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At least 91 records · Page 5Linked to original sources
USGS2022

New insights into the occurrence and implications of mobile water in gas hydrate systems

Gas hydrate production technologies commonly feature reservoir depressurization. Depressurization occurs when a pressure gradient is established in a well, drawing mobile water from the reservoir and reducing reservoir pressure. As such, the occurrence of mobile water is a necessary condition for effective gas production from gas hydrate reservoirs using common borehole-based methods. However, recent field programs have revealed that mobile water exists widely within the overall gas hydrate reservoir system, including within overlying and underlying units once thought of as virtually impermeable seals. Further, excess free water may also be commonly found in hydrate-free or hydrate-poor permeable strata interbedded within the larger gas hydrate reservoir system. Such internal sources of water are complex to characterize, difficult to explain, potentially highly heterogeneous, and may pose significant challenges to depressurization-based production. This report summarizes the general occurrence of water in gas hydrate systems and select technical implications.

Journal of Energy and Fuels↗
USGS2022

Advanced distributed acoustic sensing vertical seismic profile imaging of an Alaska North Slope gas hydrate field

Gas hydrates are found in significant quantities on the North Slope of Alaska in subpermafrost sand units and intermixed in lower portions of permafrost within the hydrate stability window. While conventional surface seismic data and established imaging methods can indicate the presence of gas hydrate reservoirs, producing high-resolution images of (seismically) thin layers remains challenging due to the preferential attenuation of the higher-frequency data components. An alternative strategy is to use distributed acoustic sensing (DAS) involving cementing optical fibers into boreholes to measure seismic wavefield energy closer to the strata of interest using vertical seismic profiling (VSP). DAS VSP imaging takes advantage of the shorter travel paths and reduced attenuation to generate higher-resolution near-well images. We illustrate these benefits on a DAS VSP data set acquired at the Hydrate-01 stratigraphic test well located in the Prudhoe Bay Unit of Alaska where significant gas hydrate deposits have been detected in two subpermafrost sand layers that are intended for long-duration production testing. Our DAS data preprocessing workflow effectively isolates the upgoing compressional-wave (P-wave) reflections required for subsurface acoustic imaging. After applying three-dimensional (3-D) tomography to improve the quality of the 3-D migration velocity model, we use 3-D reverse-time migration (RTM) to develop high-quality images of the two target sands and minor near-well faulting. We validate our RTM images through highly accurate well-ties with previously acquired petrophysical log data. This study demonstrates that combining 3-D RTM imaging with DAS VSP data provides significant value to gas hydrate and similar projects, and it suggests that more advanced inversion approaches such as (elastic) least-squares RTM could recover higher-resolution and more quantitative estimates of subsurface reflectivity, which would be valuable for refining the understanding of gas hydrate systems.

Alaska↗
USGS2022

Review of past gas Production attempts from subsurface gas hydrate deposits and necessity of long-term production testing

This paper summarizes the conditions, applied techniques, results, and lessons of major field gas production attempts from gas hydrates in the past and the necessity of longer term production testing with the scale of years to fulfill the gap between the currently available information and the knowledge required for commercial development. The temporal and spatial scales of field production test projects employing depressurization have expanded since 2002. The results from the projects have proved the applicability of these techniques in both onshore and offshore conditions. However, many technical and reservoir condition-related issues have emerged in gas production, and the gap between current status and industrial requirements is still large. Sand control, artificial lift, and related flow assurance issues are common technical issues that impact onshore and offshore production testing operations. Different reservoir responses were observed well by well, and discrepancy between model predictions and actual field measurements were seen, although reasonable matches were made for short-term behaviors. Those observations suggest that temporal change of the wellbore and near-wellbore conditions and reservoir heterogeneity that cannot be fully modeled have caused complex short-term responses to the depressurization operations. To ensure the long-term operational stability and reliability of the prediction technologies for production behaviors that are essential for commercialization of gas hydrate resources, gas hydrate production testing with comparable duration with commercial operations are necessary. Due to the locality of geological conditions in gas hydrate reservoirs, numerous gas production tests will be required to understand the factors controlling gas production.

Journal of Energy and Fuels↗
USGS2022

Scientific results of the Hydrate-01 Stratigraphic Test Well Program, Western Prudhoe Bay Unit, Alaska North Slope

The United States Department of Energy, the MH21-S Research Consortium of Japan, and the United States Geological Survey are collaborating to enable gas hydrate scientific drilling and extended-duration reservoir response testing on the Alaska North Slope. To feasibly execute such a test, a location is required that is accessible from existing roads and gravel pads and that can be occupied without disrupting ongoing industry operations. A review of potential locations meeting these criteria determined the likely occurrence of gas hydrate in two fine-grained marginal-marine sands of Tertiary age in the vicinity of the inactive “Kuparuk State 7-11-12” exploration pad in the western Prudhoe Bay Unit (PBU). Existing well and seismic data for that site were insufficient to preclude the potential for free gas occurrence within the deeper (and most prospective) target sand. Therefore, with support from the PBU Working Interest Owners, Alaska Department of Natural Resources, and Petrotechnical Resources Alaska, the Hydrate-01 Stratigraphic Test Well (STW) was drilled in December 2018 to confirm the suitability of the site for future gas hydrate scientific testing. The Hydrate-01 well was successfully drilled to −3290 ft (1003 m) subsea vertical depth at a bottom hole location of approximately 900 ft (∼275 m) east of the surface location. The drilling program featured acquisition of a full suite of logging while drilling data, the collection of side-wall pressure cores, and the installation of distributed temperature and distributed acoustic sensor fiber-optic cables. The log data acquired confirmed the occurrence of gas hydrate at high saturation in two target sands. Integrated evaluation of log and sidewall core data provide petrophysical and geomechanical property information that allow for potential reservoir response to depressurization to be simulated. The deeper “B1 sand” is deemed to be most favorable for reservoir response testing as a result of confirmed gas hydrate occurrence in sediments of high intrinsic permeability, location within 100 ft (30 m) of the base of gas hydrate stability, and minimal risk for direct communication with permeable water-bearing (hydrate-free) zones. The shallower “D1 sand” provides a secondary target that is differentiated by colder in situ temperatures and the interpreted direct hydraulic communication to a lower section of non-hydrate-bearing, water-saturated sand. The Hydrate-01 log data also confirm the occurrence of at least one sub-seismic fault in close proximity to the B1 sand reservoir. To better image the distribution of the gas-hydrate-bearing reservoir sections and associated faults, a three-dimensional (3D) vertical seismic profile was conducted in early 2019 using the distributed acoustic sensors installed as part of the Hydrate-01 STW completion. Detailed two-dimensional (2D) and 3D geologic models have been constructed to enable numerical simulations to inform the planning for potential future scientific tests of reservoir response to depressurization at the site.

Alaska↗
USGS2022

Geological reservoir characterization of a gas hydrate prospect associated with the Hydrate-01 Stratigraphic Test Well, Alaska North Slope

Geological reservoir characterization is essential for accurate evaluation of gas production performance from gas hydrate reservoirs. Particularly, the understanding of reservoir architecture and heterogeneity is of great importance since these are considered as major controls on fluid hydrodynamic and thermodynamic conditions. This study deals with well log and three-dimensional (3-D) vertical seismic profile (VSP) data acquired from the Hydrate-01 Stratigraphic Test Well within the 7-11-12 prospect, Prudhoe Bay Unit, Alaska North Slope and reports on the results of geological/geophysical evaluation related to the geological structure and reservoir properties of the 7-11-12 prospect. The structural trends of the target reservoirs, based on well correlations, are mostly consistent with the predrill prediction using the surface seismic data, and infer the existence of subseismic faults cutting through the Hydrate-01 well. The 3-D VSP data confirm a down-to-the-east normal fault that offsets the reservoir units across the Hydrate-01 well, which is concordant with the well identification of the same fault, and indicate a northeast-dipping relay structure associated with the overstepping normal faults. The edge enhancement attribute associated with discontinuity generated from the 3-D VSP data shows small faults/fractures, possibly as part of a complex fault network within the imaged normal fault system. These results reveal that the 3-D VSP data provide detailed structural information that is not present from the surface seismic data. The Hydrate-01 well log data confirm the occurrence of gas hydrate at high saturation in the two targeted sand units (B1 and D1 sands), and the comparison to a nearby pre-existing well (7-11-12 well) shows the same general trend in gas hydrate saturation as a map of seismic impedance generated from surface seismic data. The well log data also suggest that the base of gas hydrate occurrence in the Hydrate-01 and 7-11-12 wells is almost aligned at the same depth in both of the targeted B1 and D1 sand reservoirs. Especially for the D1 sand in the Hydrate-01 well, the resistivity logs show a sharp transition from high gas hydrate saturation to fully water-saturated within the D1 sand, suggesting a common gas hydrate/water contact. The results of this study will be used to construct the geological models needed for reservoir simulation studies and they can provide important insights into the geological factors that control the occurrence of gas hydrate on the Alaska North Slope.

Alaska↗
USGS2024

3-D geological modeling for numerical flow simulation studies of gas hydrate reservoirs at the Kuparuk State 7-11-12 Pad in the Prudhoe Bay Unit on the Alaska North Slope

Accurate reservoir evaluation requires reliable three-dimensional (3-D) geological models. This study conducted 3-D geological modeling for numerical flow simulation of the B1 sand gas hydrate reservoir at the Kuparuk State 7-11-12 pad, Prudhoe Bay Unit, Alaska North Slope. The model integrates well logs, core, and seismic data to address spatial heterogeneity in geological structures and reservoir properties. Two modeling types were performed: structural framework modeling and petrophysical property modeling. For structural framework modeling, seismic data and well log markers were used to reproduce subsurface structures characterized by a normal fault system. A volume-based modeling algorithm and stair-step gridding were applied. The resulting 3-D model comprised 2,640,000 grid cells across 264 layers, including seven fault grids. For petrophysical property modeling, total porosity was initially modeled using sequential Gaussian simulation with collocated cokriging. To reproduce the upward coarsening of the B1 sand, upscaled log-derived total porosity and a 3-D trend depicting total porosity variation were used as primary and secondary data, respectively. Gas hydrate saturation distribution was modeled similarly, with secondary data from estimated porosity distribution and seismic-derived acoustic impedance map enhancing accuracy. Results indicate higher gas hydrate saturation in the upper part of the B1 sand and areas with higher acoustic impedance. Intrinsic permeability was modeled from the total porosity and clay-bound water volume, and effective permeability was derived from the gas hydrate saturation and intrinsic permeability distributions based on the “Tokyo model”. Effective permeability distributions were influenced by the total porosity, gas hydrate saturation, and intrinsic permeability. Within the same layer, higher gas hydrate saturation leads to decreased effective permeability. In total, 100 sets of multiple scenarios were prepared, providing input data for dynamic flow simulations to evaluate the effects of lateral heterogeneity in reservoir properties and the hydraulic characteristics of faults on production behavior for preassessment before the long-term production test.

Alaska↗
USGS2017

Real-time specific surface area measurements via laser-induced breakdown spectroscopy

From healthcare to cosmetics to environmental science, the specific surface area (SSA) of micro- and mesoporous materials or products can greatly affect their chemical and physical properties. SSA results are also widely used to examine source rocks in conventional and unconventional petroleum resource plays. Despite its importance, current methods to measure SSA are often cumbersome, time-consuming, or require cryogenic consumables (e.g., liquid nitrogen). These methods are not amenable to high-throughput environments, have stringent sample preparation requirements, and are not practical for use in the field. We present a new application of laser-induced breakdown spectroscopy for rapid measurement of SSA. This study evaluates geological samples, specifically organic-rich oil shales, but the approach is expected to be applicable to many other types of materials. The method uses optical emission spectroscopy to examine laser-generated plasma and quantify the amount of argon adsorbed to a sample during an inert gas purge. The technique can accommodate a wide range of sample sizes and geometries and has the potential for field use. These advantages for SSA measurement combined with the simultaneous acquisition of composition information make this a promising new approach for characterizing geologic samples and other materials.

Energy and Fuels↗
USGS2019

Nanoscale molecular fractionation of organic matter within unconventional petroleum source beds

Fractionation of petroleum during migration through sedimentary rock matrices has been observed across lengths of meters to kilometers. Selective adsorption of specific chemical moieties at mineral surfaces and/or the phase behavior of petroleum during pressure changes typically are invoked to explain this behavior. Such phenomena are of interest as they impact both the quality and recoverability of petroleum resources. Given the current emphasis on unconventional (continuous) resources, there is a need to understand petroleum fractionation occurring during expulsion and migration at the nanometer to micron scale, due to the fine-grained nature of petroliferous mudrocks. Here, organic matter compositional differences observed within kukersites (petroleum source beds containing acritarch Gloeocapsomorpha prisca) and the overlying carbonate reservoir layer from the Ordovician Stonewall Formation are explored using a suite of spectroscopic methods, primarily through atomic force microscopy based infrared spectroscopy (AFM-IR). AFM-IR is capable of providing spatial resolutions approaching 50 nm and allows for assessment of the molecular fingerprint of kukersite organic matter across transition zones from organic-rich ‘source’ layers into neighboring carbonate ‘reservoir’ layers ~150 μm away. Results indicate that organic matter composition begins to vary immediately following expulsion from source layers, with loss of carbonyl groups and a concomitant decrease in alkyl chain-length, as migration distance increases. These chemical transitions correlate with a decrease in fluorescence intensity, increase in solid bitumen reflectance, and increase in Raman aromaticity proxies (D-G band separation) in the organic matter. Our findings are consistent with the retention of polar compounds onto mineral grains during expulsion and migration, following primary cracking and bituminization of the Gloeocapsomorpha prisca kerogen.

Energy and Fuels↗
USGS2001

Preservation of methane hydrate at 1 atm

A "pressure-release" method that enables reproducible bulk preservation of pure, porous, methane hydrate at conditions 50 to 75 K above its equilibrium T (193 K) at 1 atm is refined. The amount of hydrate preserved by this method appears to be greatly in excess of that reported in the previous citations, and is likely the result of a mechanism different from ice shielding.

Energy and Fuels↗
USGS2004

Generation of ethylene tracer by noncatalytic pyrolysis of natural gas at elevated pressure

There is a critical need within the pipeline gas industry for an inexpensive and reliable technology to generate an identification tag or tracer that can be added to pipeline gas to identify gas that may escape and improve the deliverability and management of gas in underground storage fields. Ethylene is an ideal tracer, because it does not exist naturally in the pipeline gas, and because its physical properties are similar to the pipeline gas components. A pyrolysis process, known as the Tragen process, has been developed to continuously convert the ???2%-4% ethane component present in pipeline gas into ethylene at common pipeline pressures of 800 psi. In our studies of the Tragen process, pyrolysis without steam addition achieved a maximum ethylene yield of 28%-35% at a temperature range of 700-775 ??C, corresponding to an ethylene concentration of 4600-5800 ppm in the product gas. Coke deposition was determined to occur at a significant rate in the pyrolysis reactor without steam addition. The ?? 13C isotopic analysis of gas components showed a ?? 13C value of ethylene similar to ethane in the pipeline gas, indicating that most of the ethylene was generated from decomposition of the ethane in the raw gas. However, ?? 13C isotopic analysis of the deposited coke showed that coke was primarily produced from methane, rather than from ethane or other heavier hydrocarbons. No coke deposition was observed with the addition of steam at concentrations of > 20% by volume. The dilution with steam also improved the ethylene yield. ?? 2005 American Chemical Society.

Energy and Fuels↗
USGS2006

Geochemical investigation of the potential for mobilizing non-methane hydrocarbons during carbon dioxide storage in deep coal beds

Coal samples of different rank (lignite to anthracite) were extracted in the laboratory with supercritical CO2 (40 ??C; 10 MPa) to evaluate the potential for mobilizing non-methane hydrocarbons during CO2 storage (sequestration) or enhanced coal bed methane recovery from deep (???1-km depth) coal beds. The total measured alkane concentrations mobilized from the coal samples ranged from 3.0 to 64 g tonne-1 of dry coal. The highest alkane concentration was measured in the lignite sample extract; the lowest was measured in the anthracite sample extract. Substantial concentrations of polycyclic aromatic hydrocarbons (PAHs) were also mobilized from these samples: 3.1 - 91 g tonne-1 of dry coal. The greatest amounts of PAHs were mobilized from the high-volatile bituminous coal samples. The distributions of aliphatic and aromatic hydrocarbons mobilized from the coal samples also varied with rank. In general, these variations mimicked the chemical changes that occur with increasing degrees of coalification and thermal maturation. For example, the amount of PAHs mobilized from coal samples paralleled the general trend of bitumen formation with increasing coal rank. The coal samples yielded hydrocarbons during consecutive extractions with supercritical CO2, although the amount of hydrocarbons mobilized declined with each successive extraction. These results demonstrate that the potential for supercritical CO2 to mobilize non-methane hydrocarbons from coal beds, and the effect of coal rank on this process, are important to consider when evaluating deep coal beds for CO2 storage.

Energy and Fuels↗
USGS2010

Abundances of polycyclic aromatic hydrocarbons (PAHs) in 14 chinese and american coals and their relation to coal rank and weathering

The abundances of 16 polycyclic aromatic hydrocarbons (PAHs) on the priority list of the United States Environmental Protection Agency (U.S. EPA) have been determined in 14 Chinese and American coals. The ranks of the samples range from lignite, bituminous coal, anthracite, to natural coke. Soxhlet extraction was conducted on each coal for 48 h. The extract was analyzed on a gas chromatograph-mass spectrometer (GC-MS). The results show that the total PAH content ranged from 0.31 to 57.6 ??g/g of coal (on a dry basis). It varied with coal rank and is highest in the maturity range of bituminous coal rank. High-molecular-weight (HMW) PAHs are predominant in low-rank coals, but low-molecular-weight (LMW) PAHs are predominant in high-rank coals. The low-sulfur coals have a higher PAH content than high-sulfur coals. It may be explained by an increasing connection between disulfide bonds and PAHs in high-sulfur coal. In addition, it leads us to conclude that the PAH content of coals may be related to the depositional environment. ?? 2010 American Chemical Society.

Energy and Fuels↗
USGS2007

Origins of thiadiamondoids and diamondoidthiols in petroleum

Thiadiamondoids and diamondoidthiols are orders of magnitude more abundant in oil altered by thermochemical sulfate reduction (TSR) than they are in nonaltered oil. This suggests that thiadiamondoids and diamondoidthiols form during TSR. In order to prove this hypothesis, we perform laboratory TSR experiments on diverse organic compounds using sodium sulfate as an oxidant in the presence of elemental sulfur and deionized water at 200 and 350 °C for 48 and 96 h under acidic conditions (pH = 4). Our results show that thiadiamondoids and diamondoidthiols can be created from non-sulfur-containing diamondoids by TSR. It seems likely that diamondoid species are organic precursors of thiadiamondoids and diamondoidthiols. In addition, thiocholesterol yields trace quantities of dimethyl-2-thiaadamantanes when heated with montmorillonite at 200 °C, suggesting that these diamondoid derivatives may partly originate by molecular rearrangement of polycyclic sulfides and thiols in the presence of acidic clay minerals since they also exist in crude oil that has not undergone TSR. The present study of these heteroatomic cage compounds improves understanding of TSR and can be used to reduce risk in petroleum exploration.

Energy and Fuels↗
USGS2008

Meso- and micropore characteristics of coal lithotypes: Implications for CO2 adsorption

Lithotypes (vitrain, clarain, and fusain) of high volatile bituminous Pennsylvanian coals (Ro of 0.56-0.62%) from Indiana (the Illinois Basin) have been studied with regard to meso- and micropore characteristics using low-pressure nitrogen and carbon dioxide adsorption techniques, respectively. High-pressure CO2 adsorption isotherms were obtained from lithotypes of the Lower Block Coal Member (the Brazil Formation) and the Springfield Coal Member (the Petersburg Formation), and after evacuation of CO2, the lithotypes were re-analyzed for meso- and micropore characteristics to investigate changes related to high-pressure CO2 adsorption. Coal lithotypes have differing Brunauer-Emmett-Teller (BET) surface areas and mesopore volumes, with significantly lower values in fusains than in vitrains or clarains. Fusains have very limited pore volume in the pore size width of 4-10 nm, and the volume, increases with an increase in pore size, in contrast to vitrain, for which a 4-10 nm range is the dominant pore'Wlidth. For clarain, both pores of 4-10 nm and pores larger than 20 nm contribute substantially to the mesoporosity. Micropore surface areas are the smallest for fusain (from 72.8 to 98.2 m2/g), largest for vitrain (from 125.0 to,158.4 m2 /g), and intermediate for clarain (from 110.5 to 124.4 m2/g). Similar relationships are noted for micropore volumes, and the lower values of these parameters in fusains are related to smaller volumes of all incremental micropore sizes. In the Springfield and the Lower Block Coal Members, among lithotypes studied, fusain has the lowest adsorption capacity. For the Lower Block, vitrain has significantly higher adsorption capacity than fusain and clarain, whereas for the Springfield, vitrain and clarain have comparable but still significantly higher adsorption capacities than fusain. The Lower Block vitrain and fusain have much higher adsorption capacities than those in the Springfield, whereas the clarains of the two coals are comparable. After exposure of coal to CO2 at high pressure, vitrains experienced the largest porosity changes among all lithotypes studied. These changes are dominantly manifested in the mesoporosity (decrease in mesopore volume) range; whereas little to no change occurred in the micropore size range. In other lithotypes (clarains, the dominant lithology in the coals studied, and sporadic fusains), the changes were minimal. ?? 2008 American Chemical Society.

Energy and Fuels↗
USGS2010

Methane hydrate synthesis from ice: Influence of pressurization and ethanol on optimizing formation rates and hydrate yield

Polycrystalline methane gas hydrate (MGH) was synthesized using an ice-seeding method to investigate the influence of pressurization and ethanol on the hydrate formation rate and gas yield of the resulting samples. When the reactor is pressurized with CH 4 gas without external heating, methane hydrate can be formed from ice grains with yields up to 25% under otherwise static conditions. The rapid temperature rise caused by pressurization partially melts the granular ice, which reacts with methane to form hydrate rinds around the ice grains. The heat generated by the exothermic reaction of methane hydrate formation buffers the sample temperature near the melting point of ice for enough time to allow for continuous hydrate growth at high rates. Surprisingly, faster rates and higher yields of methane hydrate were found in runs with lower initial temperatures, slower rates of pressurization, higher porosity of the granular ice samples, or mixtures with sediments. The addition of ethanol also dramatically enhanced the formation of polycrystalline MGH. This study demonstrates that polycrystalline MGH with varied physical properties suitable for different laboratory tests can be manufactured by controlling synthesis procedures or parameters. Subsequent dissociation experiments using a gas collection apparatus and flowmeter confirmed high methane saturation (CH 4 · 2 O, with n = 5.82 ± 0.03) in the MGH. Dissociation rates of the various samples synthesized at diverse conditions may be fitted to different rate laws, including zero and first order.

Energy and Fuels↗
USGS1997

Unified mechanism of alkali and alkaline earth catalyzed gasification reactions of carbon by CO2 and H2O

From molecular orbital calculations, a unified mechanism is proposed for the gasification reactions of graphite by CO 2 and H 2 O, both uncatalyzed and catalyzed by alkali and alkaline earth catalysts. In this mechanism, there are two types of oxygen intermediates that are bonded to the active edge carbon atoms: an in-plane semiquinone type, C f (O), and an off-plane oxygen bonded to two saturated carbon atoms that are adjacent to the semiquinone species, C(O)C f (O). The rate-limiting step is the decomposition of these intermediates by breaking the C−C bonds that are connected to C f (O). A new rate equation is derived for the uncatalyzed reactions, and that for the catalyzed reactions is readily available from the proposed mechanism. The proposed mechanism can account for several unresolved experimental observations: TPD and TK (transient kinetics) desorption results of the catalyzed systems, the similar activation energies for the uncatalyzed and catalyzed reactions, and the relative activities of the alkali and alkaline earth elements. The net charge of the edge carbon active site is substantially changed by gaining electron density from the alkali or alkaline earth element (by forming C−O−M, where M stands for metal). The relative catalytic activities of these elements can be correlated with their abilities of donating electrons and changing the net charge of the edge carbon atom. As shown previously (Chen, S. G.; Yang, R. T. J . Catal . 1993 , 141 , 102), only clusters of the alkali compounds are active. This derives from the ability of the clusters to dissociate CO 2 and H 2 O to form O atoms and the mobility of the dissociated O atoms facilitated by the clusters.

Energy and Fuels↗
USGS1997

Mechanism of SO2 removal by carbon

The reaction of SO 2 with carbon (C) in the presence of O 2 and H 2 O involves a series of reactions that leads to the formation of sulfuric acid as the final product. The rate-determining step in the overall process is the oxidation of SO 2 to SO 3 . Three SO 2 oxidation reactions are possible. Adsorbed SO 2 (C−SO 2 ) can react either with gas phase O 2 or with adsorbed oxygen (C−O complex) to form sulfur trioxide (SO 3 ), or gas phase SO 2 can react directly with the C−O complex. In optimizing the SO 2 removal capabilities of carbon, most studies only assume a given mechanism for SO 2 adsorption and conversion to H 2 SO 4 to be operable. The appropriate SO 2 oxidation step and role of the C−O complex in this mechanism remain to be determined. The ultimate goal of this study was to prepare activated char from Illinois coal with optimal properties for low-temperature (80−150°C) removal of sulfur dioxide from coal combustion flue gas. The SO 2 adsorption capacity of activated char was found to be inversely proportional to the amount of oxygen adsorbed on its surface. A temperature-programmed desorption technique was developed to titrate those sites responsible for adsorption of SO 2 and conversion to H 2 SO 4 . On the basis of these results, a mechanism for SO 2 removal by carbon was proposed. The derived rate expression showed SO 2 adsorption to be dependent only on the fundamental rate constant and concentration of carbon atoms designated as free sites. Recent studies indicate a similar relationship exists between the rate of carbon gasification (in CO 2 or H 2 O) and the number of reactive sites as determined by transient kinetics experiments. Utilizing the concept of active or free sites, it was possible to produce a char from Illinois coal having an SO 2 adsorption capacity surpassing that of a commercial catalytic activated carbon.

Energy and Fuels↗