue gas concentrations between 350 and 2500 ppm SO2. Powdered sodium alkaline reagents were injected into the hot flue gas downstream of the air preheater and the spent reagents were collected using an electrostatic precipitator. Three different sorbents were used: processed sodium bicarbonate of two particle sizes; solution mined sodium bicarbonate, and processed sodium sesquicarbonate. SO2 concentrations were measured upstream of the reagent injection, 25‐ft (7.62 m) downstream of the injection point, and downstream of the electrostatic precipitator. SO2 collection efficiencies ranged from 40 to 80% using sodium bicarbonate stoichiometric ratios from 0.5 to 3.0. Much of the in‐duct SO2 removal occurred during the first second of reagent reaction time, indicating that the sulfur dioxide–sodium reaction rates may be faster than have been measured for fixed bed measurements reported in the literature. © 2007 American Institute of Chemical Engineers Environ Prog, 2007

99/00039 Experimental and theoretical studies of catalytic ignition of coal

Historic and futuristic review of electron beam technology for the treatment of SO2 and NOx in flue gas