Environmental data from bench-scale pressurized fluidized-bed hydroretorting of Eastern oil shales

As part of a three year programme to develop the pressurized fluidized-bed hydroretorting (PFH) process for Eastern oil shales, tests were conducted in laboratory-scale batch and continuous units as well as a bench-scale unit (45 kg h⁻¹) to generate a data base for six Eastern shales. Data were collected during PFH processing of raw Alabama and Indiana shales and a beneficiated Indiana shale for environmental mitigation analyses. The data generated include trace element analyses of the raw feeds and spent shales, product oils and sour waters. The sulphur compounds present in the product gas and trace components in the sour water were also determined. In addition, the leaching characteristics of the feed and residue solids were determined. The data obtained were used to evaluate the environmental impact of a shale processing plant based on the PFH process. This paper presents the environmental data obtained from bench-scale tests conducted during the programme.     

Pyrolysis behaviour of Australian oil shales in a fluidized bed reactor and in a material balance modified Fischer assay retort

The pyrolysis behaviour of several Australian oil shales was determined using the material balance modified Fischer assay and a bench-scale fluidized bed pyrolysis reactor, with nitrogen or steam as the sweep gas. The assay oil yield, which ranged from 5.3 to 15.7 wt% of the dry shale, did not correlate well with the organic carbon contents of the shales. However, under both assay and fluidized bed pyrolysis conditions, a shale of high kerogen H/C had high organic carbon conversions to oil. Compared with the Fischer assay, nitrogen pyrolysis gave 7 ± 4 wt% more oil for the shales studied, and steam pyrolysis gave 15 ± 4 wt% more oil for all shales except one, which showed a 35 wt% increase in oil yield. However, the oils from both nitrogen and steam pyrolysis had lower H/Cs, higher sulphur and nitrogen contents, and more high boiling point fractions than those from the Fischer assay. Nitrogen pyrolysis oils were of higher quality than those produced by steam pyrolysis. With steam as the sweep gas, much more hydrogen and hydrogen sulphide were produced for all shales; in most cases, there was also more carbon monoxide and less hydrocarbon gases.     

Chattanooga Shale—An Important U. S. Mineral Resource

Abstract

Chattanooga shale, a major component of the eastern Devonian shales, covers a wide area from lower Kentucky through Tennessee and into northern Alabama. It contains sizable resources of oil and several critically needed metals. Leaching experiments with sulfuric acid have demonstrated that excellent trace metal solubilization can be obtained from hydroretorted Chattanooga shale, i.e. the solid residue remaining after the raw shale has been processed to produce oil and/or gas.     

Correlations describing the pressurized fluidized-bed hydroretorting carbon conversions of six Eastern oil shales

A set of correlations has been developed to describe the pressurized fluidized-bed hydroretorting (PFH) carbon conversions of six Eastern oil shales. Laboratory-scale fluidized-bed and thermogravimetric data were used to relate hydroretorting conditions and organic carbon conversions to oil, gas and residue. Conversions have been found to depend on temperature, hydrogen pressure and residence time over the ranges studied of 750–865 K, 0–7 MPa H₂ and 0–30 min, respectively. Gas yield increases with increasing temperature but is independent of changes in hydrogen pressure. Oil yield increases with increasing hydrogen pressure and has different relationships to temperature for the various shales. A single mechanism has been used to describe the carbon conversions of Alabama and Tennessee Chattanooga, Indiana and Kentucky New Albany, Michigan Antrim and Ohio Cleveland shales under PFH conditions. The mechanism includes the simultaneous conversion of carbon to gas, oil and active carbon species which can form oil or remain as residue carbon. Yields are predicted over the temperature, hydrogen pressure and resistance time ranges used in PFH processing.     

Hydrogen retorting of oil shales from Eastern Canada

The liquid production potential of thirty oil shale samples from Eastern Canada was determined by Fischer assay retort and pyrochem retort. For all shales, the presence of hydrogen during pyrochem retorting resulted in a significant increase in oil yields compared to Fischer assay yields. Ten oil shale samples were selected for detailed evaluation in the pyrochem retort in the presence of nitrogen and hydrogen. Besides increasing yields, the presence of hydrogen lowered the specific gravity of liquid products and the content of sulphur but increased the content of nitrogen. This was attributed to the stabilization of precursors to nitrogen compounds which prevented their polymerization.     

A common relation for correlating pyrolysis yields of coals and oil shales

Pyrolysis yields for both coals and oil shales exhibit a common relation between the original aromatic carbon content of the sample and the residual organic carbon after pyrolysis. Corresponding measurements of organic carbon distribution by solid-state ¹³C n.m.r. and pyrolysis yields by Fischer assay or proximate analysis have been correlated for 125 coal and oil shale samples composed of widely differing types of organic matter and inorganic constituents. Even though these measurements have been accumulated from various laboratories using different instrumentation and interpretative procedures, there is a remarkably high degree of correlation between original aromatic carbon and residue carbon. The common relation between pyrolysis yield and organic carbon distribution generally supports the previous notion that aromatic carbon is resistant to volatilization and extends this same characterization of pyrolysis behaviour to oil shale kerogen as well as coal.     

Gas evolution during pyrolysis of various Colorado oil shales

Rates of evolution of C0₂, CO, H₂, CH₄ and the C₂ and C₃ hydrocarbons during the pyrolysis of seven Colorado oil shales have been measured. These shales, which are from various depths at two different sites, yield 34–255 ¦ of oil per tonne raw shale (9–61 US gal of oil per short ton raw shale) and linear heating at a rate of 2°C min⁻¹ was used for the retorting of all samples. The objective of the study is to monitor variations in gas evolution from shales of different organic content and from various stratigraphic and areal locations. Comparisons between shales from each site are made together with correlations with data from Fischer assays. A kerogen concentrate (mineral fraction removed by HCl-HF treatment) and retorted shale from a Fischer assay are also included. The ability of a kinetic model due to Campbell et al. to predict gas evolution is tested and it is found necessary to modify slightly some of the stoichiometric coefficients to obtain good agreement. The resultant kinetic model should adequately describe the gas and oil evolution behaviour of shale from the upper portion of the Green River formation.     

Use of Fourier Transform infrared spectroscopy for determining oil shale properties

Fourier Transform infrared analysis has been examined as a technique for evaluating the oil-yielding potential of raw oil shales. The technique was developed recently for analysing coals, and gives a quantitative measure of aliphatic, aromatic and hydroxyl hydrogen. From these measurements, it was verified that an approximate rectilinear relation exists between the oil yield of an oil shale as determined by Fischer assay and the aliphatic hydrogen concentration in the shale. An equivalent relation was established previously between the oil yield and the aliphatic carbon concentration as determined by ¹³C cross polarization n.m.r. When the oil yield is expressed in weight per cent, it is seen that the yield is only slightly less than the weight per cent of aliphatic hydrocarbons. This suggests that, under the conditions of the Fischer assay, there is almost complete conversion of the aliphatic components to oil.     

Comments on the Modified Fischer Assay of Eastern oil shales of Kentucky

The Modified Fischer Assay is the accepted method for evaluating the potential liquid fuel yield of an oil shale. For a given shale, percent of Fischer Assay oil yield has become the standard used for judging technologies. The method has been developed for and is well understood when applied to oil shales in the western United States. However, the assay can be successfully applied to eastern United States oil shales only if care is taken in several areas that prove less important for its successful application to western shales. In particular, standardized sample preparation and handling with minimum air exposure of pulverized shale is required; a well-controlled and reproducible heating profile during retorting must be employed; and consistently effective liquid product collection must be accomplished. These considerations have a major influence on assay accuracy. Only with care in these areas, can Modified Fischer Assays suitable for eastern shale resource evaluations and technology comparisons be obtained.     

Determination of shale oil yields by petrographic analysis

Rundle-type oil shales from five Australian deposits (Rundle, Stuart, Condor, Byfield and Duaringa) contain abundant lamellar alginite that is easily recognized using fluorescence microscopy. Shale oil yield, as determined by modified Fischer assay, is directly related to the volume per cent of alginite in the parent shales for each of the above deposits. Data provided show that interdeposit estimates of shale oil yield, based on alginite content, are more reliable than estimates based on specific gravity of the parent shales. Application of petrographic techniques should provide rapid assessment of the shale oil yield for other deposits with Rundle-type oil shale. The method requires initial calibration of alginite content, in a limited number of samples, with Fischer assays.     

A modified Gray-King assay method for small oil shale samples

A precise method for the assay of oil shales requiring only 10 g of shale per assay has been developed by modifying the Gray-King technique for the carbonization assay of coals. The precision of the method is illustrated by results obtained for a Queensland (Julia Creek) oil shale. Twelve sub-samples were assayed at 520 °C to give a mean oil yield of 6.77% with a standard deviation of 0.09%. At 500 °C the mean oil yield was 6.73% and the standard deviation 0.10%. Repetitive assays by the Fischer method yielded a mean oil value of 5.71% with a standard deviation of 0.06%. Significant departures from the Gray-King method include the use of an inert carrier gas to remove the pyrolysis products as they are formed, a more efficient condensate trapping system and an accurate method of measuring the water content. Separation of the water from the oil is the most critical part of the assay. Repeatable results can be obtained when boiling times are extended and the water retained on the condenser walls is collected. Assays can be conducted on the same-sized samples as used for chemical analysis, so that correlations can be attempted with greater confidence.     

Secondary coking and cracking of shale oil vapours from pyrolysis or hydropyrolysis of a Kentucky Cleveland oil shale in a two-stage reactor

It is widely recognized that secondary reactions which are mainly associated with minerals during oil shale retorting have a marked influence on the product yields and compositions. To understand these phenomena more clearly, the secondary reactions of shale oil vapours from the pyrolysis (or hydropyrolysis) of Kentucky Cleveland oil shale were examined in a two-stage, fixed-bed reactor in flowing nitrogen or hydrogen at pressures of 0.1–15 MPa. The vapours from pyrolysis (first stage) were passed through a second stage containing combusted shale, upgrading catalyst or neither. Carbon conversion to volatile products in the first stage increased from 49% during thermal pyrolysis to 81% at 15 MPa H₂ partial pressure. During thermal pyrolysis, total pressure had only a slight effect on carbon removal from the raw shale and subsequent deposition on to the porous solids in the second stage. Carbon deposition on to the combusted shale in the second stage was reduced to zero at 15 MPa H₂ partial pressure. The n-alkane distributions of the oils as determined by gas chromatography clearly demonstrated that higher hydrogen pressure, contact with combusted shale, or both contributed to lower-molecular-weight products.     

Correlation between electron spin resonance spectra and oil yield in eastern oil shales

Organic free radical spin concentrations were measured in 60 raw oil shale samples from north Alabama and south Tennessee and compared with Fischer assays and uranium concentrations. No correlation was found between spin concentration and oil yield for the complete set of samples. However, for a 13 sample set taken from a single core hole, a linear correlation was obtained. No correlation between spin concentration and uranium concentration was found.     

Fluidized bed steam retorting of Kentucky oil shale

A three-inch (7.6-cm) diameter fluidized bed reactor has been used at the Kentucky Center for Energy Research Laboratory (KCERL), operated by the Institute for Mining and Minerals Research (IMMR), to investigate the fluidized bed retorting characteristics of Kentucky oil shales. Because steam has been indicated to be a reactive pyrolysis gas for both Eastern and Western U.S. oil shales by many, a main objective of the fluidized bed investigation was to determine the effects of steam as a fluidizing medium. This was accomplished by comparing the yields and compositions of the products from steam and N₂ retorting under otherwise equivalent fluidized bed conditions. Oil yields obtained from steam fluidization were approximately 2% greater than oil yields obtained from N₂ retorting. Steam retorting released significantly more pyritic sulfur from the shale, providing evidence that reduced hydrogen scavenging from the kerogen for H₂S production was a possible mechanism for the increased oil production. Steam fluidization resulted in increased oil collection efficiency, and represented the most significant difference between the steam and nitrogen systems. Liquid product quality was similar for both steam and N₂ fluidization and the oils were more aromatic, more viscous, higher in density, higher in nitrogen content, and lower in volatility than Fischer Assay oil derived from the same shale.     

Effect of lignite addition and steam on the pyrolysis of Turkish oil shales

Steam was found to be a more effective sweep gas than nitrogen at low velocities in fixed-bed pyrolysis of Goynuk oil shale but, at higher velocities and in fluidized-bed pyrolysis, the differences were considerably less marked. Relatively small but significant synergistic effects were observed between lignites and the two oil shales investigated — Goynuk and Seyitomer — under static retorting conditions. These effects were more pronounced with large concentrations of oil shales but disappeared in fluidized-bed pyrolysis, where conversions are considerably higher because mass transfer limitations largely disappear.     

N.m.r. study of US Eastern and Western shale oils produced by pyrolysis and hydropyrolysis

Shale oils produced from US Eastern and Western oil shales by pyrolysis and hydropyrolysis processes have been investigated by both ¹H and ¹³C high-resolution n.m.r. techniques. Eastern shale oils produced by hydropyrolysis, and subsequently hydrotreated, were also included. From the n.m.r. data of the shale oils, the average molecular structure parameters were calculated. These parameters quantitatively represent the differences observed in the n.m.r. spectra of the various shale oils because of changes in the chemical composition. Mol percentages of aromatics, olefins, and alkanes were also determined for the shale oils, and show that the composition of the shale oil is dependent upon the geographic origin of the oil shale, the pyrolysis method, and the hydrogenation process. In addition to the study of shale oils, solid-state ¹³C n.m.r. spectra of Eastern and Western oil shales before and after pyrolysis and hydropyrolysis were obtained. The spectral data show that the carbon aromaticities for the Eastern oil shales and shale oils are higher than for the Western oil shale and shale oils. The data also show that hydropyrolysis relative to pyrolysis reduces the amount of residual organic carbon remaining on the spent shales. Carbon aromaticity data for both oil shale and shale oil suggest that the organic moieties present in kerogen may be retained in the shale oils to a greater extent after hydropyrolysis than after pyrolysis.     

Development of FT-i.r. procedures for the characterization of oil shale

A characterization of oil shale from the Mahogany Zone of the Green River Formation has been obtained by FT-i.r. A quantitative analysis of the mineral component by FT-i.r. spectroscopy is shown to be comparable to that obtained by X-ray diffraction when considering broad mineral types, i.e., carbonates. Methods for FT-i.r. analysis of the organic component, both from the whole shale and from kerogen specimens, have been refined. There is a good correlation between the intensity of alkyl bands and Fischer assay yields. An assessment is made of the applicability of extinction coefficients obtained from paraffins to their use in quantitative analysis of oil shales.     

Mineral and trace element composition of the Lokpanta oil shales in the Lower Benue Trough, Nigeria

The concentrations of minerals and trace elements in the Lokpanta oil shale from the Lower Benue Trough, Nigeria have been determined by X-ray diffraction (XRD) and laser ablation-inductively coupled plasma-mass spectrometry (LA-ICP-MS), respectively. X-ray diffraction data were evaluated using the SIROQUANT™ interactive data processing system based on Rietveld interpretation methods. A new method of trace element determination in oil shale, involving LA-ICP-MS analysis of glass beads prepared by fusing oil shale ash on an iridium strip heater was used, and the accuracy of the method was assessed by including a standard shale reference material (SGR-1b) in the analysis program.The minerals in the raw oil shales are mainly quartz, calcite and clay minerals, with the latter being represented by kaolinite and interstratified illite/smectite. Ashes of the oil shale samples prepared at 815 °C have quartz and (in some cases) illite as the dominant mineral phases, along with a significant proportion of amorphous materials. The Lokpanta oil shales are highly enriched in some potentially hazardous trace elements, including V, Cr and Ni, when compared with oil shales from other deposits around the world. The results obtained for the trace elements in the reference material show that the LA-ICP-MS method described in this study is very accurate and precise for the determination of a wide range of trace elements in oil shales.     

Organic geochemistry of the British Kimmeridge clay: 2. Acyclic isoprenoid alkanes in Kimmeridge shale oils

The C15---C20 isoprenoid alkane composition of Kimmeridge Clay shale oils produced by Fischer assay has been examined, and compared with the isoprenoid composition of corresponding bitumens. C16 and C18 isoprenoid alkanes are generally dominant in shale oils, while pristane (C19) and phytane (C20) dominate in bitumens. A significant proportion of the phytane in many shale oils is derived from simple evaporation of free (bitumen) phytane, while free pristane contributes less to shale oil composition. Some shale oil phytane and a large proportion of pristane is kerogen-derived. Certain shale oils contain lower concentrations of isoprenoid alkanes than corresponding bitumens, suggesting that some free alkane is thermally degraded during pyrolysis. Results thus indicate three sources for shale oil isoprenoid alkanes: thermal evaporation of free alkanes (particularly for phytane), kerogen decomposition, and possibly the cracking of higher homologues for C15---C19 alkanes. Kerogen-derived isoprenoids are suggested to arise by thermal desorption of adsorbed free alkane (particularly for phytane) and from C---O and C---C bonded species (excluding phytane) via postulated clay catalysed hydrogenation of initially formed alkenes. Comparison of shale oil and bitumen pristane/phytane ratios allows groups of oil shales to be defined, dependent on source composition, organic carbon content and maturity. Shale oil pristane/phytane ratios can also help to determine depositional environments and source composition, although maturity, shale mineralogy and competing alkene-forming pyrolytic reactions may also affect the ratios.