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Interest in hydrogen (H2) energy has exploded in the last few years. Much of the interest comes from transitioning to a decarbonised energy future, through the use of renewables, to convert hydrogen-rich materials (methane, water) to pure hydrogen gas streams. Each of these methods have their own challenges, such as the need for carbon capture and storage to manage carbon emissions or perspectives on the use of fresh water. At the same time as this engineered approach to generating hydrogen, there has been a quiet but exponential upsurge in research surrounding the origins and fate of naturally occurring hydrogen. Sometimes referred to as ‘gold’ or ‘white’ hydrogen, geological forms of hydrogen have been recognised for thousands of years. While already present as H2, hydrogen may exist with other gases, such as methane, helium, hydrogen sulfide and/or nitrogen. But is it real? Is it volumetrically significant, discoverable, predictable or exploitable? Early work suggests that we can begin to characterise potential sources of hydrogen, the depth ranges they may be generated from, the migration mechanisms that are relevant, and how they might be retained or lost in relation to the discovery and exploitation of this gas. However, existing publicly available data is constrained by a lack of analysis and limited evidence. While there are increased reports of seeps containing hydrogen, there is an absence of evidence of more significant finds and a lack of major analogues and case studies to date. We explore these risks and uncertainties and provide a roadmap for reducing the evidence gap.

This contribution focuses on the organic rich intervals of the prospective Mesoproterozoic Velkerri Formation from the Beetaloo Sub-basin, part of the greater McArthur Basin (Northern Territory). It is based on the integration of petrophysical measurements, high resolution petrographic observations from scanning and transmission electron microscopy, organic and inorganic geochemical analyses, and sequence stratigraphy. Specifically, we show how intervals of intense diagenetic quartz cementation are widespread throughout the Amungee Member of the Velkerri Formation and preferentially affect the organic-rich intervals of the formation. At the micro-scale, these intervals show a pervasive, quartz dominated nano-crystalline matrix interspersed with clays. The presence of this diagenetic matrix also shows at the well scale through 1D geochemical profiles and is well correlated with intervals of high organic content in all the wells where organic and inorganic profiling has been acquired. Using sequence stratigraphy to explain these consistent vertical patterns, we infer that the organic-rich and diagenetic quartz-rich layers are associated with detrital sediment starved intervals overlying transgressive surfaces. These are capped by maximum flooding surfaces and progressively leaner high-stand system tracts. The vertical patterns can be laterally correlated to map organic-rich and silica-rich strata with desirable reservoir properties like stiffness and storage potential., Open-Access Online Publication: March 03, 2023

Exploration in Australia's Beetaloo Sub-basin focuses on the liquids, wet-gas, and dry-gas mature shales of the Kyalla and Velkerri formations. Gas storage in these reservoirs occurs as free gas and additionally through adsorption to the internal pore surfaces of organic matter and clay minerals. The adsorbed gas component may represent a significant proportion of total gas-in-place for shales, and in the Beetaloo the co-production of wet gas components (e.g. ethane, propane) is also expected to improve the economics of gas production. Accurate characterisation of the adsorption behaviour of these hydrocarbons is critical for developing accurate resource estimates and understanding production behaviour. A gravimetric isotherm rig and measurement methodology was developed enabling accurate high pressure high temperature (HPHT) adsorption measurements on shales. Such measurements present a challenge due to the low sorption capacity of shale, as well as the requirement to approximate in-situ conditions. For example, an interlaboratory comparison by Gasparik et al. (2014) observed discrepancies of around 25% in CH4 sorption measurements in the high pressure range, and significant variation in C2H6 measurements above 5 MPa. Gravimetric isotherm measurements avoid cumulative errors of the volumetric method, and are less sensitive to the presence of leaks, an important consideration for HPHT measurements. Equipment design allowed the CSIRO gravimetric rig to overcome reported shortcomings of the method at high pressures due to sample buoyancy and low sample mass, and a calibration methodology using material with a known adsorption isotherm validated rig performance. The method was applied to measure CH4, C2H6 and C3H8 adsorption isotherms at multiple temperatures of four Beetaloo Sub-basin shales with a range of petrological properties. Measurements were also undertaken using a volumetric isotherm method to enable comparison. The measured isotherms present the first published C2 and C3 isotherms for Australian shales., Open-Access Online Publication: March 01, 2023

The ability to understand and predict the distribution of the primary organic content in a basin is key when exploring for unconventional hydrocarbons. Many pathways lead to the formation of organic-rich rocks through combinations of primary production, organic matter preservation, and dilution rates. It is likely that: (1) primary productivity will vary temporally and spatially, (2) preservation will be affected by the basin's physiography (e.g., open vs. restricted) and the burial efficiency, and (3) dilution will be a function of the stratigraphic evolution. If the vertical and lateral variations of each of these factors are not understood, it is difficult to quantify the impact of their interaction on organic matter accumulation, thus making the accurate prediction of the distribution of organic matter difficult. In the present work, we focus on the Mesoproterozoic Velkerri Formation, an unconventional hydrocarbon selfsourced shale reservoir that is currently the target of exploration and appraisal activities in the Beetaloo Subbasin. Using stratigraphic modelling, we simulate the evolution of the basin in the Proterozoic and calibrate the results to key wells located in the basin. We then run multiple realisations of the model while changing the input parameters that affect organic primary productivity, oxygen renewal in the water column, and sediment supply. This allows the effects of each parameter on organic matter accumulation to be quantified. This study emphasizes that deposition during the Mesoproterozoic required high primary productivity for organic-rich shales to form in the basin. In addition, this study shows that the controls on organic matter distribution vary spatially, both laterally and with stratigraphic depth within the Velkerri Formation/Beetaloo basin., Open-Access Online Publication: March 01, 2023

The Cooper Basin of Australia is a world-class unconventional gas resource with estimated gas resources of 29.8 trillion cubic feet. However, the production of this gas is challenging as the signif...

Reservoir and geomechanical analysis of Kyalla Formation core and wireline logs acquired at Beetaloo W-1 indicate the presence of two potential Source Rock Reservoir (SRR) intervals; the middle Kyalla SRR and the lower Kyalla SRR. The key properties of the SRRs include TOC 1-3%wt, PHIT 5-10%BV, SWT 30-60%PV, free gas porosity 2-5%BV, and 20-40scf/ton adsorbed gas content. A Poissons Ratio of 0.15-0.2 and Young’s Modulus of 30-35GPa suggest favourable geomechanical properties for effective hydraulic fracture stimulation. The lower Kyalla SRR has the greatest potential as it displays consistently positive geomechanical properties over the entire SRR interval as well as consistently high free gas porosity (>2-3%BV). Mudgas and core analysis indicate that the reservoir hydrocarbon phase is likely to be a wet gas. Potential retrograde condensation may yield significant condensate and LPG fractions from the produced gas stream. The positive reservoir and geomechanical properties within the Kyalla Formation SRR intervals at Beetaloo W-1 suggest further appraisal work is warranted to determine the deliverability of the SRRs and to determine what LPG and Condensate yields can be recovered at the well head.

The vast majority of petroleum exploration wells in the offshore basins of Western Australia bottom in Jurassic sedimentary rocks for which vitrinite reflectance results commonly appear to be anomalously low. Light element electron probe microanalysis (EPMA) of dispersed vitrinites in five samples of marine, Jurassic, potential source rocks from three petroleum exploration wells drilled in the Vulcan Sub-basin, Timor Sea, enables better understandings of this problem. The elemental abundance of carbon, oxygen, nitrogen, sulphur, aluminium and silicon were measured, and hydrogen content was calculated by difference. The EPMA method was validated by comparison of microprobe results for vitrinite in an Australian, Permian, medium volatile bituminous coal, with those determined by conventional elemental analysis according to the Australian ‘standard method’. Results on the Vulcan Sub-basin samples show that hydrogen contents of the Jurassic vitrinites are anomalously high, plotting as ‘type II’ ‘oil prone’ organic matter, on a van Krevelen-type diagram (atomic H/C vs O/C), a region normally associated with liptinite macerals. Implications of the EPMA results were investigated using fluorescence alteration of multiple macerals (FAMM) analyses, a laser-based technique that enables determination of the degree of vitrinite reflectance suppression. The elemental analyses, together with associated optical microscopy, confirm the occurrence of vitrinite having suppressed reflectance in marine Jurassic rocks of the Vulcan Sub-basin, which has important consequences for petroleum exploration if using vitrinite reflectance data in modelling thermal maturation and petroleum generation. In addition, the perhydrous vitrinites themselves may have considerably more petroleum generation potential than previously thought.

The Beetaloo Sub-basin is known for its vast unconventional hydrocarbon resources even though it is relatively underexplored. There is reasonably good coverage of 2D seismic within the sub-basin which is used as the basis for most structural interpretations. However, seismic quality varies, and it is occasionally deteriorated by the presence of basalts from the Kalkarindji suite and the karstic nature of the Gum Ridge formation. Aeromagnetic data, constrained by petrophysical logs are used, to map faults in the basalts of the Kalkarindji suite and their lateral extent to the South and the East of the sub-basin. The same structural elements are identified in the full tensor gravity gradiometry data. The top of this unit is observed in the electrical conductivity profiles, derived from Tempest data, in the NW part of the eastern sub-basin.

We studied a large dataset of ∼2600 shale gas samples from 76 geological formations in 38 sedimentary basins located in eleven countries. Shale gases contain mostly hydrocarbons dominated by methane. Shale gases can have primary microbial, secondary microbial and thermogenic origin. However, gases produced from most commercially successful shale plays (e.g., the Marcellus, Haynesville, Eagle Ford and Barnett in the USA, the Vaca Muerta in Argentina and the Wufeng-Longmaxi in China) are thermogenic. It appears that formations with greater gas endowment such as the Marcellus and the Haynesville contain late-mature thermogenic gas. Shale plays with early-mature thermogenic and secondary microbial gas such as the Antrim (USA) and the New Albany (USA) formations have relatively low endowments of recoverable gas. Shale plays with primary microbial gas are not significant from commercial exploration perspective. Isotope reversals (δ13C of methane > δ13C of ethane) are observed in shale plays with mature organic matter (vitrinite reflectance > 2%) that experienced significant uplift (>2 km). It appears that isotope fractionation during desorption from depressurized late-mature shales leads to isotope reversal in the residual gas produced from shale formations (e.g., the Wufeng-Longmaxi). Significant contribution of adsorbed gas (enriched in 13C-rich C2+ hydrocarbons relative to the co-occurring free gas) in the production from some plays (e.g., the Fayetteville, USA) may result in isotope rollovers.

The Proterozoic (~1.43 Ga) Velkerri Formation (McArthur Basin, Northern Territory) is believed to host one of the world’s oldest petroleum systems. Drilling and production tests demonstrated the encouraging potential of this unconventional gas resource and current efforts are aimed at better defining the extent of the gas and liquid-rich portions of this shale play. In this context, we conducted a comprehensive characterisation of specimens from the Amungee Member of the Velkerri Formation (previously referred to as the Middle Velkerri) sampled along a thermal maturity gradient from wells drilled across the Beetaloo Sub-basin. The scope of our analysis was to shed light on how the organic matter in the Velkerri Formation is affected by thermal maturity and how this affects the pore structure of the host rock. To this end, we integrated light and electron microscopy imaging with Raman spectroscopy and pyrolysis techniques to define the maturity of the sediments and visualise the shale pore network. In concert with the direct imaging, bulk samples were experimentally tested to measure their gas permeability and gas adsorption capacity. The results indicate that porosity is mostly organic-hosted with pore size dominated by meso- and micro-pores (i.e.

Stable isotope composition of gas is widely used in hydrocarbon exploration to determine the composition and thermal maturity of source rocks. The analyses of Australian coal and marine shale samples indicate that during gas desorption both molecular and isotopic compositions change with time. Therefore, a detailed understanding of the mechanism of isotope fractionation is required to improve our ability to better characterize source rocks and fluids. δ13C of Permian coals range between -22 and -26‰ (VPDB) and that of thermogenic methane generated from these range from -25 to -40‰. δ13C of gas desorbed from coal varies with time according to molecular weight and sorption properties. For example, in a set of deep Bowen Basin coals the difference in δ13C-CH4 between early and late desorbed gas varies from 2‰ to 29‰. For higher hydrocarbons this fractionation is lower, where for ethane it is

There is growing interest in optimising biogenic coal seam methane generation; however, relatively little is known about the microbiology of coal. To begin to address this deficiency, the biodiversity of a microbial community within a deep coal gas reservoir was investigated using the Amplified Ribosomal DNA Restriction Analyses (ARDRA) method. Additionally, a cultured subset of organisms from this community was examined for the ability to produce methane. ARDRA revealed that this community included both bacterial and archaeal lineages. The bacterial community was dominated by proteobacterial and Firmicutes taxa, though one actinobacterial taxa was also detected. This study is the first report of methanogenic archaea in an Australian coal seam gas reservoir. Cultures derived from the microbial community in the groundwater were able to produce methane from yeast extract and H2/CO2, but did not produce methane from coal. The ecological and physiological implications of these data are discussed.

Organic geochemical and petrological assessment of coals/coaly shales and fine grained sediments, coupled with organic geochemical analyses of oil samples, all from Permo–Triassic sections of the Southern Sydney Basin (Australia), have enabled identification of the source for the widely distributed oil shows and oil seeps in this region. The Permian coals have higher hydrogen indices, higher liptinite contents, and much higher total organic matter extract yields than the fine grained sediments. A variety of source specific parameters obtained from n-alkanes, regular isoprenoids, terpanes, steranes and diasteranes indicate that the oil shows and seeps were generated and expelled predominantly from higher plant derived organic matter deposited in oxic environments. The source and maturity related biomarkers and aromatic hydrocarbon distributions of the oils are similar to those of the coals. The oil-coal relationship also is demonstrated by similarities in the carbon isotopic composition of the total oils, coal extracts, and their individual n-alkanes. Extracts from the Permo–Triassic fine grained sediments, on the other hand, have organic geochemical signatures indicative of mixed terrestrial and prokaryotic organic matter deposited in suboxic environments, which are significantly different from both the oils and coal extracts. The molecular signatures indicating the presence of prokaryotic organic matter in some of the coal extracts and oils may be due to thin sections of possibly calcareous lithologies interbedded within the coal measures. The genetic relationship between the oils and coals provides new evidence for the generation and expulsion of oils from the Permian coals and raises the possibility for commercial oil accumulations in the Permian and Early Triassic sandstones, potentially in the deeper offshore part of the Sydney Basin.

Isotopic data indicate that coalbed methane (CBM) in many Australian reservoirs comprise secondary biogenic gas, however, little is known of the microbes active in these reservoirs. Therefore, for the first time in Australia, a preliminary culture-independent survey of the prokaryotic microbial composition of some of these reservoirs was undertaken to provide a basis for an understanding of the origin of the observed biogenic gas. Four water and three coal samples from the east coast of Australia were examined for their prokaryotic diversity by 16S rDNA analysis. DNA was extracted from the samples and amplified using bacterial- and archaeal-selective primers, and the resulting amplicons were cloned and sequenced. DNA amplicons derived from Gram-negative bacteria predominated; relatively few archaeal and Gram-positive bacterial sequences were amplified from the original samples. By-and-large coal samples yielded almost exclusively archaeal and α-proteobacterial amplicons, whereas the water samples contained amplicons derived from the remaining proteobacteria (β-e) and bacteroidetes. Amplicons from three genera of archaea were observed, none of which were genuine methanogens, although the dominant genus, Archaeoglobus, is reported to have some weak methanogenic activity. Further integrated studies of microbiology, hydrochemistry, gas geochemistry and geology of CBM reservoirs are continuing in order to better understand the parameters for methane production in eastern Australian basins.

Gas content of coals continuously change throughout their burial histories as a result of the changing state of equilibrium of the coal–gas system caused by variations in P–T conditions and coal rank. To fully evaluate the prospectivity of a coalbed methane resource, numerous coal properties, burial history, P–T conditions, hydrology and the likelihood of secondary biogenic gas generation need to be considered with respect to gas sorption capacity, gas contents and permeability. Previous studies have given differing interpretations on relationships between rank and maceral composition with sorption capacity. The maximum gas storing capacities for Sydney Basin coals is inversely related to rank up to medium volatile bituminous, but a coked, contact metamorphosed coal has an elevated capacity. Comparison of sorption capacities of coals having similar ranks and variable maceral group composition, indicate that rank has a dominating effect over any effects of organic matter type. For the Sydney Basin coals, the in-situ gas contents, on average, increase with depth up to about 600 m and with further increases in depth to 900 m, the gas contents tend to plateau or even decrease. Such a trend probably is consistent with the combined effects of pressure and temperature on the gas sorption capacity during the geological history. R-mode cluster analyses of the coal and gas properties yield a positive correlation between gas contents and inertinite abundance. This is related to undersaturation of the vitrinite-rich coals, possibly due to higher permeability and consequent leakage of more gas from vitrinite-rich coals than from inertinite-rich coals. Although a large amount of methane and other hydrocarbon gases would have been generated in the Sydney Basin at maximum burial during the Early Cretaceous, a large proportion of the gas might not have been sorbed within the coal due to limited gas sorption capacities and enhanced diffusivity at high temperatures. Upon uplift, gas that migrated from deeper in the sequence or from shallower biological activity may have been sorbed into the coals. Without secondary gas replenishment however, many of these coals remain significantly undersaturated. The areas that contain considerable amounts of secondary biogenic gas are highly prospective for coalbed methane production partly because of the higher gas contents, but also because of the higher permeability, which is required for access of the microbes and nutrients in meteoric waters. To fully evaluate prospectivity of coalbed methane resources, numerous coal properties, burial history, geologic setting and the likelihood of secondary biogenic gas generation need to be considered with respect to gas sorption capacity, gas contents and permeability.

Measurements of CO 2 adsorption and diffusion properties of coals are reported for various coalfields within Sydney Basin, New South Wales (NSW), Australia. Adsorption measurements were undertaken using a gravimetric method. Measurements carried out on 27 coals show that Sydney Basin coals at CO 2 sub-critical conditions, namely gas pressures below 6 MPa and temperatures below 39 °C, can adsorb a maximum volume (Langmuir volume) of 40 to 80 m 3 of CO 2 per tonne of coal on a dry ash free basis (daf). The coals used in this study are of sub-bituminous to bituminous rank, ranging from 0.66 to 1.45% mean maximum vitrinite reflectance, and are from depths ranging from about 27 m to 723 m. The highest adsorption capacity applies to the highest rank coal, which is also the deepest coal. The standard deviation between Langmuir modeled and measured values is less than 1.5 m 3 /t, corresponding to a relative error of less than 2.7% for all except one coal. Based on adsorption isotherms, the CO 2 storage capacity for in-situ seam pressure conditions range from about 6 to 51 m 3 /t. CO 2 diffusion properties of 15 of these coals, determined using a newly developed system capable of accurately measuring diffusivity of gases in solid coal indicate that CO 2 diffusivity (diffusion coefficient) in the Sydney Basin coals varies from 1.2 × 10 − 6 to 10.2 × 10 − 6 cm 2 /s. The diffusivity does not show any discernable trend with the variation in depth and rank. Porosity measured by a mercury injection method varies from 4 to 10% and decreases with increase in coal depth and rank. For some of the coal samples adsorption measurements for pure CH 4 , CO 2 and N 2 indicate that the Sydney Basin coals can store twice as much CO 2 as CH 4 and six times more CO 2 than N 2 (volume basis). Also, measurement of diffusivity in solid coal samples shows that CO 2 diffuses twice as quickly as CH 4 . The data obtained from this study and the estimated coal resources in the state of New South Wales, allow CO 2 sequestration potentials to be calculated.

Carbon dioxide contents of coals in the Sydney Basin vary both aerially and stratigraphically. In places, the coal seam gas is almost pure CO 2 that was introduced from deep magmatic sources via faults and replaced pre-existing CH 4 . In some respects this process is analogous to sequestration of anthropogenic CO 2 . Laboratory studies indicate that CO 2 :CH 4 storage capacity ratios for Sydney Basin coals are up to ∼2 and gas diffusivity is greater for CO 2 by a factor of up to 1.5. Present-day distribution of CO 2 in the coals is controlled by geological structure, depth and a combination of hydrostatic and capillary pressures. Under present-day P – T conditions, most of the CO 2 occurs in solution at depths greater than about 650 m; at shallower depths, larger volumes of CO 2 occur in gaseous form and as adsorbed molecules in the coal due to rapidly decreasing CO 2 solubility. The CO 2 has apparently migrated up to structural highs and is concentrated in anticlines and in up-dip sections of monoclines and sealing faults. CO 2 sequestered in coal measure sequences similar to those of the Sydney Basin may behave in a similar way and, in the long term, equilibrate according to the prevailing P – T conditions. In situ CO 2 contents of Sydney Basin coals range up to 20 m 3 /t. Comparisons of adsorption isotherm data measured on ground coal particles with in situ gas contents of Sydney Basin coals indicate that the volumes of CO 2 stored do not exceed ∼60% of the total CO 2 storage capacity. Therefore, the maximum CO 2 saturation that may be achieved during sequestration in analogous coals is likely to be considerably lower than the theoretical values indicated by adsorption isotherms.

Coal bed methane (CBM) is rapidly becoming a significant contributor to energy needs along the eastern seaboard of Australia. The prospective coal seams for methane production in Australia range from Jurassic to Permian in age with ranks varying from sub-bituminous to low volatile bituminous coal. These coals contain mixed gas compositions comprising mainly methane and carbon dioxide with subsidiary amounts of ethane and higher hydrocarbons. Geochemical data for gases and coal indicate extensive microbial activity, especially in coal seams shallower than about 600 m. Microbial activity possibly occurred subsequent to uplift of the eastern Australian basins during the Late Cretaceous and Tertiary. Such microbial activity has contributed to considerable volumes of methane presently stored in the shallow coals of these basins. The two main pathways of biogenic methane generation in coal are the carbon dioxide (CO2-reduction) and acetate dependant (aceticlastic-reaction) methanogenesis by archaea. Carbon and deuterium isotope data indicate that CO2 reduction is the main pathway of secondary biogenic methane generation in the eastern Australian coal seams. 'Sweet spots' for CBM production are likely to be mainly confined to permeable coal seams where microbial activity has enhanced the methane saturation levels of the coals. In the Sydney Basin, for example, the CBM production rates are up to an order of magnitude higher in areas where coal contains considerable volumes of secondary biogenic gas compared to areas containing only thermogenic gas. In the high producing wells of the Sydney Basin, the isotope fractionation factor for CO2 and CH4 is >1.06 which indicates extensive methane generation from CO2 dependant methanogenesis.

The northern part of Honshu Island contains the major petroleum resources of Japan. The source rocks mainly comprise a sequence of Miocene marine mudstones that are overlain in places by thick Pliocene and Pleistocene sediments. In the past, mainly vitrinite reflectance analyses have been used to evaluate thermal maturities of these rocks. However, vitrinite reflectance suppression caused by compositional variation of vitrinite is common in marine-deposited rocks, and therefore, modeled estimations of the extent of petroleum generation from the Japanese sequences could be in error. Fluorescence alteration of multiple macerals (FAMM) analysis is a method that aids in solving the problem of vitrinite reflectance suppression and gives improved evaluations of thermal maturity. Combined vitrinite reflectance and FAMM analyses of potential source rock sequences intersected by the Ministry of International Trade and Industry (MITI) Shin-Takenomachi and MITI Nishi-Kubiki wells of the Niigata Basin and the MITI Honjo-Oki and MITI Yuri-Oki-Chubu wells of the Akita Basin show that vitrinite reflectance suppression is common in the Neogene source rocks. This leads to major differences between the depth profiles for vitrinite reflectance and for FAMM-derived, equivalent vitrinite reflectance. On the basis of vitrinite reflectance, the thermal maturity and hence, the petroleum source rock potential is underestimated for the Miocene Noudani Formation of the Niigata Basin and the Pliocene Funakawa and Miocene Onnakawa and Nishikurosawa formations of the Akita Basin. The new thermal maturity data indicate that these formations would have generated more oil than previously thought, such that petroleum prospectivity for areas including these sequences should be reassessed.

A variety of geochemical techniques have been used to identify vertical remigration of oil and saline formation water from Mesozoic hydrocarbon traps in the Timor Sea, Northern Australia. This transient fluid flow event is thought to have been initiated by the Mio-Pliocene fault reactivation and has a major impact on the seal integrity of fault dependant hydrocarbon traps. Significant thermal anomalies appear to accompany brine flow and together with the highly saline nature of the fluids and absence of a shallow salt source suggest that these originate from deeply buried Palaeozoic evaporites. Numerical simulations have been utilised to test this hypothesis, and in combination with the empirical observations seek to provide an enhanced prediction of fault seal integrity for future exploration.

Methane generation by microbial activity or biogenesis is a significant source of coal bed methane (Faiz and Hendry, 2006; Strapoć et al, 2011). Being able to stimulate microbial methane generation in a coal seam reservoir has the potential to add significant value to depleted or undersaturated fields. Several laboratory studies have demonstrated that this process can be stimulated through the addition of inorganic nutrients (Jones et al, 2010; Orem et al, 2010). These studies, performed at atmospheric pressure on crushed coal, provide encouraging support for the concept of inducing in-situ biogenic methanogenesis and increasing gas-in-place in coal bed methane reservoirs. Important questions, however, remain about how laboratory results relate to what occurs in the reservoir. This extended abstract presents the results from a series of core flooding experiments conducted at reservoir pressure and temperature on intact coal core samples. Nutrient consumption is characterised by measuring the nutrient balance between the inflow and outflow waters. Gas content is measured through a helium flood at the end of the experiment, during which the pore pressure is dropped to atmospheric pressure to drive off any adsorbed gas. These experiments confirm that microbial gas generation does occur at reservoir pressure and temperature, and at high enough rates to rapidly increase gas content.

Coal seams of the Sydney Basin contain large volumes of gas, mainly methane (CH4) and carbon dioxide (CO2) with subordinate amounts of heavier hydrocarbons (C2+). The desorbable gas content of the Sydney Basin coals ranges up to about 20 m3/t, and its abundance is mainly related to depth and geological structure.

The southern Sydney Basin is an ideal natural analogue for CO 2 geosequestration because of the widespread CO 2 occurrence, extensive data sets available and general knowledge of gas distribution. The CO 2 mainly occurs adsorbed in coal, incorporated into carbonate minerals and dissolved in formation water. On this basis, an area of -900 km 2 has been chosen for detailed examination. Gas in the coal seams of this area contain mainly CH 4 and CO 2 , the CO 2 content ranging from

Coals in the Sydney Basin contain large amounts of gas ranging in composition from pure methane (CH4) to pure carbon dioxide (CO2). These gases are derived from thermogenic, magmatic and biogenic sources and their present-day distribution is mainly related to geological structure, depth and proximity to igneous intrusions.A coal bed methane (CBM) study of the Camden area of the Sydney Basin has been jointly conducted by Sydney Gas Company NL (SGC) and the Commonwealth Scientific and Industrial Research Organisation (CSIRO). The delineation of high production fairways is vital for any CBM project development to be commercially successful. An integrated research project employing various methods of reservoir characterisation, including geological, geochemical, geomechanical and gas storage analyses contribute to this delineation for the Camden area, where SGC is currently developing the 300-well Camden Gas Project.In particular, accurate determinations of gas content, saturation levels, composition and origin, as well as interpretations about distribution, are essential for identifying sweet spots for CBM production optimisation. The extent of gas saturation is a function of numerous factors, including amounts of gas generated between the Permian and Late Cretaceous, amounts expelled from the system during Late Cretaceous-Tertiary uplift and amounts of subsequent secondary biogenic methane generated and absorbed in the coals. The extent of this secondary biogenic gas generation appears to be greatest in coals proximal to the basin margins, where meteoric waters carrying bacteria and nutrients had ready access. Significant enhancement of methane content also occurs, however, in deeper parts of the basin where permeable structures exist.The integrated study shows that high production CBM wells drilled to date by SGC are located in zones of enhanced permeability. In these locations original thermogenic wet gases have been removed and additional secondary biogenic methane has been generated due to microbial alteration of coal, hydrocarbons and carbon dioxide. This process has replenished the coals by enhancing the methane contents of the respective seams and this phenomenon can be termed ‘bio-enhancement’ in the context of CBM production.

The fluorescence alteration of multiple macerals (FAMM™) technique was developed in 1989-91 to overcome problems encountered by existing techniques applied to the thermal maturity determination of North West Shelf organic matter. Subsequently it has been widely used in Australia, SE Asia and elsewhere. This paper reviews the present status of the FAMM technique.Since its inception, the methodology of the FAMM technique has undergone some changes. The most important is a closer integration with vitrinite reflectance (VR) resulting in expansion of the capacity of the technique to solve complex maturity problems. The accumulated data indicate that shales and mudstones are most suitable for FAMM analysis for the reason that more porous lithologies are potentially more susceptible to organic matter oxidation. There is extensive evidence that organic matter in cores and well-protected cuttings samples of shales remain unaffected by oxidation during decades of storage because clay is extremely effective in limiting access of oxygen. Adhering to sampling guidelines can greatly reduce the risk of errors from this source. Of the two recently described thermal maturity techniques based on combining VR with fluorescence intensity measurements (Quick, 1994; Newman, 1997), FAMM is more closely related to Quick's method. As the fluorescence alteration ratio which acts as the thermal maturity indicator in the FAMM method is independent of VR, it is possible to cross check results for consistency using suppression iso-correction curves-a possiblity which does not exist with the other thermal maturity techniques based on fluorescence. A working set of suppression iso-correction curves has been determined specifically for Australian Jurassic vitrinite. Whether from coal or dispersed organic matter (DOM), Australian Jurassic vitrinites are commonly perhydrous and this should be borne in mind when modelling thermal histories of North West Shelf sequences.

The coal seam gas content of the Late Permian Illawarra Coal Measures ranges from