Powder River Basin Coal Research Articles

Reaction kinetics of Powder River Basin coal gasification in carbon dioxide using a modified drop tube reactor

Carbon dioxide gasification and coal pyrolysis rates were measured in a modified drop tube fixed bed reactor, accompanied with a rapid response, real-time gas analysis system. Rapid heating and fast pyrolysis of the coal sample are intended to approximate the injection of ambient temperature coal into a fluidized bed gasifier. Experiments were done from 833°C to 975°C and from 1atm to 12atm in a 4:1 mixture of CO2 and argon with coal particles ranging between 250μm and 850μm. Reaction rates and carbon conversions were calculated based on the CO signal from a quadrupole mass spectrometer. The random pore model closely fits the experimental results and fitting parameters are listed. Results from the effects of temperature and pressure, pyrolysis conditions, and characteristics of chars (surface area measurements, scanning electron microscope images) are presented.

Characterization of coal water slurry prepared for PRB coal

Powder River Basin (PRB) coal, which accounts for over 40% of the coal consumed for power generation in the United States, was investigated for preparation of coal water slurry (CWS). The static stability and rheology of the CWS were characterized as a function of loading. The coal loading was varied from 30% to 50% and both ionic (sodium polystyrene sulphonate (PSS)) and nonionic (Triton X-100) surfactants were employed as additives. The addition of PSS to PRB slurries was found to yield poor static stability. On the other hand, Triton X-100 was found to be an effective surfactant, reducing the sedimentation by more than 50% compared to the one without surfactant in 45% CWS. Adding Triton X-100 reduces the viscosity of the CWS for coal loadings of 30% and 40%. Although the viscosities for coal loading of 42.5% and 45% are higher when Triton X-100 is added, the static stability is significantly better than for samples without surfactant. The highest coal loading for PRB slurry with acceptable viscosity for pumping is 42.5%.

Advanced Chemistry Surrogate Model Development within C3M for CFD Modeling, Part 1: Methodology Development for Coal Pyrolysis

A generalized method was developed to implement complex chemistry from third-party computational coal chemistry tools within multiphase, reacting computational fluid dynamic (CFD) codes. This method involves generating response surfaces that represent the computational coal chemistry tool output and using them to build a comprehensive surrogate model which can be easily incorporated into a CFD code. In this first part of a series of work, the method was applied to coal pyrolysis of Powder River Basin coal using PC Coal Lab (PCCL) and Carbonaceous Chemistry for Computational Modeling (C3M) to generate the series of response surfaces which form the basis of the surrogate model that can be implemented in CFD. This method has the benefit that local environmental variables (such as heating rate, final pyrolysis temperature, local pressure, and particle diameter) can be incorporated as part of the chemistry model in CFD on a cell by cell, time step by time step basis which creates the potential to significantly...

Upgrading Low-Rank Coal Using a Dry, Density-Based Separator Technology

Low-rank coal such as the coal in the Powder River Basin (PRB) is typically direct shipped without any need for upgrading. Due to the lack of on-site processing capabilities, coal that is mixed with out-of-seam dilution during the mining process is typically left in the mine pit. In some cases, the loss could amount to 5% of the total reserve. Research conducted on laboratory and pilot-scale pneumatic air table separators indicates that sufficient upgrading can be achieved on the +1 mm fraction of the reject material to meet typical end-user specifications. Low-rank coals are especially susceptible to upgrading by density-based processes due its naturally lower density relative to higher rank coals. For example, a PRB coal containing 26% feed ash was reduced to 7% ash content with a combustible recovery of 83% on a dry basis from a coal source that was reject from the mining process. Partition curve data revealed the achievement of relatively low Ep values in the range of 0.12 to 0.22 with separation densities between 1.58 and 1.88 gm/cm3, respectively. Effective separations were achieved using air table separators for particle sizes larger than 1 mm.

A comparative process study of chemical-looping combustion (CLC) and chemical-looping with oxygen uncoupling (CLOU) for solid fuels

A solid-fuel combustion system based on chemical-looping combustion (CLC) and chemical-looping with oxygen uncoupling (CLOU) has the potential to assist in the capture of CO2 from coal-fired power plants. In both processes an air separation unit is not required, and the flue gas streams from CLC and CLOU contain primarily carbon dioxide and water, which facilitates CO2 capture. CLOU offers a potential advantage for solid fuels as it uses combustion reactions. The O2 for the combustion reactions in CLOU is supplied from the reduction of a metal oxide (e.g. CuO). Iron-based materials are being considered for oxygen carriers in CLC, wherein the coal is gasified, and subsequently the product gas is oxidized to CO2 and H2O by reaction with the circulating oxygen carrier. CLOU affords faster coal char oxidation reaction rates, as compared to CLC coal gasification reactions, but CuO-based materials for CLOU will necessarily be more expensive. Furthermore, the stability of CuO-based oxygen carrier materials is also an important concern. In this paper, ASPEN PLUS process engineering models were developed for combustion of a Wyoming Powder River Basin coal using an iron-based oxygen carrier for CLC and a copper-based oxygen carrier for CLOU. The objective of these process models was to evaluate the material and energy requirements for a process development unit by incorporating insights from previously reported kinetic studies on laboratory scale units. A relative economic analysis has also been performed to address key technical challenges which will subsequently help in addressing the development of CLC and CLOU for solid fuels. Due to slower char gasification reaction times, CLC requires a larger reactor, which results in a relatively higher capital cost. It also manifests in a higher pressure drop and consequently higher energy costs for fluidizing the oxygen carrier.

Characterization of the mechanism of gasification of a powder river basin coal with a composite catalyst for producing desired syngases and liquids

The objective of this research was to examine the mechanisms of FeCO3, Na2CO3, and FeCO3-Na2CO3 based catalytic coal gasification of a low-sulfur sub-bituminous Wyodak coal from the Powder River Basin (PRB) of Wyoming. X-ray diffraction (XRD), Mössbauer spectroscopy, scanning electron microscopy (SEM), Fourier transform infrared spectroscopy (FTIR), gas chromatography (GC–MS) and nuclear magnetic resonance spectroscopy (NMR) were used to perform the analyses. Use of composite catalysts for coal gasification overcomes some of the limitations of the standalone use of Na or Fe catalysts. The XRD results are consistent with interactive mechanisms or the formation of Na–Fe oxides as the catalytic pathway. Mössbauer spectroscopy indicated the presence of metallic iron and cementite in the char at different stages. The Fe catalysts were better at tar decomposition than the Na catalysts, as indicated by GC–MS analyses. NMR spectra confirmed that tar compositions vary with the catalytic mechanism. FTIR analysis confirmed the presence of high yields of aromatic components and long aliphatic chains in the tar. Composite Fe–Na catalysts provide a method to tailor the amounts and composition of product generated during gasification.

Conversion of metallurgical coke and coal using a Coal Direct Chemical Looping (CDCL) moving bed reactor

The CLC process has the potential to be a transformative commercial technology for a carbon-constrained economy. The Ohio State University Coal Direct Chemical Looping (CDCL) process directly converts coal, eliminating the need for a coal gasifier oran air separation unit (ASU). Compared to other solid-fuel CLC processes, the CDCL process is unique in that it consists of a countercurrent moving bed reducer reactor. In the proposed process, coal is injected into the middle of the moving bed, whereby the coal quickly heats up and devolatilizes, splitting the reactor roughly into two sections with no axial mixing. The top section consists of gaseous fuel produced from the coal volatiles, and the bottom section consists of the coal char mixed with the oxygen carrier. A bench-scale moving bed reactor was used to study the coal conversion with CO2 as the enhancing gas. Initial tests using metallurgical cokefines as feedstock were conducted to test the effects of operational variables in the bottom section of the moving bed reducer, e.g., reactor temperature, oxygen carrier to char ratio, enhancer gas CO2 flow rate, and oxygen carrier flow rates. Experiments directly using coal as the feedstock were subsequently carried out based on these test results. Powder River Basin (PRB) coal and Illinois #6 coal were tested as representative sub-bituminous and bituminous coals, respectively. Nearly complete coal conversion was achieved using composite iron oxide particles as the oxygen carriers without any flow problems. The operational results demonstrated that a moving bed reactor design is favorable for the CDCL application.

Novel Temperature-Controlled Ash Deposition Probe System and Its Application to Oxy-coal Combustion with 50% Inlet O2

Prediction of ash deposition characteristics under oxy-firing conditions helps to determine how retrofit to oxy-combustion might affect boiler performance. To obtain data to help achieve this end, a novel temperature-controlled ash deposition probe was designed to collect temporally resolved deposit samples in a 100 kW rated down-flow test furnace system, firing a Powder River Basin coal. The rig was designed to represent practical units in terms of temperatures and particle and gas concentrations yet still be sufficiently well-defined to allow for controlled systematic studies. The deposit probe/furnace system, which is described in detail, was designed to segregate early “inside” deposits from the average deposits gathered over a period of time. Deposits were gathered under controlled conditions for oxidant input conditions of 50% O2/50% CO2 (once through, with no flue gas recycle) and air. Effects of the deposit holding time, deposit probe temperature, and flue gas temperature at the probe location were investigated. Temporal segregation of deposits was achieved by physically separating deposits gathered on the horizontal probe surface into “inside” and “outside” deposits, where “inside” deposits approximated the initial deposit layers. Furthermore, results showed that deposits gathered over long times on the vertical surface of the probe were similar with respect to both composition and particle size distribution to the inside layer of the horizontal deposits, but different from the bulk horizontal deposits that have typically been reported in the literature. There were no significant effects of holding times greater than 1 h on bulk deposit compositions, although particle size within the deposit did appear to increase with time. There were also no significant differences between compositions of “outside” deposits from oxy-firing (OXY50) and those from air firing. “Inside” deposits from OXY50, however, contained higher Si and Fe and lower S and Na compared to those from air combustion. These results are interpreted in the light of available mechanisms. Tests in which only the deposit surface temperature was changed showed that the mass of deposits on the vertical surface parallel to the flow, shown to be representative of the “inside” deposits on the horizontal surface, was proportional to the temperature difference between the flue gas and the surface. This supported the hypothesis that the early layer was deposited largely by thermophoresis of small particles and not by Fickian or Brownian diffusion or impaction.

The effect of coal oxidation on methane production and microbial community structure in Powder River Basin coal

Vast reserves of coal represent a largely untapped resource that can be used to produce methane gas, a cleaner energy alternative compared to burning oil or coal. Microorganisms are able to utilize coal as a carbon source, producing biogenic methane. The conversion of coal to methane by microorganisms has been demonstrated experimentally by a number of research groups, but coal handling and treatment prior to incubation often goes unreported and may impact biogenic methane production. Microcosm experiments were designed to assess how prior exposure of coal to oxygen might influence methane production (e.g., as in a dewatered coal-bed natural gas system). Microcosms containing oxidized and un-oxidized coal samples from the Powder River Basin were incubated with and without inoculation with an enrichment culture derived from coal. Gas chromatography and pyrosequencing of the 16S rRNA gene were used to assess how coal oxidation affects methane production and microbial community structure within microcosm samples. Although the magnitude of methane production differed between experiments, the oxidized coal microcosms consistently produced between 50 and 100 micromoles less methane per gram of coal than the un-oxidized microcosms. Additionally, un-inoculated microcosms produced levels of methane comparable to their inoculated counterparts, demonstrating the importance of native, coal-associated microbial assemblages in biogenic methane production. Specific methanogens were identified in the different treatments and their relative prevalence supported the relative level of methane production. Common coal-associated bacterial groups such as δ- and γ-Proteobacteria, Spirochaetes and Firmicutes were prevalent in different microcosms, though the presence of specific bacteria was not correlated with methane production. These data suggest that while coal oxidation decreased methane production, oxidation was not a primary factor in the variation between microcosm community structures.

Powder River Basin Coal: Powering America

Powder River Basin (PRB) coal in Wyoming and Montana is used to produce 18 percent of the electricity consumed in the United States. Coal production from the PRB more than doubled between 1994 and 2009. PRB coal companies produced greater amounts of coal at declining real prices over much of this period through investment in equipment and production systems that achieved massive economies of scale. The bulk of PRB coal is shipped to the middle part of America from Texas in the south to Michigan in the north and New York in the east. States that consume significant amounts of PRB coal have electricity rates well below the national average. The largest industrial users of electricity are in these regions. Replacing PRB coal would require almost 5.5 trillion cubic feet of natural gas per year, representing a 26 percent increase in demand. Such an increase in gas consumption would increase prices for natural gas by roughly 76 percent. In such a world, U.S. energy users would pay $107 billion more each year for electricity and natural gas. Hence, by using PRB coal, the U.S. economy avoids $107 billion per year in higher energy costs. Estimates reported in the literature indicate that the gross environmental damages from PRB coal production are $27 billion. Hence, the net social benefits of PRB coal are $80 billion per year. Given the large size and low cost of these reserves, PRB coal will likely supply societal energy needs well into the future as long as the public and their elected officials are willing to accept the environmental impacts in return for the substantial economic benefits from using PRB coal.

Extent and limits of biodegradation by in situ methanogenic consortia in shale and formation fluids

Consortia of microbes degrade recalcitrant organic-matter in deep subsurface reservoirs, such as shales and coals, under anaerobic conditions into simple C molecules such as CO2 and acetate. These substrates are subsequently metabolized by methanogens into economic quantities of natural gas in sedimentary basins world-wide. This study explores organic matter in the Devonian New Albany Shale (Illinois Basin, USA) and associated fluids to investigate the extent of organic matter biodegradation, and evaluate the potential for stimulating in situ gas production. Identification of labile compound classes such as n-alkanes, fatty acids, and phenols in produced waters of the New Albany Shale, and low biodegradation indices in the shale core samples indicate limited biodegradation. Together with detectable acetate concentrations (up to 225.1 μM), these observations suggest that both the supporting microbial consortia and methanogens are limited in extent and activity. By comparison, the New Albany Shale is much less biodegraded than the microbial CH4-producing Michigan Basin Antrim Shale, Powder River Basin coals, or San Juan Basin coals. In the New Albany Shale, the extent of biodegradation generally becomes more varied with higher salinities, suggesting diverse microbial adaptations to degrade OM at high salinities. Enhancement of in situ CH4 production may be most effective if targeted at stimulating production of the supporting microbial consortia as well as methanogens.

In Situ Characterization of Ash Thermal Conductivity for Three Coal Types Formed Under Oxidizing and Reducing Conditions in a Laboratory Furnace

This work presents in situ measurements of the effective thermal conductivity in particulate coal ash deposits under both reducing and oxidizing environments. Laboratory experiments generated deposits on an instrumented deposition probe of loosely bound particulate ash from three coals generated in a down-fired flow reactor with optical access. An approach is presented for making in situ measurements of the temperature difference across the ash deposits, the thickness of the deposits, and the total heat transfer rate through the ash deposits. Using this approach, the effective thermal conductivity was determined for coal ash deposits formed under oxidizing and reducing conditions. Three coals were tested under oxidizing conditions: two bituminous coals derived from the Illinois #6 basin and a subbituminous Powder River Basin coal. The subbituminous coal exhibited the lowest range of effective thermal conductivities (0.05–0.18 W/m K) while the Illinois #6 coals showed higher effective thermal conductivities (0.2–0.5 W/m K). One of the bituminous coals and the subbituminous coal were also tested under reducing conditions. A comparison of the ash deposits from these two coals showed no discernible difference in the effective thermal conductivity based on stoichiometry. All experiments indicated an increase in effective thermal conductivity with deposit thickness, probably associated with deposit sintering.

Effect of Weathering of Coal and Organic Dusts on Their Spontaneous Ignition

Weathering of coal and other cellulosic dusts occur due to the process of wetting and subsequent drying, or by subjecting them to a temperature higher than the ambient temperature for prolonged time periods. The first type of weathering occurs in a wetted storage. The second type of weathering occurs when a dust processing unit stores and maintains the dust deposit at an elevated temperature. As a result of weathering, the physical and thermal properties of the dust may change. Therefore, the weathered dust sample is expected to ignite at a different hot plate temperature as compared to that of a fresh sample, when tested in a standard test method (ASTM E 2021). In this study, three dust samples namely, wheat flour, Pittsburgh seam coal and powder river basin coal, are tested. These dust samples are subjected to one or both types of weathering. Thermogravimetric analysis and standard ignition tests are carried out with both fresh and weathered dust samples. Estimation of the activation energies and reactivity, and measurement of the minimum surface temperature for the onset of ignition have been carried out for all the cases. The implications of the observed results on industrial safety related to combustible dust layers are discussed.

Catalytic gasification of a Powder River Basin coal

Catalytic gasification of a Wyodak low-sulfur sub-bituminous coal from the Powder River Basin of Wyoming was investigated using an inexpensive catalyst, Na2CO3, widely available in Wyoming. Experiments were performed in an atmospheric pressure fixed-bed laboratory gasifier. The effects of different factors including feed gas composition, catalyst loading and reaction temperature on the associated coal pyrolysis and char gasification were evaluated. Na2CO3 was found to be active during both pyrolysis and gasification steps and it can considerably decrease the activation energy of gasification step. The optimal Na2CO3 addition level is approximately 3wt.%. Shrinking core model and random pore model can be used to fit the kinetic data obtained under both non-catalytic and catalytic conditions.

Role of exhaust gas recycle on submicrometer particle formation during oxy-coal combustion

During oxy-coal combustion, recycled exhaust gas is used as a diluent to replace nitrogen in pulverized coal-fired boilers to moderate boiler temperatures. The effect of recycle (upto recycle ratios of 60%) on combustion of Powder River Basin (PRB) coal related submicrometer particle formation was investigated in a drop-tube furnace system. The recycled exhaust gas containing lower O2 concentration and higher CO2 concentration suppressed submicrometer particle formation. However, it was found that water vapor in recycled exhaust gas greatly enhanced the formation of submicrometer particles. The gas composition changes that result with exhaust-gas recycle significantly affected the size distribution of submicrometer particles at the exit of the combustor. Differences in the particle size distribution with and without filtration of recycled exhaust gas was insignificant. The composition of the resultant particles in oxy-coal combustion and conventional coal-air combustion as determined by X-ray diffraction was similar.

Effect of Flue Gas Treatment on the Solubility and Fractionation of Different Metals in Fly Ash of Powder River Basin Coal

Studies were conducted to examine the effect of flue gas carbon dioxide (CO2) on solubility and availability of different metals in fly ash of Powder River Basin (PRB) coal, Wyoming, USA. Initial fly ash (control) was alkaline and contains large amounts of water-soluble and exchangeable metals. Reaction of flue gas CO2 with alkaline fly ash resulted in the formation of carbonates which minimized the solubility of metals. Results for metal fractionation studies also supported this fact. The present study also suggested that most of the water-soluble and exchangeable metals present in the control (untreated) fly ash samples decreased in the flue gas-treated samples. This may be due to the transfer of the above two forms to more resistant forms like carbonate bound (CBD), oxide bound (OXD), and residual (RS). Geochemical modeling (Visual MINTEQ) of water solubility data suggested that the saturation index (SI) values of dolomite (CaMg(CO3)2) and calcite (CaCO3) were oversaturated, which has potential to mineralize atmospheric CO2 and thereby reduce leaching of toxic metals from fly ash. Results from this study also showed that the reaction of flue gas CO2 with alkaline fly ash not only control the solubility of toxic metals but also form carbonate minerals which have the potential to fix CO2.

Mercury emission control from coal combustion systems: A modified air preheater solution

Results are presented of pilot-plant testing of a new approach to resolve the mercury control problem primarily from coal combustors. Performed at the Western Research Institute’s facility in Laramie, Wyoming, the recorded data reflect the previous laboratory results that proved that untreated steel or platinum surfaces in a specific downstream temperature range can significantly convert gaseous atomic mercury to its water-soluble gaseous dichloride without a need for catalysis or amalgamation. This was confirmed by utilizing various steel inserts in a pilot-plant scale combustor fueled by a low-chlorine Powder River Basin coal. The results and mechanism help to explain why it is in full-scale combustors that large excesses of chlorine generally are necessary to convert their very low concentrations of mercury. These efforts have further validated the underlying predominance of mercury’s heterogeneous chemistry. Most importantly it has illustrated that the efficient laboratory proven mechanism extrapolates to the low mercury parts per billion by volume (ppbv) concentrations relevant to full-scale coal combustion. Depending on conditions, chlorine can become less controlling, removing the need for halogen addition or coal blending approaches as possible methods for mercury control. Additional testing now is establishing the exact surface area of the inserted thin metallic surfaces and the residence time required to attain specific conversion efficiencies. Optimal surface temperatures are about 230±30°C (450±50°F) for the conversion mechanism. As a result, this temperature region generally will occur in the location of air preheaters in many coal combustions. This also explains previous reports of mercury oxidation across these and other lower temperature devices. Suggestions now are made for modifying or retrofitting air preheater designs. This enhancement of what is mercury’s natural chemical mechanism now raises the possibility for a one-time modification of the combustion train to resolve this otherwise rather expensive problem.

Relationship between Particle Size Distribution of Low-Rank Pulverized Coal and Power Plant Performance

The impact of particle size distribution (PSD) of pulverized, low rank high volatile content Alaska coal on combustion related power plant performance was studied in a series of field scale tests. Performance was gauged through efficiency (ratio of megawatt generated to energy consumed as coal), emissions (SO2,NOx, CO), and carbon content of ash (fly ash and bottom ash). The study revealed that the tested coal could be burned at a grind as coarse as 50% passing 76 microns, with no deleterious impact on power generation and emissions. The PSD’s tested in this study were in the range of 41 to 81 percent passing 76 microns. There was negligible correlation between PSD and the followings factors: efficiency, SO2,NOx, and CO. Additionally, two tests where stack mercury (Hg) data was collected, did not demonstrate any real difference in Hg emissions with PSD. The results from the field tests positively impacts pulverized coal power plants that burn low rank high volatile content coals (such as Powder River Basin coal). These plants can potentially reduce in-plant load by grinding the coal less (without impacting plant performance on emissions and efficiency) and thereby, increasing their marketability.

Measurement of PM2.5 and ultra-fine particulate emissions from coal-fired utility boilers

The new international regulations that limit the ambient PM2.5 levels necessitated reliable methods to monitor and report these very fine particulate matter emissions from contributing sources. Due to the inadequacies of conventional stack sampling methods, source dilution techniques were developed in particulate matter (PM) measurement from combustion sources to closely simulate realistic atmospheric conditions where hot stack gases transform to very fine secondary aerosols. Using such dilution samplers, a PM2.5 database from coal-fired utility boilers was initiated using field measurement results. Fuels include blends of Canadian subbituminous, Canadian lignite and US Powder River Basin coals. PM2.5 concentration results, along with their elemental and sulphate constituents found in emissions from utility boilers, are discussed in conjunction with coal feed properties. The nature of ultra-fine components found in stack emission is briefly reported.

Mercury capture by boiler modifications with sub-bituminous coals

The extent of mercury (Hg) emissions at a particular coal-fired boiler is unit-specific and determined by factors that include the type of coal fired, boiler operating conditions, and the amount of Hg removed at the boiler back-end by the pollution control devices. Mercury speciation, adsorption and removal in the boiler are affected by parameters such as the flue gas and fly ash characteristics, and back-end boiler configuration/operation. Various studies have reported that boiler operating conditions can be optimized to enhance the “naturally” occurring Hg capture in coal-fired boilers.A study was carried out to investigate the impact of boiler operating conditions on Hg emissions at a full-scale coal-fired power plant. Testing was performed at a 810MW coal-fired power plant firing a Northern Powder River Basin (PRB) coal, and equipped with a low-NOx system and a wet flue gas desulfurization (FGD) system for particulate and sulfur dioxide (SO2) control. Speciated (total and elemental, Hg0) Hg measurements and analytical procedures were performed according to the Ontario Hydro Method (OHM)/ASTM D6784-02 Method. OHM measurements were conducted at the air preheater (APH) inlet and the stack. Mercury emissions were also continuously monitored using single-point, non-isokinetic sampling with semi-continuous emissions monitors (SCEM). Readings from these analyzers were used for guidance during boiler control setting manipulations. Individual semi-continuous sampling modules were installed at four single-point locations along the convective pass: APH inlet, FGD inlet, FGD outlet and the stack.The test results obtained in this study showed the benefit of boiler modifications for Hg control and the extent to which the “natural” Hg control could be influenced. Parametric testing indicated a modest, but inconsistent improvement in the stack Hg (HgT) emissions at reduced excess oxygen. This was probably due to the fact that the fly ash unburned carbon levels were very low (less than 1.0%). Modifications to the low-NOx system over-fire registers, burner tilt and FGD liquid-to-gas (L/G) ratio resulted in stack HgT reductions in excess of 25%. The FGD L/G ratio manipulations also resulted in an improvement in oxidized mercury removal across the FGD. However, none of the test data suggested any reduction in Hg0 across the FGD. The combination of optimal boiler control settings for reduced Hg emission operation resulted in a 34.5% reduction in HgT at the stack.