Academic literature on the topic 'Surat Basin'

The stratigraphy of the Surat Basin, Queensland, has historically been sub-divided by formation and unit nomenclature with a few attempts by other authors to apply sequence stratigraphy to existing formation boundaries. At a local- to field-scale, lithostratigraphy may be able to represent stratigraphy well, but at regional-scale, lithostratigraphic units are likely to be diachronous. To date, this lithology-driven framework does not accurately reflect time relationships in the sub-surface. An entirely new integrated methodological approach, involving well tied seismic data and sequence stratigraphic well-to-well correlations compared with published zircon age dates, has been applied to hundreds of deep wells and shallower coal seam gas wells. This method sub-divides the Surat Basin stratigraphy into defendable 2nd order to 3rd order sequence stratigraphic cycles and has required the use of an alpha-numeric sequence stratigraphic nomenclature to adequately and systematically label potential time equivalent surfaces basin-wide. Correlation of wells is the first step in building models of aquifers and coal seam gas fields for numerical simulation of fluid flow, which is necessary for responsible resource management. Lithostratigraphic correlations will overestimate the extent and hydraulic connectedness of the strata of interest. The result may be fluid flow models that do not represent a realistic pressure footprint of the flow. The present sequence stratigraphic method more accurately reflects the disconnectedness of sub-surface coals and sandstones (aquifers) on a field-to-field scale, adjacent field-scale, and basin-wide scale. It forms the basis for improved and more representative modelling of the sub-surface.

The Surat Basin portion of the Great Artesian Basin (GAB) in Queensland has long been known to contain natural gas from both conventional and CSG sources. Commercial gas extraction from conventional sources target the Evergreen and Precipice Formations, which are among the lowermost of the Surat Basin stratigraphic units; however, evidence exists of methane occurrences in waterbores, which in most cases, access aquifers much shallower than recognised conventional gas or CSG targets. Large-scale development of CSG in the Surat and southern Bowen basins has highlighted the presence of gas in aquifers overlying and underlying the coal measures. Potential issues associated with gas in waterbores include health and safety risks, and the difficulty of establishing baseline groundwater bore conditions against which potential CSG impacts can be compared. Australia Pacific LNG has been investigating the presence of gas in the aquifers across the basin. The program has involved the routine measurement of wellhead gas concentrations and analysis of dissolved gas in waterbores. Stable isotope analysis of the dissolved methane (δ13C-methane and δD-methane) has been undertaken to ‘fingerprint’ aquifer gasses to ascertain their provenance. More recently, δ13C-CO2 has been added to the suite of isotopes. Initial results confirm the presence of natural methane across the study area and in all of the GAB aquifers sampled. Isotopic analysis indicates a distinct difference in isotopic signatures between the methane from the coal measures and that of the overlying aquifers from which most groundwater is extracted.

Extensive drilling of the Walloon Subgroup for coal seam gas (CSG) during the last decade has revealed a world-class CSG play on the northern flank of the Surat Basin. Resources discovered in the Walloon Subgroup exceed 30 TCF; this gas now underpins four CSG-to-liquefied natural gas (LNG) projects. Results to date have revealed the highly heterogeneous nature of the Walloon Subgroup and its associated coal properties. The Walloon Subgroup is typically 350 m thick and contains an average of 30 m of net coal that is interbedded with a range of clay-rich, fluvio-lacustrine lithologies. The most prospective area of the play occurs down-dip and adjacent to the Walloon subcrop edge, where high permeability exists combined with a thick section of net pay. Coals in the Walloon Subgroup are low rank (0.35–0.65% Ro) with gas contents ranging between 1–15 m3/tonne (dry ash-free). Average coal ply thickness is 30 cm, making correlation and prediction of reservoir properties difficult. Reservoir properties—including permeability, gas content and saturation—differ as a result of compositional variability of the coal seams and also the tectonic history. Mapping of sparse 2D seismic data has highlighted the distribution of major structural features throughout the basin. Coal fracture permeability ranges from less than 0.1 mD to more than 2,000 mD, and mapping has identified areas where permeability appears to be enhanced on structures that have undergone mid Cretaceous–Eocene deformation.

The Hutton-Wallumbilla (HWF), Merivale (MF), Kia Ora, and Injune faults are the major structures in the western Surat Basin, deforming Palaeozoic to Jurassic rock units. The authors present results from the interpretation of gridded gravity data and open-file seismic reflection data, which provide constraints on the geometry and kinematics of these faults. The interpretation of gravity data indicates that the HWF and MF are expressed by sharp lineaments in moderate to high-amplitude anomalies, indicating a deep-seated nature of the faults. The interpretation of seismic lines shows that the HWF and MF are northeast-dipping and east-dipping reverse blind faults, respectively. Some other faults also displaced and folded the rock units of the Bowen and Surat basins, such as the Kia Ora and Injune faults. The MF, Kia Ora, and the northern part of the HWF acted as normal faults during the early Permian and then have been inverted during the Late Permian–Triassic Hunter-Bowen Orogeny phases, especially during the early Late Triassic. The largest fault throws in the Bowen Basin successions are observed along the southern part of the HWF and its central splay, which are around 350 m and 480 m, respectively. The stratigraphic units of the Surat Basin above it have gently been folded over the major blind faults. The largest amount of shortening in the Surat Basin has taken place over the southern part of the HWF by 0.5%. The basement depth played an important role in the amount of contractional deformation in the Bowen and Surat basins. Where the basement is shallow, the amount of deformation along the faults in both the Bowen and Surat basins is higher.

The three-dimensional thermal maturity pattern has been investigated and the hydrocarbon generation potential assessed for the Permian and Triassic sequences of the southern Bowen and northern Gunnedah Basins and the lower part of the overlying Jurassic Cretaceous Surat Basin sequence in northern New South Wales. An oil-source rock correlation also has been investigated in the Gunnedah Basin. Vitrinite reflectance measurements were conducted on 256 samples from 28 boreholes. A total of 50 of these samples were subjected to Rock-Eval pyrolysis analysis, and 28 samples extracted for additional organic geochemical studies (GCMS). A re-evaluation of the stratigraphy in the southern Bowen Basin and a stratigraphic correlation between that area and the northern Gunnedah Basin was also included in the study. An overpressured shaly interval has been identified as a marker bed within the lower parts of the Triassic Moolayember and Napperby Formations, in the Bowen and Gunnedah Basins respectively. Suppressed vitrinite reflectance in the Permian sequence was used as another marker for mapping the stratigraphic sequence in the southern Bowen Basin. The Permian sequence in the Bowen Basin thins to the south, and probably pinches out over the Moree High and also to the west. The coal-bearing Kianga Formation is present in the north and northeastern parts of the study area. A disconformity surface between Digby and Napperby Formations in the Gunnedah Basin is probably time-equivalent to deposition of the Clematis Group and Showgrounds Sandstone in the Bowen Basin. The Clematis Group is absent in the study area, and the Moolayember Formation considered equivalent to the Napperby Formation. Although in many cases core samples were not available, handpicking of coal or shaly materials from cuttings samples where geophysical log signatures identify these materials helped in reducing contamination from caved debris. Histogram plots of reflectance also helped where the target and caved debris were of similar lithology. Vertical profiles of the vitrinite reflectance identified suppressed intervals in the study area due to marine influence (Back Creek Group and Maules Creek Formation) and liptinite rich source organic matter (Goonbri Formation). The suppression occurs due to the perhydrous character of the preserved organic matter. High reflectance values were noted within intrusion-affected intervals, and two types of igneous intrusion profiles were identified; these are simple and complex profiles. An isoreflectance map for the non-suppressed interval at the base of the Triassic sequence in the southern Bowen Basin shows that the organic matter is mature more towards the east close to the Goondiwindi Fault, and also towards the west where the Triassic sequence directly overlies the basement. High values also occur over the Gil Gil Ridge in the middle, to the south over the Moree High, and to the north where the sequence is thicker. The reflectance gradient in the suppressed intervals is higher than in the overlying non-suppressed sequences, especially when the rank has resulted from burial depth. Tmax from Rock-Eval pyrolysis was found to be lower in the perhydrous intervals, and was high in mature and igneous intrusion-affected intervals. Based on the source potential parameters, the Permian Back Creek Group is a better source than the Kianga Formation, while the Goonbri Formation is better than the Maules Creek Formation. The Triassic Napperby Formation has a fair capacity to generate oil, and is considered a better source rock than the equivalent Moolayember Formation. The Jurassic Walloon Coal Measures is a better source than Evergreen Formation, and has the best source rock characteristics, but is immature. The Rock-Eval S1 value shows better correlation with extracted hydrocarbon compounds (saturated and aromatics) than the total extractable organic matter. This suggests that solvent extraction has a greater ability to extract NSO compounds than temperature distillation over the Rock-Eval S1 interval. Terrestrial organic matter is the main source input for the sequences studied. This has been identified from organic petrology and from the n-alkane distributions and the relatively high C29 steranes and low sterane/hopane ratios. The absence of marine biomarker signatures in the Permian marine influenced sequence, could be attributed to their dilution by overwhelming amounts of non-marine organic matter. A mainly oxic to suboxic depositional environment is inferred from trace amounts of 25-NH, BNH and TNH. This is further supported by relatively high pr/ph ratios. Although C29/C30 is generally regarded as an environmental indicator, high values were noted in intrusion-affected samples. The 22S and 20S ratios were inverted ????reaches pseudo-equilibrium???? in such rapidly heated, high maturity samples. The ratio of C24 tetracyclic terpane to C21-C26 tricyclic terpanes decreases, instead of increasing, within the Napperby Formation close to a major igneous intrusive body. The 22S ratio, which is faster in reaction than the other terpane and sterane maturity parameters, shows that the Permian sequence lies within the oil generation stage in the Bowen Basin, except for a Kianga Formation sample. The Triassic sequence is marginally mature, and the Jurassic sequence is considered immature. In the Gunnedah Basin, the Permian sequence in Bellata-1 and Bohena-1, and the Triassic sequence in Coonarah-1A, lie within the oil generation range. In the intrusion-affected high maturity samples, the ratio is reaches pseudo-equilibrium. This and other terpane and sterane maturity parameters are not lowered (suppressed) in the perhydrous intervals. The ???????? sterane ratio, however, is slowest in reaction to maturity, and variations in low maturity samples are mainly due to facies changes. Diasterane/sterane ratios, in the current study, increase with increasing TOC content up to 5% TOC, but decrease in rocks with higher TOC contents including coals. Highly mature samples, as expected, in both cases are anomalous with high ratios. Calculated vitrinite reflectance based on the method of Radke and Welte (1983), as well as MPI 1 and MPI 2, shows the best comparison to observed values. These aromatic maturity parameters are lowered within the reflectance-suppressed intervals. Oil stains in the Jurassic Pilliga Sandstone in the Bellata-1 well have been identified as being indigenous and not due to contamination. The vitrinite reflectance calculated to the oil stain suggests that the source rock should be within a late mature zone. Such high maturity levels are only recognised within intrusion-affected intervals. A close similarity between the oil stain sample and the intruded interval of the Napperby Formation is evident from the thermal maturity and biomarker content. Hydrocarbon generation and expulsion from the lower part of the Napperby Formation as a result of igneous intrusion effects is suggested as the source of the oil in this particular occurrence. Terpane and sterane maturity parameters increase with increasing burial depth in the intervals with suppressed (perhydrous) vitrinite reflectance. The generation maturity parameters also increase through intervals with perhydrous vitrinite, which suggests that hydrocarbons continue to be generated and the actual amount is increasing even though traditional rank ????????????stress???????????? maturity parameters are lowered. Accordingly, the Permian sequences in the lower part of the Bowen Basin are at least within the peak oil generation zone, and probably within late oil generation in the north and northeast of the study area. To generate significant amounts of hydrocarbon, however, the thickness of the shaly and coaly intervals in the Permian sequence is probably a critical parameter. In the Gunnedah Basin, a significant amount of hydrocarbon generation is probably only possible as a result of igneous intrusions.

The coal seam gas industry is booming in Queensland, however extraction of the gas is accompanied by water containing several salts. To facilitate beneficial water reuse for applications such as crop irrigation, treatment methods are required. However, one challenge is the variability of water quality produced and thus this project was directed at: understanding the composition of 150 water samples from an operating gas field; determining correlations between components; suggesting appropriate remediation methods. This research revealed the diversity of water compositions, informed management procedures by developing improved correlations between dissolved species and predicted the performance of reverse osmosis for desalination.

This project addressed potential connection between aquifers in an area where groundwater extraction for both agriculture and coal seam gas occur. The analysis of water chemistry and isotopes, and new mathematical techniques were employed. Overall, there was no evidence of significant solute or gas transfer between aquifers. Methane gas was found to be generated within all aquifers via microbial activity. As a result, stable and radioactive isotopes results are complex. In contrast, hydrochemistry, and the analysis of very low concentrations of the lithium ion and its stable isotopes were found to be effective indicators of coal-seam gas bearing groundwater.

This study characterises the root causes for fines generation in coal seam gas wells in the Walloons Subgroup of the Surat Basin, southeast Queensland, Eastern Australia. Fines production can be critical in causing erosion in downhole pumping equipment and disruption to surface facilities. The Surat Basin has, in places, exceptional coal permeabilities (>1 Darcy), and most high permeability wells are completed with pre-perforated liners. Fines that are captured in separators are usually generated from the interburden lithologies, not from coals (reservoir rocks). Fines production characterisation and mitigation generically requires identification of the processes that lead to breakdown of cohesion in rocks that generate fines. Conventionally, fines production is dealt with using a geomechanical approach to understand the interaction of rock strength and in situ stresses in the context of reservoir production conditions. Significant factors that may control fines production are in-situ stresses, rock strength, drawdown and depletion as well as completion type and geometry. Geomechanical models were developed from log based, strain derived stress models, which are calibrated to rock strength testing of the core samples. Interestingly, fines production remains prevalent in areas with low differential stress and little variability in other parameters, such as flowing bottom hole pressure (FBHP). Tests exposing interburden rocks to produced formation water were used to understand rock weakening, as well as a comprehensive program of mineralogy (XRD) and rock fluid sensitivity testing on selected sandstone, siltstone and mudstone core samples. Each sample was photographed initially dry (i.e., in its original state), and then in contact with synthetic brine or various clay stabiliser solutions, in order to qualitatively evaluate the change in both rock strength and stability over the duration of fluid exposure. Results suggest that volcanogenic sediments contribute to fines production in fields in the Walloons Subgroup. The results of the work presented here help to identify completion strategies, go forward development and future production optimisation opportunities.
Thesis (MPhil) -- University of Adelaide, Australian School of Petroleum, 2018

The Mesozoic Surat Basin constitutes part of the Great Australian Basin, which is composed of the Clarence, Moreton, Surat, Eromanga and Carpentaria basins and is located in southern Queensland and northern New South Wales. Within the northeastern basin, the Middle Jurassic Walloon Subgroup is the dominant coal-bearing unit. The Walloon Subgroup is best developed within the northeastern region of the Surat Basin between Wandoan in the north, Moonie in the south, as far east as the Kumbarilla Ridge and to the Mimosa Syncline in the west. This region offered the best likelihood for thick and continuous coal intersections and was chosen for this study. The objects of this study were to revise the stratigraphy and sedimentology and to review and understand the coal and coal seam gas characteristics of the Walloon Subgroup. Coals of the Walloon Subgroup have become the source of one of Queensland's fastest growing energy industries, producing over 100 TJ of gas daily into southern Queensland's gas pipeline network. Growth has occurred quickly over the past five years. Prior to 2000 only one well had been drilled that deliberately targeted the Walloon Subgroup coals to assess their coal seam gas potential. Since 2000, five companies have drilled over 260 core, exploration, appraisal and development wells to assess and develop this gas resource. Review and revision of Walloon Subgroup stratigraphy utilised the work of many previous workers and additionally over 300 well intersections, 85 of which were specifically drilled for coal seam gas exploration. While the upgrading of the Walloon Subgroup had been proposed as early as 1981, this proposal was based on only a small number of wells that had mostly only intersected incomplete sections of the subgroup in a limited area of the northeastern basin. The present study is based on over 300 well intersections, with over 20 fully cored intersections spread across the entire northeastern basin. The unit has been raised to subgroup status and divided into four distinct formations: the Durabilla Formation, Taroom Coal Measures, Tangalooma Sandstone and Juandah Coal Measures. Coal seams are concentrated within the Juandah and Taroom Coal Measures with the seams mostly being thinly interlaminated with carbonaceous mudstone, mudstone, siltstone and sandstone but can be identified and correlated across the northeastern basin. While the coal plies are lenticular, the coal packages are continuous across the study area. These coal packages have been named. Within the Juandah Coal Measures they are, from shallowest to deepest, Kogan, Macalister Upper, Macalister Lower, Nangram, Wambo, Iona and Argyle. Within the Taroom Coal Measures, they are Auburn, Bulwer and Condamine. Sedimentology of the Walloon Subgroup in the Surat Basin was reviewed and categorised using lithofacies associations developed for the Walloon Coal Measures in the Moreton Basin. Over 2,000m of core was logged from seven fully cored wells located across the northeastern Surat Basin to understand the nature and change (if any) of the sediments. Lithofacies associations developed in the Moreton Basin are shown to be relevant for the subgroup in the northeastern Surat Basin. Seven lithofacies were developed which could be grouped into three associations related to their environment of deposition: Major Alluvial Channel Facies (A1); Quiet Water – Lake/Abandoned Channel Facies (B1); Quiet Water – Lake/Abandoned Channel Facies (B2); Crevasse Splay/Channel (B3); Major Channel Levee (B4); Swamp (C1) and Ash Fall Pyroclastics (C2). These seven lithofacies are present in each of the subgroup's component formations and while the proportions of these lithofacies was not consistent across the northeastern basin, each of the formations was composed of a number of fining upwards sequences, beginning with either the A1 or B4 facies and culminating in the C1 facies. These fining upwards sequences are consistent enough to have each of the end facies, the coal swamp (C1), correlatable across the northeastern basin. Detailed graphic core logs and a cross section using the seven core wells were drawn to show the relationships of the lithofacies associations to each other as well as how they changed across the basin. This work confirmed that the Walloon Subgroup was deposited on a broad alluvial plain, with the sedimentary architecture being very similar across the subgroup, from the Durabilla Formation up to the Juandah Coal Measures. While the Walloon Subgroup is the fine-grained end member of one of the fining upwards sequences in the Surat Basin, it still contains a significant volume of sandstone. During the work to delineate lithofacies associations across the northeastern basin, sand/mud ratios were also determined from the cores in the seven selected wells. Sandstone makes up between 50 and 70% of the sequence while coal comprises only between 15 and 30% of the sequence. This result contrasts with earlier work that showed the Walloon Subgroup comprising less than 20% sandstone in the Surat Basin. This earlier work was based on electrical and gamma ray logs from 166 conventional petroleum wells and because of the high percentage of volcano-lithic components of many of the sandstones found within the Walloon Subgroup, many of these sandstones do not display low gamma ray counts. This then explains the apparent discrepancy. Previously only the seams of the upper Juandah Coal Measures (Macalister Upper and Lower) and Taroom Coal Measures (Condamine) had been extentsively studied for coal quality due to their suitability for open-cut coal mining. During this study over 570 coal samples from 23 fully and partially cored wells, located across the northeastern Surat Basin, were analysed to determine the characteristics of all seams present in the Walloon Subgroup. All samples were analysed to determine ash yield, moisture content and relative density. Samples from wells drilled during the latter stages of this study were also analysed for volatile matter and fixed carbon content. Due to the variable and high mineral matter content of the coals, most data needed to be recalculated to a dry, ash-free (d.a.f.) basis or a mineral matter free (m.m.f.) basis for comparison purposes. Coals from the Walloon Subgroup are high-volatile, bituminous coal with a moisture content ranging between 1.5 and 10.5% (weighted average 4.6%), volatile matter content ranging between 12.6 and 49.1% (weighted average 36.0%), an ash yield ranging from 5.1 to 78.7% (weighted average 27.7%) and a fixed carbon content between 4.3 and 46.7% (weighted average 31.5%). On an individual seam basis, moisture content decreases through the Juandah Coal Measures but seems to increase marginally at the top of the Taroom Coal Measures before again decreasing through this formation. Volatile matter content of the individual seams has an inverse relationship to that of the moisture content. Volatile matter content increases steadily through the Juandah Coal Measures, peaking in the Tangalooma Sandstone before dipping at the top of the Taroom Coal Measures, increasing towards the middle of the unit before dipping again at the base of the formation. Ash yield is relatively constant through the Juandah Coal Measures with the exception of the Wambo Seam, which has a much higher ash yield than the other Juandah Coal Measures seams. There is then a quantum shift with the thin seams of the Tangalooma Sandstone having significantly greater ash yields than those of the overlying Juandah Coal Measures. The seams of the Taroom Coal Measures have a lower ash yield than those of the Tangalooma Sandstone but greater than those within the Juandah Coal Measures. Relative density across the seams mirrors the changes seen in the seam's ash yield. Relative densities for seams in the Juandah Coal Measures are relatively similar with the exception being the Wambo Seam, which is higher. There is then an increase for the Tangalooma Sandstone seams and then a decrease through the Taroom Coal Measures. Coal samples were also analysed for their maceral composition and vitrinite reflectance with 215 samples analysed. Initially composite samples taken for adsorption analysis were also petrologically analysed for maceral composition and vitrinite reflectance. Only in the most recent sampling have individual plies analysed for gas content and coal quality also been petrologically analysed. While 125 samples from three wells have been analysed to this extent so far, a number of characteristics are apparent. Petrographically the coals of the Walloon Subgroup are dominated by vitrinite and liptinite with only minor to trace amounts of inertinite. Vitrinite content ranges from 62.4 to 90.6% (weighted average 76.8%), liptinite content ranges from 7.6 to 33.4% (weighted average 19.5%) and inertinite content ranges from 0 to 18.8% (weighted average 3.7%). On an individual seam basis the vitrinite content is very similar for the seams of the Juandah Coal Measures and which in turn are also similar to the seams of the Tangalooma Sandstone. The seams of the Taroom Coal Measures are also similar in vitrinite content but the lowermost seam (Condamine Seam) has the highest vitrinite content of all seams in the Walloon Subgroup. Liptinite content for the individual seams increases through the Juandah Coal Measures and peaks in the seams in the Tangalooma Sandstone before decreasing through the Taroom Coal Measures. Inertinite content for the Walloon Subgroup coal seams shows the most variation. The seams in the upper Juandah Coal Measures (Kogan, Macalister Upper, Macalister Lower and Nangram) have the highest inertinite content with the seams in the lower Juandah Coal Measures, Tangalooma Sandstone and Taroom Coal Measures having only a trace amount. Vitrinite reflectance across the Walloon Subgroup seams shows a steady increase through the unit. Over 570 coal samples from the Springbok Sandstone, Juandah Coal Measures, Tangalooma Sandstone and Taroom Coal Measures from 23 fully and partially cored wells were desorbed to determine their gas content and composition. The gas content was determined using the slow desorption method according to Australian Standards. All seams within the Walloon Subgroup contain coal seam gas. On a dried, ash free basis, gas content ranges from 1.15 to 14.48 m³/t (weighted average 5.33 m³/t). Gas content increases through the seams of the Juandah Coal Measures, peaks in the seams of the Tangalooma Sandstone and then decreases through the seams of the Taroom Coal Measures. This trend is very similar to the one displayed for the seams' liptinite content and indicates that within the coals of the Walloon Subgroup, liptinite content controls gas content. Gas saturation of the seams within the Walloon Subgroup again show an increase through the Juandah Coal Measures, peaking in seams of the Tangalooma Sandstone and then decreasing through the Taroom Coal Measures with the exception of the Kogan Seam which has a very high saturation. This trend also mirrors the gas content and liptinite content trend. To further characterise the coal seam gas potential of the coals of the Walloon Subgroup the methane adsorption properties of the coals was also determined. One hundred and seventeen samples were analysed to determine Langmuir volume and Langmuir pressure. These characteristics display a similar trend to that shown by the gas content. Using the Langmuir constants, the gas saturation of each seam could be determined. Overall the coals of the Walloon Subgroup are undersaturated and again a similar trend to that displayed for gas content and liptinite content is evident. Overall a number of physical characteristics of the Walloon Subgroup coals influence the quantity and quality of the coal seam gas present in the subgroup. These traits include depth, seam continuity, formation contacts and coal petrology. To further understand the coal seam gas characteristics of the Walloon Subgroup coals, sampling points were divided into groups dependent on their geographic location. The study area is divided into three structural regions; the Mimosa Syncline, Undulla Nose and the Chinchilla-Goondiwindi Slope and when coal characteristics, gas contents and gas saturations of each region are compared some differences and trends become evident. Broadly speaking the coals of the Juandah and Taroom Coal Measures are very similar and any differences are due to changes in depth and so the coals' maturity. What is evident is that there is a difference in gas content and saturation and a marginal difference between liptinite contents across the three regions. Modelling of the results of the study showed there are a number of stratigraphic and geologic features controlling the coal seam gas characteristics of the coals of the Walloon Subgroup. Regional geologic controls which increase gas content include the generation of secondary biogenic methane by the action of bacterially charged meteoric water entering the coal seams through the coals' outcrop and/or subgroup zones, the introduction of thermogenically generated gas from much deeper seams, and an increase in gas content due to an increase in coal maturity by an increase in the geothermal gradient. Regional geologic controls can also decrease gas content. These controls include the loss of gas due to a loss of seal between the Walloon Subgroup and the overlying permeable "Proud Sandstone" member of the Springbok Sandstone, a decrease in hydrostatic pressure due to the shallowing of the coal seams close to and at the seams' subcrops/outcrops and a loss of seal due to large regional faults which appear to act as conduits for gas. Stratigraphic controls on gas properties include coal characteristics and composition. Gas contents and saturations are expected to increase steadily with depth as a function of increasing hydrostatic pressure but there are anomalous jumps through the Juandah Coal Measures and a decrease through the seams of the Taroom Coal Measures. This trend in gas content and saturation is mirrored in the trend displayed by ash content and liptinite content and so are strongly suggestive as being linked. It has been demonstrated that the Walloon Subgroup can be divided into four separate formations which can be recognised across the northeastern Surat Basin. Two of these formations, the Juandah and Taroom Coal Measures, contain significant coal and coal seam gas resources. The Walloon Subgroup was deposited on an alluvial plain, which commenced with a high sedimentary accommodation rate but towards the end of depositional time had slowed considerably. Coal quality within the subgroup varies only marginally across the study area and the coal seam gas content within the coals varies with depth but does not uniformly increase with depth. This non-uniformity of gas content can only be partially explained by differing coal maceral composition of the different seams and is also due to a number of controlling factors including structural setting, depositional setting and coal petrology.

The Middle to Upper Jurassic Walloon Coal Measures of eastern Australia host petroleum resources mostly in the form of coal bed methane. The coals accumulated at a high-latitude (>75°S) during a greenhouse epoch and occur in regionally extensive fluviolacustrine successions. Previous studies have described the spatial relationship of facies using a variety of (and sometimes ambiguously defined) stratigraphic frameworks. This was complicated by the absence of marker beds or published radiometric dates. The coal beds are thin and laterally discontinuous and their origin, which has been poorly understood, has implications for consistent stratigraphic correlations. Improved correlation techniques and an understanding of the controls on coal bed geometry should allow better prediction of: 1) the location and architecture of prospective reservoirs, and 2) gas drainage patterns around individual wells. This study aims to address these questions by building upon pre-existing notions on the evolution of eastern Australia during the Middle to Late Jurassic using an integrated approach with new sedimentologic and palynologic data, combined with precise U-Pb dating of volcanic sediments and basin subsidence studies. Zircon from twenty-eight tuffs in 12 wells across the Surat and Clarence- Moreton Basins were dated using the high-precision chemical abrasion thermal ionization mass spectrometry (CA-TIMS) technique to within an error margin of ±40 ka. In addition, two volcanogenic sandstones from one well that intersected the Birkhead Formation in the Eromanga Basin were dated using the same methodology to within ±50 ka. On a 1237 km transect, five regional datums <420 ka in duration were defined for a chronostratigraphic framework using UPb dates. The dated zircons indicate that the Walloon Coal Measures that had previously been considered as Middle Jurassic (Aalenian-Callovian) are largely of Upper Jurassic age (Oxfordian-Tithonian). The new dates also reveal the diachroneity of coal-bearing facies across eastern Australia and inconsistencies in the correlation of lithostratigraphic units. Jurassic spore-pollen units of Price (1997) were also calibrated to the geologic time-scale using the same U-Pb dates to enable chronostratigraphic horizons to be correlated between basins where volcanic sediments are absent. The first occurrences of key taxa maybe younger than originally estimated, possibly by as much as ~4.2 Ma. These interpretations require further palynological analyses to confirm the age of first occurrences in wells to due to the rarity of key spore-pollen taxa. A high-resolution investigation on the roles of accommodation creation and climate on coal bed geometry suggest that, although subsidence was important in determining the abundance of coal, the climatic patterns contributed towards their thin, discontinuous character. Although the Walloon Coal Measures were deposited at high latitudes (>75°S), the coals originated from peats that accumulated in mires that experienced a warm temperate climate. Rapid and frequent climate change in the polar region may have limited the window of opportunity for thick, widespread coals to develop. New sedimentological and palynological data from the Surat Basin substantially revises interpretations of the environments of deposition. Sedimentary facies and spore-pollen assemblages confirm deposition in a predominately fluviolacustrine setting. However, the identification of tidally-influenced facies, acritarchs and dinoflagellate cysts (a first for Jurassic-aged strata in the basin) indicate periods of brackish water conditions. Marine incursions may have come from the north and the east during time of high eustatic sea-level during the Jurassic. Palaeogeographic reconstructions over 13 Ma reveal extensive fluviolacustrine systems draining from an eroding orogenic belt into proximal estuarine complexes. Allocyclic controls revealed by incised valleys and the deposition of transgressive estuarine facies strongly suggests the accumulation of coal (peat) was unlikely to be coeval with clastic sedimentation because of frequent changes in base level. This study illustrates that a multidisciplinary approach (notably the acquisition of precise U-Pb dates from volcanic sediments and the recognition of subtle indicators of marine influences) can be used to elucidate complex continental successions over large geographic areas. These type of studies will help in the search for subtle oil and gas reservoirs and better calculation of resource and reserve numbers. They may also be of use in better understanding sedimentary mineral resources and groundwater aquifer systems.
Thesis (Ph.D.) -- University of Adelaide, Australian School of Petroleum, 2018

Production of coal seam gas (CSG), or coal bed methane, requires large-scale depressurisation of a target formation by extracting groundwater, which, in turn, has the potential to affect overlying and underlying aquifers. This leads to wide-ranging stakeholder concerns around the impacts on groundwater assets such as water supply bores, groundwater-dependent ecosystems and connected watercourses. Around 2010, the CSG industry in Queensland, Australia grew rapidly with the expansion of operations in the Surat and Bowen basins by multiple operators. This particularly raised concerns about the cumulative effects, because the target coal seams are part of the Great Artesian Basin – one of the world’s largest aquifers. To respond to this challenge, an innovative framework was developed to provide for an independent cumulative impact assessment and to set up arrangements for managing those impacts. This chapter describes the main thrust of that framework.

This chapter lays out the criteria for the chronological arrangement of the suras that will be followed in the rest of the book. It argues critically for upholding the basic chronology first set out by Nöldeke at the end of the nineteenth century, providing detail on the textual and rhetorical qualities used to define the chronological development of the text. It also provides an overview of the structural qualities of the sura as a genre, and of the verbal features characteristics of the successive stages of the text’s development.

Carbon dioxide (CO2) storage is a vital part of the energy transition to low emissions. The Jurassic age Precipice Sandstone of the Surat Basin in Queensland, Australia, has been investigated as a suitable reservoir for CO2 storage. The overlying Evergreen Formation is a thick, interbedded mudstone and sandstone seal, and regarded a regional aquitard. Wells have been drilled for feasibility studies, initially in CTSCo’s Glenhaven region, near Wandoan, and recently in the southern Surat Basin near the town of Moonie. Since the Precipice Sandstone is also a Great Artesian Basin aquifer, the southern region with deeper groundwater unsuitable for stock use, and minimal to stagnant flow, is likely a more suitable site. The University of Queensland has undertaken research in both potential storage regions, and more broadly across the basin, including the separate Moonie oil field. This presentation will focus on core characterisation, experimental and modelled geochemical CO2-water-rock reactions and their impacts on water quality, porosity and permeability, and the effects of gas stream impurities SOx, NOx and O2. In addition, it may touch on field studies to assess existing hydrochemistry, water quality and native greenhouse gases in the Precipice Sandstone, and in the Hutton Sandstone that overlies the Evergreen Formation.