Hydrogen, as an energy carrier, is at the centre of research attention for its potential advantages over electricity to transport and store excessive renewable energy at the GW scale as part of the energy transition. To store energy at such a large scale and in a seasonal manner, energy storage technologies such as compressed air storage and high-temperature aquifer thermal storage are proposed, where Underground Hydrogen Storage (UHS) in porous reservoirs may be an important technology for hydrogen economy. Research studies suggest the necessity of using alternative gas to hydrogen as cushion gas due to the very low density at reservoir conditions and the high production cost of hydrogen. In addition, the potentially lower development cost of UHS in existing depleted natural gas reservoirs or former sites for underground gas storage compared to that of saline aquifers makes gas mixing a real possibility for future UHS operations. However, this topic is rarely studied, let alone its geological governing factors. In this study, we focus on the most likely geological settings for early UHS projects (Depleted gas fields in high permeability braided fluvial reservoirs) to understand the potential impacts of geological heterogeneity on project economics. To quantify the possible gas mixing induced by macro-scale heterogeneity and find the dominant factors that affect storage performance, in this study, we start by building synthetic high permeability water-gas reservoir model with geological characteristics of braided-fluvial systems often encountered in the oil and gas industry. Then we examine the effects of structural and litho-facies heterogeneity on gas mixing processes during typical UHS projects (10 mol% hydrogen-methane mixture as stored gas) via compositional numerical simulation. Homogeneous cases with different injection/production rates are also part of the sensitivity analysis. The cumulative days hydrogen fraction in produced stream is used as the metric for quantifying gas mixing during this process. Our results show that, compared to the homogeneous cases, macro-scale geological heterogeneity will intensify gas mixing and degrade the hydrogen fraction in the produced stream, affecting up to 15.8% of the recovery in 10 years (6% more than the homogeneous cases). Geological structure (reservoir dip angle and closure area) is a first-order determining factor above facies heterogeneity (braided channel dimensions). It determines the level of methane breakthrough during UHS projects in all the test cases, leading to contrasting gas mixing behaviors. Our study hereby provides a systematic method for evaluating gas mixing in UHS projects and facilitates future UHS techno-economic analysis.

During geological CO2 storage traditionally CO2 is injected subsurface into a high permeability reservoir capped by a low permeability seal to trap the buoyant supercritical plume. Wastewater from oil and gas production is also currently disposed of by subsurface injection into suitable reservoirs, most notably in the USA and Canada. Injection of CO2 dissolved in water may both increase storage security by reducing vertical migration and enhancing dissolution and mineral trapping. There is potential for surface dissolution of CO2 into wastewater that is already being stored subsurface. CO2-water-rock reactions in different sandstone or limestone reservoir rocks with either saline coal production water or low salinity water were geochemically modelled. The geochemical potential for mineral trapping of CO2, and associated changes to pH for potential reservoirs is compared. For a mineralogically clean quartz-rich saline sandstone reservoir only 0.18 and 0.20 kg/m3 CO2 was mineral trapped as ankerite and calcite over 30 or 1000 years. Feldspars, clays and carbonate minerals were converted to kaolinite, calcite, ankerite and smectites, as pH increased to 5.65. The specific silicate minerals present controlled mineral trapping potential e.g. with an Fe-rich chlorite present rather than a clinochlore chlorite 6.3 and 6.8 kg/m3 CO2 was trapped at 30 and 1000 years respectively as siderite and ankerite. Dissolution trapping dominated in the low salinity or limestone reservoirs with minor mineral trapping. The presence of small amounts of SO2 or H2S in the CO2 stream resulted in dissolved S sequestered as elemental S, pyrite, barite, and anhydrite. The effects of low CO2 content or potential reservoir cooling induced by injection fluids were also investigated. The low pH of the injection fluid could potentially corrode legacy wellbores, one solution is a form of amendment such as liming to neutralise pH.

The Great Artesian Basin (GAB) in eastern Australia is one of the most productive complex aquifers on Earth, covering a large portion of the continent. Yet stratigraphic correlation within and among constituent basins of the GAB remain poorly constrained. This has significant implications for resource estimation and management. In this study and for the first time, palynostratigraphic and zircon geochronologic data are integrated from the Lower Jurassic Precipice Sandstone and Evergreen Formation in the Surat Basin-a component of the GAB. The goal was to better constrain the depositional ages as a starting point for calibrating stratigraphy across the GAB. The results showed that the Precipice Sandstone and Evergreen Formation are highly diachronous, as are their sequence stratigraphic subdivisions. We provisionally revise the stratigraphic framework based on the integration of age information to show that the "lower" Precipice Sandstone (lowstand systems tract) ranges from Hettangian to Pliensbachian, the "upper" Precipice Sandstone (transgressive systems tract) extends from Sinemurian to Pliensbachian, the Evergreen Formation varies from Pliensbachian to Aalenian within which the Boxvale Sandstone varies from Pliensbachian to Toarcian and the Westgrove Ironstone member ranges from Pliensbachian to Aalenian. Additionally, the data allow us to provisionally assign the APJ1 to APJ2 palynozone boundary to similar to 190 Ma, the APJ3.2 to APJ3.3 boundary to similar to 180 Ma, and to constrain the APJ2.2.2 palynozone to span 184.80 +/- 0.20 Ma. This new age-context for the Precipice Sandstone and Evergreen Formation will be useful for future workers correlating strata between constituent basins of the GAB, as well as New Zealand and the broader Gondwana palaeocontinent.

Geological storage of CO2 captured from industrial processes such as coal combustion or from direct air capture is part of the transition to low emissions. The Jurassic Precipice Sandstone of the southern Surat Basin, Queensland, Australia, is undergoing feasibility studies for industrial scale CO2 geological storage, however regional data has so far been lacking. Precipice Sandstone reservoir drill core samples from the Southwood 1 and Tipton 153 wells in the southern Surat Basin include favourably quartz rich sandstone regions with quartz grain fracturing. A mudstone layer is also present in the reservoir. The overlying lower section of the Evergreen Formation seals consist of clay rich sandstones, interbedded mudstones, coal layers, Fe-Mg-Mn siderite, and Mg-calcite cemented sandstones. K-feldspars are weathered creating localised secondary porosity and pore filling kaolinite and illite. Layers of coal, pore filling cements, and framework grain compaction introduce vertical heterogeneity. Heavy minerals including pyrite, mixed composition sulphides, and barite are associated with disseminated coals in mudstones. Precipice Sandstone mercury intrusion porosities (MIP) ranged from 9 to 22% with favourably low reservoir injection threshold pressures, and the QEMSCAN measured open porosity between 2 and 22%. Evergreen Formation seal porosities were 7.5 to 16% by MIP or 1 to 19% by QEMSCAN, with the smallest pore throat distribution associated with the low permeability coal rich mudstone. Synchrotron XFM shows Rb mainly hosted in K-feldspars and muscovite, with metals including Mn mainly hosted in siderite. Zn and As are present in sulphides; and calcite and apatite cements mainly hosted Sr. Twenty kinetic geochemical CO2 -water-rock models were run for 30 and 1000 years with Geochemist Workbench, with calcite and siderite initially dissolving. In the Precipice Sandstone reservoir variable alteration of carbonates, feldspars and chlorite to kaolinite, silica, siderite and smectite were predicted with the pH remaining below 5.5. CO2 was mineral trapped through alteration of chlorite to siderite in three of the four cases, with -0.02 to 1.43 kg/m(3) CO2 trapped after 1000 years. In the calcite and siderite cemented Evergreen Formation seal, plagioclase conversion to ankerite trapped the most CO2 with 2.6 kg/m(3) trapped after 1000 years. The Precipice Sandstone in both wells appears to be generally suitable as a storage reservoir, with mineral trapping predicted to mainly occur in the overlying lower Evergreen Formation and in interbedded mudstones. Heterogeneity in interbedded sandstone, mudstone, and coal layers are likely to act as baffles to CO2 and encourage mineral trapping. Quartz grain fractures may influence preferential migration pathways in the reservoir but this would need future experimental investigation. Experimental CO2 water rock reactions to understand porosity and permeability changes were out of scope here but are recommended in future validation, along with investigating the potential for CO2 adsorption trapping in coal and mudstone layers.

Ancient basement fault geometry has a systematic effect on the folding of overlying sedimentary successions. Using aeromagnetic, Bouguer gravity, as well as 2D and 3D seismic datasets, the characteristics of the basement structure underlying the Jurassic-Cretaceous Surat Basin were examined and used to contextualise the nature of its folded strata. Using Fault-Forward modelling software, the deformation of the basement structural layers was modelled and analysed for its influence on the reactivation of faulting. The results show that the major fault trends in the eastern Surat and Bowen basins consist of five key features with N- and NE-trending orientations: the Goondiwindi, Moonie, Undulla Transition Zone, Burunga-Leichhardt, and Cockatoo fault systems. Most of the major fault deformation ceased in the Late Triassic. However, some faults (i.e., the Moonie and Goondiwindi fault systems) were variably reactivated along their lengths during the Jurassic. Three models of pre-existing basement reactivation are proposed to explain the observed variability in folding style with application to different parts of the basin. Ancient fault systems with dip angles greater than 45 degrees were readily reactivated and produced tight monocline structures with high strain (epsilon > 0.35) and fault throw (>60 m) (e.g. Moonie Fault System), while faults with small dip (<30 degrees) or large apical angles generated folds with low strain and uplift of the hanging wall. This variability in fault reactivation according to differences in fault throw potentially influences across-fault juxtaposition of strata and sealing potential for CO2 storage. Modelling such as this should be undertaken elsewhere in situations where trishear structural domains are expected, to better understand and predict the deformation of overlying stratal successions.

CO2 geological storage has been proposed as one method to mitigate climate change. Storage of CO2 in depleted oil or gas fields is one option, potentially following enhanced recovery. Understanding the potential impacts of CO2 water rock reactions is an important aspect of storage feasibility studies. Drill core samples of sandstones and mudstones from the Jurassic Moonie oil field, Australia, were characterised. In the Precipice Sandstone reservoir samples pore throats had broad size distributions, with mercury intrusion porosities 6.2 to 14.6%. Evergreen Formation samples were more variable with 1.2 to 16.1% porosity. Porosities measured by QEMSCAN were in reasonable agreement at 8.6 to 15.3% for Precipice Sandstones, and 0.6 to 21.5 for the Evergreen Formation. Sandstones had larger pore throat sizes and lower threshold pressures indicative of good reservoir rocks. Calcite cemented sandstones had truncated pore throat distributions, and the coal and clay rich mudstones had pore throats <0.1 mu m with higher threshold pressures likely to seal or baffle CO2. Quartz grains were naturally fractured, with silica, apatite, rutile, calcite, and siderite cements filling porosity in some samples. Feldspars had been weathered producing secondary porosity but also resulting in kaolinite and illite filling intergranular porosity. Pyrite and barite were mainly associated with coals. Synchrotron X-ray fluorescence mapping showed Sr was mainly hosted in calcite cement, apatite and barite; with Rb in both plagioclase and K-feldspars. Calcite mainly hosted Mn; while Zn and Cu were mainly in sulphides. Sulphide minerals in coal also hosted As in one core. Kinetic geochemical CO2-water-rock modelling using the characterisation data over 30 or 1000 years indicated reaction of carbonate minerals where present, and alteration of mainly plagioclase, K-feldspar and chlorite. Net precipitation of ankerite, calcite or siderite mineral trapped 0.23 to 1.28 kg/m3 of CO2 after 1000 years in the different rock packages and was highest in Evergreen Formation rocks. The predicted pH was in the range 5.0 to 5.4 after 1000 years, or higher at 5.2 to 7.1 in lower CO2 fugacity models. Sandstone reactivity was overall low over 30 years indicating a low likelihood of reservoir scaling which would be favourable, with mineral trapping likely in the overlying Evergreen Formation.

Sodium Hypochlorite (NaClO) oxidation has been reported as a promising method for coal seam permeability enhancement and extracting valuable hydrocarbons from coal. Different coal macerals, particularly vitrinite and inertinite behave differently in NaClO with varying reaction extent exhibited. The reasons for variability are not completely understood. This study aims to reveal the controlling factors of different coal maceral oxidation by comparing their molecular structures and pore characterization. A Permian coal from Bowen Basin, Australia, was collected and separated into vitrinite-rich concentrate (bright coal) and inertinite-rich concentrate (dull coal). Their reaction phenomena with NaClO are examined and their molecular structures and pore structures are compared with multiple techniques. The vitrinite-rich and inertinite-rich concentrates share similar organic molecular structures although there is some marginal difference with the bright coal being slightly more aliphatic with higher oxygen content. By contrast, their pore structures are significantly different such that the dull coal is more porous with higher content of mesopores and better connectivity. For coal powders vitrinite is more reactive than inertinite and yet for coal particles inertinite is more reactive. Given that inertinite is more porous, these results suggest that the porosity of the inertinite is the key property making the inertinite more reactive. Therefore, it is proposed that the different extent of oxidation for different macerals from isorank coal is controlled primarily by the difference in their porosity rather than molecular structures.

The Great Artesian Basin (GAB) (Australia) is one of the world’s most iconic groundwater basins and the lifeblood of much of Australia’s interior with high eco-hydro-socio-economic importance. Nonetheless, the GAB is currently mostly perceived and managed based on outdated hydrogeological conceptual models, which give rise to over-simplistic and incorrect public understanding of the basin. Capitalizing on 10 years of research, mainly in areas targeted by gas and mining industries (e.g. Surat Basin), this project aims to contribute to updated conceptual understandings of the GAB that can lead to more informed discussions and management of the basin. It also explores how the knowledge gained from intensive work conducted in the Surat Basin can inform research and management in other parts of the GAB. This is firstly achieved through (i) the 2020 interdisciplinary Hydrogeology Journal Special Issue “Advances in hydrogeologic understanding of Australia’s Great Artesian Basin”. Secondly through a science-communication and public engagement program, targeting a range of publics, aiming at societal education on GAB-related groundwater science and management, which includes a dedicated Website (temporarily https://natural-gas.centre.uq.edu.au/gab) with all produced scientific and communication material (informational videos, other educational material and links to the Special Issue articles).

Injected CO 2 streams may have geochemical reactivity to different rock types in a CO 2 storage complex depending on solubility and formation water chemistry. The Precipice Sandstone and Evergreen Formation are a low-salinity reservoir–seal pair in the Surat Basin, Australia, targeted for potential CO 2 storage. The kinetic geochemical CO 2 reactivity of different rock facies from three regions were predicted over 30 and 1000 year time periods. No material CO 2 mineral trapping in the quartz-rich Precipice Sandstone reservoir was predicted, owing to the low rock reactivity. Predicted CO 2 mineral trapping in the Evergreen Formation was more variable due to different amounts of more reactive feldspars, clays, calcite and siderite. Predicted mineral trapping as siderite and ankerite was between 0.03 and 8.4 kg m −3 CO 2 , and mainly depends on chlorite and plagioclase content. Predicted pH was between 5 and 7.5 after 1000 years. Pyrite precipitation was also predicted with SO 2 present in the injectate. QEMSCAN and SEM-EDS (scanning electron microscopy and energy-dispersive spectroscopy) spot imaging of samples from the seal containing natural fractures filled by siderite, pyrite, clays, ankerite, calcite, barite and apatite represent a natural analogue for natural mineral trapping. These are in good agreement with our model predictions. This study suggests that, from a geochemical perspective, the Precipice Sandstone is a suitable storage reservoir, whereas mineral trapping would occur in the overlying Evergreen Formation. Supplementary material: Additional model inputs, characterization and model images, and an excel file of QEMSCAN mineral and porosity components, are available at https://doi.org/10.6084/m9.figshare.c.5395393 Thematic collection: This article is part of the Geoscience for CO 2 storage collection available at: https://www.lyellcollection.org/cc/geoscience-for-co2-storage

Carbon dioxide (CO2) geological storage traditionally involves capturing a CO2 stream from a point source such as a power station or from cement, steel, or natural gas processing plant, transporting it and compressing it, prior to injection as a supercritical phase into a suitable geological reservoir overlain by a cap-rock or seal. One of the main perceived risks in CO2 geological storage is migration or leakage of the buoyant CO2 stream through the seal, via faults or fractures, or other migration out of the storage complex. Injection of CO2 dissolved in water may be one solution to mitigate the leakage risk. This approach could take advantage of large volumes of wastewater already being reinjected into saline aquifers worldwide but particularly in North America, thus reducing costs. This study examines the potential to “piggyback” off the existing wastewater injection industry as a novel carbon storage option.

The Lower Jurassic Precipice Sandstone and Evergreen Formation are an important prospective reservoir–seal pair for CO 2 storage in the Surat Basin, Australia. However, there is little seismic and well data to constrain reservoir modelling in the best notional injection area. To test the likely storage performance, three contrasting sector-scale static reservoir models were built to capture the range of geological uncertainty in facies distribution and reservoir properties. These considered sectors of the Surat Basin with different palaeogeographical arrangements. The models were focused on capturing detail at the interface between the top of the Precipice Sandstone (Blocky Sandstone Reservoir: BSR) and the overlying basal portions of the Evergreen Formation (Transition Zone: TZ), a critical area for understanding CO 2 injection. Object modelling was used for the BSR and lower TZ. Stochastic modelling was implemented for the upper TZ and the Ultimate Seal because these zones were less sensitive to facies distributions. Porosity was modelled stochastically, and permeability calculated using porosity–permeability transformation functions. Dynamic simulation showed the TZ has the capacity to arrest CO 2 flow out of the BSR given appropriate CO 2 injection conditions. This study shows a method of capturing uncertainty in geological heterogeneity when data are sparse or absent. The promising initial modelling results of CO 2 injection into the Surat Basin suggests that it presents a real option for carbon storage at a climate mitigation scale. Further investigation should focus on assessing other major risks associated with carbon storage such as fault seals, reactive fluid transport and the impact of legacy wells. This article is part of the Energy Geoscience Series available at https://www.lyellcollection.org/cc/energy-geoscience-series

CO2 geo-sequestration can significantly contribute to the reduction of greenhouse gas emissions. Out of all geological CO2 storage sites, mature oil fields are often considered primary targets for CO2 sequestration as one of Carbon Capture, Utilisation and Storage (CCUS) approaches where the operation cost can be offset by enhancing oil recovery and utilising the existing facilities. However, a geological formation with large volumetric capacity (pore volume) is not necessarily an appropriate candidate for CO2 storage and CO2 injectivity plays equally an important role for site selection to store CO2. Therefore, evaluation of CO2 dynamic storage capacity (injectivity) and ultimate CO2 enhanced oil recovery (EOR) are key elements for a successful CO2 storage – EOR project. CO2 EOR was considered as a suitable tertiary oil recovery approach after very short and inefficient primary and secondary oil recoveries in Yanchang oil field, the second largest tight oil field in China, located at Ordos Basin in north western China. This paper describes the acquisition of essential dynamic data from a reservoir in Yanchang oil field to evaluate its CO2 injectivity/dynamic storage capacity. For that, numerical reservoir simulation was utilised to model and history match the target reservoir. The history matched model was then used to numerically perform several testing scenarios resulting in the selection and design of the most appropriate test. A unique two-stage well testing approach was proposed to inject water and CO2 into one well and observe the pressure at two monitoring wells for a total testing period of about one year. It accurately estimates formation effective permeability in both the water flooded zone (test stage 1) and the CO2 flooded zone (test stage 2) at the injecting well. Also, it qualitatively estimates the water and CO2 fronts in the reservoir as well as CO2 injectivity using data at the injecting well. The radius of investigation (ROI) significantly increases by adding two monitoring wells to the existing injecting well. Using two monitoring wells also identifies heterogeneities and lateral anisotropy in the reservoir. The recently acquired field data, as part of this well testing program, indicate that the reservoir characteristics at the monitoring wells are significantly different from each other, suggesting the existence of considerable heterogeneity/anisotropy in the reservoir. The results generated by this well test are included in the reservoir model to reduce uncertainties for the future CO2-EOR field development plan. Finally, more informative decisions can be made on whether or not a field is suitable for a CO2-EOR project to unlock further oil resources from tight formations.

Newly acquired high-quality data are being used to reinterpret the Surat Basin flow systems of the Great Artesian Basin (GAB) in Australia. This paper revisits and updates previous interpretations of flow in the Hutton Sandstone with detailed analysis of the Dawson River area in the northern Surat Basin. Combining analysis of high-resolution permeability measurements with hydraulic head and hydrochemistry data supports the contention that there is significant flow towards the northeast, counter to the canonical regional flow conceptualisation of the GAB. The analysis in this work better identifies the likely discharge to be in the area that the Dawson River intersects the Hutton Sandstone. Heterogeneity in physical and hydrochemical properties suggests that local flowpaths are more complex than previously thought and, at least in this part of the Hutton aquifer, very little recharge contributes to flow deeper in the basin. These results provide a firm basis on which to refine and develop numerical hydrodynamic models of the basin, at least for the Hutton aquifer.

An understanding of the long-term reactivity of different rock types to injected CO2 is needed for sequestration site assessment. Relative to saline aquifer studies, the long term reactivity of CO2 in low salinity aquifers has received little attention. Currently in Australia, the Surat Basin is being appraised for its large-scale CO2 storage potential within low salinity aquifers. Sixteen core samples from the Precipice Sandstone and Evergreen Formation - the notional target reservoir and seal complex - were characterized for mineral content; helium, mercury-injection and micro CT porosities; air permeability; and, imaged with SEM-EDS. Samples consisted of quartz rich reservoir sandstones, feldspar and clay rich or calcite cemented sandstones (secondary reservoir), mudstones (sealing complex), and oolitic ironstones (sealing complex) derived from braided river, fluvial-deltaic, and restricted marine shoal depositional environments, respectively. The reservoir sandstone samples characterized here had measured total porosity that ranged from 11 to 23% with pore throats mainly between 90 and 100 mu m, and core air permeability from 558 to 3397 mD. In the Precipice Sandstone reservoir sample mu CT plugs, 98% of the pore space was connected with calculated vertical permeability 145-4611 mD and horizontal 4291-8200 mD. Feldspar and clay rich sandstone and mudstone samples from the overlying Evergreen Formation had porosity that ranged between 0.2 and 22.9%, with a wide range of pore throat sizes from similar to 0.005 to 30 mu m, and permeability from 0.2 to 28.1 mD, respectively. Ironstone and mudstone samples from the Westgrove Ironstone Member (Evergreen Formation) had porosity from 0.7 to 9.7% and a low permeability of 0.04 mD. Kinetic geochemical CO2 reactivity models made predictions over two time-scales: 30 or 1000 years. Selected models also accounted for the potential presence of 10 ppm SO2 gas. The Precipice Sandstone quartz-rich reservoir sandstones had consistently small amounts of reactive minerals and mineral trapping or scaling of the reservoir was not predicted over 30 years, with the pH approximately 4.5 after 30 years. Samples from the Evergreen Formation included feldspar and clay rich sandstones and mudstones, several contained variable amounts of carbonate cement. Their response to CO2 was more influenced by mineral content than rock type. Plagioclase feldspars and Fe-rich chlorite were the main silicate minerals that reacted to produce siderite and ankerite mineral trapping up to 2.57 kg/m(3) CO2. In the very unlikely event that CO2 rich fluids migrated upwards as far as the Westgrove Ironstone Member, chlorite is predicted to alter to siderite. This study indicates that the Precipice Sandstone reservoir in the study region has a low likelihood of mineral scaling which is favorable to avoid CO2 injectivity issues. Mineral trapping as ankerite and siderite could be expected to trap CO2 in the chlorite and plagioclase rich Evergreen Formation seal lithologies. Further work is suggested on validating long term predictions with observation data from natural analogue studies.

Interpretations of palaeodepositional environments are important for reconstructing Earth history. Only a few maps showing the Jurassic depositional environments in eastern Australia currently exist. Consequently, a detailed understanding of the setting of Australia in Gondwana is lacking. Core, wireline logs, two‐dimensional and three‐dimensional seismic from the Precipice Sandstone and Evergreen Formation in the Surat Basin have been used to construct maps showing the evolution of depositional environments through the Early Jurassic. The results indicate the succession consists of three third‐order sequences (Sequence 1 to Sequence 3) that were controlled by eustatic sea level. The lowstand systems tract in Sequence 1 comprises braidplain deposits, confined to a fairway that parallels the basin centre. The strata were initially deposited in two sub‐basins, with rivers flowing in different orientations in each sub‐basin. The transgressive systems tract of Sequence 1 to lowstand systems tract of Sequence 3 is dominated by fluvio–deltaic systems infilling a single merged basin centre. Finally, the transgressive and highstand systems tracts of Sequence 3 show nearshore environments depositing sediment into a shallow marine basin. In the youngest part of this interval, ironstone shoals are the most conspicuous facies, the thickness and number of which increase towards the north and east. This study interprets a corridor to the open ocean through the Clarence–Moreton Basin, or the Carpentaria and Papuan basins, evidence of which has been eroded. These results challenge a commonly held view that eastern Australia was not influenced by eustasy, and propose a more dynamic palaeogeographic setting comprising a mixture of fluvial, deltaic and shallow marine sedimentary environments. This work can be used to unravel the stratigraphic relationships between Mesozoic eastern Australian basins, or in other basins globally as an analogue for understanding the complex interplay of paralic depositional systems in data poor areas.

Ground surface movement can result from several natural and anthropogenic processes. Understanding the mechanisms that drive ground surface movement and their contribution to the net movement is crucial in assessing the impact of resource development projects and other human activities. Consequently, there is an interest in understanding ground surface movement in the Surat Cumulative Management Area (CMA), Queensland, and how it is influenced by coal seam gas (CSG) production, if at all. This paper presents the analysis of a large InSAR (interferometric synthetic aperture radar) dataset covering the CMA regions featuring no active CSG wells. These non-production areas were specifically examined in order to develop an understanding of background surface movement and its contributing processes. Of the regional dataset, four focus areas showing measurable changes over time were selected for more detailed investigation. All the focus areas exhibited an overall downward surface movement (subsidence), with three showing cycles of subsidence and uplift that appeared to be very well correlated with rainfall events. The soil types in these three areas were consistent with the hypothesis that the observed surface movement is due to rainfall infiltration-induced consolidation of the shallow soil layers and subsequent moisture-induced shrinkage and swelling. The fourth focus area, however, did not exhibit a strong seasonal fluctuation, and unravelling the mechanisms driving surface movement in this area was more difficult. This investigation resulted in a foundation for further research into the complex problem of surface movement, and in particular, deconvolution of the various contributions that occur at different depths, lengths, and time scales.

Evaluation of an accurate CO2 dynamic storage capacity, ultimate recycled CO2 and enhanced oil recovery (EOR) are key factors for a successful CO2 EOR project. The Yanchang Petroleum Company (YP)’s low permeability oil field is located at Ordos Basin - China with a very short and inefficient primary and secondary oil recovery and, therefore, YP proposed CO2 EOR as a potential tertiary oil recovery approach. In this work, the Wuqi reservoir in the Yanchang field is selected to evaluate the feasibility of full-field CO2 sequestration-EOR. The Wuqi reservoir has been in production for over a decade with historical data that can be used for a history matching process. To acquire essential dynamic data for evaluation of the CO2 injectivity/dynamic storage capacity, a specific two-stage pilot well test is proposed to inject first water and then CO2. It will provide relatively accurate calculated permeability for water (test phase 1) and CO2 (test phase 2) at the injection well. Also, the test will qualitatively estimate the location of water and CO2 fronts in the reservoir over time. Using two monitoring wells simultaneously, significantly increases the radius of investigation (ROI) that can be achieved for a given injection scenario and will also describe directional heterogeneity in the reservoir. When informed by the pilot test data, the model can be used to estimate the CO2 injection rate, ultimate cumulative CO2 injection and oil production and CO2 injection well numbers over 15 years of CO2 sequestration-EOR, which can be utilised for further techno-economic analysis of the project.

There is an increasing need to understand the influence of faults in both gas production performance and the resulting potential impact on adjacent groundwater resources. Faults can exhibit a wide variety of hydraulic properties. Where resource development induces changes in pore pressure, the effective stress and thus the permeability can be transient. In this study, w explored strategies for characterizing fault zone properties for the initial purpose of evaluating gas production performance. The same fault characterization can then be incorporated into regional groundwater flow models to more accurately represent stress, strain and the resulting transmissivities when assessing the impact of gas development on adjacent aquifers. Conventional fault zone analysis (juxtaposition, fault gouge or shale smear, fault reactivation) is combined with hydrodynamic analysis (distribution of hydraulic head and hydrochemistry) and surface water hydrology and hydrochemistry to evaluate across fault or up fault locations of enhanced hydraulic conductivity at specific locations of complex fault systems. The locations of identified vertical hydraulic communication from the hydraulic analysis are compared with the fault zone architecture derived from the 3D seismic volume overlain with the in-situ stress characterization. This provides an independent method of assessing other potential hydraulic communication locations based on seismic alone where no other hydraulic or hydrochemical information is available. A groundwater model is used in an inverse approach to assess the hydraulic properties required to generate observed hydrochemical anomalies so that a realistic range of rock properties can be assigned throughout the geological model to other faults. We use a case study example of the Gloucester Basin in New South Wales in eastern Australia to demonstrate how some of these techniques can be applied. The Gloucester Basin has been subject to exploration of coal seam gas with some pilot testing but no commercial production. It also contains data from groundwater monitoring bores and surface water features. The methodologies described can be applied elsewhere when faults play a key role in determining gas production performance or characterisation of groundwater flow system hydraulics in gas development areas.

SummaryThe Surat Basin is one of the most prospective onshore basins in Australia for CO2 storage. The Precipice Sandstone and Evergreen Formation have been appraised for their feasibility as a future CO2 storage reservoir-seal pair. Here we will focus on predicted CO2-water-rock reactions. These predictions rely on mineral and porosity data from drill core. Data were obtained from northern and two southern regions of the Basin. The northern region was more data rich. The southern region is more well core and data sparse with the exception of the Moonie oil Field. Additional drill core samples were collected from archived well core of Moonie and other parts of the basin. The core samples were characterised for porosity, mineral, and metal content to build geochemical models to predict local CO2-water-rock reactions and their potential effect on reservoir scaling, changes to porosity and mineral trapping of CO2. For the northern region, our work has predicted low reactivity of the Precipice Sandstone, with mineral trapping in the Evergreen Formation. The Precipice Sandstone sampled in the Moonie field has different mineralogical characteristics to wells in the Northern region. Here, CO2-water-rock predictions indicate minor alteration of plagioclase and K-feldspar to kaolinite, chalcedony and ankerite in cleaner Moonie sandstones, with additionally precipitation of smectite in clay rich sands. Formation water pH was buffered between 5 and 6 by dissolution of calcite or siderite cements. Sampled core has also shown evidence of previous natural CO2 and hydrothermal fluid alteration, fractured quartz grains, and fracture fills with mineral trapping as carbonates. This type of natural analogue data is vital to validate long term predictions. New drill core and data are still required in future for the southern and central Surat Basin region which is most prospective for CO2 injection and storage.