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Summary Hydraulic fractures can enhance well productivity from stress-sensitive naturally fractured reservoirs, such as coalbed methane or coal seam gas (CSG) reservoirs. Graded proppant injection (GPI) has been proposed to enhance long-term, far-field interconnectivity between the created hydraulic and short-term, enhanced natural fracture permeability, resulting from fracture fluid leakoff and lowered net effective stress. This novel study shows how applying GPI with hydraulic fracturing treatments resulting in an increased stimulated reservoir volume (SRV) can enhance well productivity and improve CSG well economics. A commercially available reservoir model and history-matched hydraulically fractured coal seam case are used to evaluate well performance differences between a hydraulic fractured reservoir and one including GPI application. A dual-porosity system and the Palmer and Mansoori model are used to simulate initial and long-term permeability accounting for reservoir depletion (i.e., increased net effective stress and matrix shrinkage). A previously validated case study is used to describe the post-embedment benefits of GPI based on the porosity model and history-matched reservoir properties. A net present value (NPV) can then be calculated for each scenario, based on the production differences and typical Australian CSG costs. Our results show that permeability enhancement is achieved beyond the hydraulically fractured region for all post-GPI stimulation cases. An optimal SRV can be found relative to permeability that maximizes the incremental NPV from GPI application. The next most significant parameters after permeability that influence the economic outcomes are fracture porosity and coal compressibility. A larger SRV yields higher cumulative gas production over 30 years with up to 7.2 times increase over gas production without GPI. This study substantially increases our understanding of how to model and understand the benefits of GPI application along with hydraulic fracturing to increase the SRV in CSG wells.

Underground Hydrogen Storage (UHS) is an emerging large-scale energy storage technology. Researchers are investigating its feasibility and performance, including its injectivity, productivity, and storage capacity through numerical simulations. However, several ad-hoc relative permeability and capillary pressure functions have been used in the literature, with no direct link to the underlying physics of the hydrogen storage and production process. Recent relative permeability measurements for the hydrogen-brine system show very low hydrogen relative permeability and strong liquid phase hysteresis, very different to what has been observed for other fluid systems for the same rock type. This raises the concern as to what extend the existing studies in the literature are able to reliably quantify the feasibility of the potential storage projects. In this study, we investigate how experimentally measured hydrogen-brine relative permeability hysteresis affects the performance of UHS projects through numerical reservoir simulations. Relative permeability data measured during a hydrogen-water core-flooding experiment within ADMIRE project is used to design a relative permeability hysteresis model. Next, numerical simulation for a UHS project in a generic braided-fluvial water-gas reservoir is performed using this hysteresis model. A performance assessment is carried out for several UHS scenarios with different drainage relative permeability curves, hysteresis model coefficients, and injection/production rates. Our results show that both gas and liquid relative permeability hysteresis play an important role in UHS irrespective of injection/production rate. Ignoring gas hysteresis may cause up to 338% of uncertainty on cumulative hydrogen production, as it has negative effects on injectivity and productivity due to the resulting limited variation range of gas saturation and pressure during cyclic operations. In contrast, hysteresis in the liquid phase relative permeability resolves this issue to some extent by improving the displacement of the liquid phase. Finally, implementing relative permeability curves from other fluid systems during UHS performance assessment will cause uncertainty in terms of gas saturation and up to 141% underestimation on cumulative hydrogen production. These observations illustrate the importance of using relative permeability curves characteristic of hydrogen-brine system for assessing the UHS performances.

This study investigates the adsorption mechanisms and the dilational surface rheology of the anionic surfactant sodium dodecylbenzene sulfonate (SDBS) at the air–liquid interface, in the presence and absence of NaCl over a wide range of SDBS concentrations. We also evaluate the Langmuir and Frumkin models in order to predict the dynamic adsorption of SDBS solutions. Our results reveal that the equilibrium surface tension of SDBS solutions is a monotonically decreasing function of NaCl concentration. However, the dilational viscoelastic properties of SDBS solutions are found to be a non-monotonic function of NaCl concentration. NaCl manifests opposing effects on the dilational viscoelastic moduli of the gas–liquid interface, depending on the frequency of surface oscillation and surfactant bulk concentration. Our measured dilational surface elasticity and viscosity data show a shift in the surfactant transition concentration, at which the viscoelastic moduli reach their maximum values, towards smaller surfactant bulk concentrations with increasing salt concentration. It is attributed to suppressing the electrostatic repulsion between the hydrophilic head groups of surfactant molecules in the presence of electrolytes. The maximum viscoelastic moduli at different NaCl concentrations is found to be the reflection of the relative impact of enhanced adsorption and increased diffusion exchange between bulk and interface.

SummaryIn coal-seam-gas (CSG) fields, where single wells tap multiple seams, it is likely that some of the individual seams hardly contribute to gas recovery. This study aims to examine the contribution of individual seams to the total gas and water production considering that each seam can have different properties and dimensions. A sensitivity analysis using reservoir simulation investigates the effects of individual seam properties on production profiles.A radial model simulates the production of a single CSG well consisting of a stack of two seams with a range of properties for permeability, thickness, seam extent, initial reservoir pressure, coal compressibility and porosity. The stress dependency of permeability obeys the Palmer and Mansoori (1998) model. A time coefficient (α) relates seam radius, viscosity, porosity, fracture compressibility, and permeability. It is used to aid interpretation of the sensitivity study. Finally, two hypothetical simulation scenarios with five seams of different thicknesses and depths obtained from producing wells are explored. The range in properties represents conditions found in the Walloon Coal Measures (WCM) of the Surat Basin, relevant to the Australian CSG industry.Each seam in the stack achieves its peak production rate at different times, and this can be estimated using α. Seams with lower α reach the peak gas rate earlier than those with higher α-coefficient. The distinct behavior of gas-production profiles depends on the combination of individual seam properties and multiseam interaction. At a αratio > 1 (i.e., αtop/αbottom > 1), the bottom seam peaks first but achieves lower gas recovery than the top seam. An increasing αratio is associated with the inhibition of less-permeable seams and reduced overall well productivity. For αratio

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.

In CO2 storage projects, CO2 usually enters the target reservoir at a lower temperature than that of the surrounding rock and its density is increased. The injection temperature affects how much CO2 can be stored. In this work we investigate the impact of heat exchange during CO2 injection into the Surat Basin, Australia, using integrated reservoir modelling. We evaluate the aquifer storage and sealing capacities, as well as pressure build up and CO2 plume migration. Flow simulations of CO2 injection into the Precipice Sandstone were conducted with injection temperature from 40 to 80°C. The modelling domain consists of the reservoir sandstone, an overlying transition zone (muddy sandstone) and above it, the ultimate seal. The distribution of porosity, permeability and capillary pressure is heterogeneous. Heat exchange between rock and fluids was enabled in the commercial simulator to evaluate changes in fluid properties due to wellbore cooling. The initial temperature was set to 80°C. The injector’s wellbore pressure drop is modelled honouring a constant well head pressure of 15,000 kPa. The maximum allowed bottom-hole pressure is 90% of a thermally reduced fracturing pressure. The viscosity of water and CO2 increases during cooling of the near wellbore zone; thus, pressure build up grows faster in the case of lower injection temperatures. Although the bottom-hole pressure becomes higher, injection rate is constrained by well head pressure. Heat exchange also increases the density and saturation of CO2 at the plume edge, which causes a sharper and faster advancing front. Higher pressure in the reservoir forces fluids to migrate to the transition zone, which also reduces its temperature. CO2 flows preferentially through the lowest capillary pressure channels and is able to permeate slightly into the transition zone. These physical conditions at the bottom of the well (lower temperature and higher pressure) lead to a denser CO2 plume and a greater mass is stored in the reservoir each year. This work analyses non-isothermal injection of CO2 into an aquifer using integrated reservoir modelling. It illustrates how reservoir cooling may increase the rate of CO2 storage and slight migration to the transition zone.

The debate on the submarine canyon origin between the upslope erosion model dominated by retrogressive mass failures and the downslope erosion model controlled by gravity flows has not been fully settled. However, this debate is critical for explaining submarine canyon evolution. This study combines susceptibility mapping and stratigraphic forward modeling (SFM) to examine the origin and evolution of submarine canyons under various fluvial discharge and morphologies. The SFM work consists of dozens of hypothetical numerical experiments based on typical passive margin bathymetry with half bathymetry occupied by an incipient canyon and associated river mouth topography, and another half bathymetry by steep slopes without canyons. Evolution characteristics in both plan and cross-section views are analyzed, and the impacts of fluvial and morphological features on canyon evolution are tested. The results indicate that the submarine canyons retreat landward, tributaries develop on the canyon outer banks, and blind canyons grow landward to capture small gullies and form shelf-incising canyons. The upslope pattern is dominant regardless of changes in fluvial discharge and morphologies. The locations of tiny gullies on steep slopes determine the distribution and growth direction of submarine canyons, whereas fluvial conditions and morphology parameters affect the canyon dimensions. High fluvial discharge and high canyon sidewall slope angle promote tributary development and canyon erosion. High canyon sinuosity leads to an asymmetrical distribution of tributaries on canyon outer banks whereas high regional slope angle increases the canyon length and decreases the canyon spacing. This study settles the debate between the upslope and downslope erosion models. In addition, it refines the upslope model by highlighting the importance of small-scale gullies and testing the influence of fluvial and morphological conditions on canyon evolution. The conclusions could promote the understanding of submarine canyons and assist in reservoir exploration and hazards prevention.

This commentary addresses “Numerical investigation of the potential contamination of a shallow aquifer in producing coalbed methane” by Xianbo Su, Fengde Zhou, and Stephen Tyson. We think the models used in the simulations described in the paper are unrealistic, even as a conceptual worst case scenario. Concerns regarding how the results of these simulations are interpreted and portrayed, and in particular how they are related to previous works are discussed in detail. We believe the original paper uses language which could be misleading, and possibly alarmist, and we suggest references cited in the original paper may have been misinterpreted.

A surrogate model approximates a computationally expensive solver. Polynomial Chaos is a method used to construct surrogate models by summing combinations of carefully chosen polynomials. The polynomials are chosen to respect the probability distributions of the uncertain input variables (parameters); this allows for both uncertainty quantification and global sensitivity analysis. In this paper we apply these techniques to a commercial solver for the estimation of peak gas rate and cumulative gas extraction from a coal seam gas well. The polynomial expansion is shown to honour the underlying geophysics with low error when compared to a much more complex and computationally slower commercial solver. We make use of advanced numerical integration techniques to achieve this accuracy using relatively small amounts of training data.

In coal seam gas (CSG) fields, where single wells tap multiple seams, it is likely that some of the individual seams hardly contribute to gas recovery. This study aims to examine the contribution of individual seams to the total gas and water production considering that each seam may have different properties and dimensions. A sensitivity analysis using reservoir simulation investigates the effects of individual seam properties on production profiles. A radial model simulates the production of a single CSG well consisting of a stack of 2 seams with a range of properties for permeability, thickness, seam extent, initial reservoir pressure, compressibility and porosity. The stress-dependency of permeability obeys the Palmer and Mansoori (1998) model. A coefficient (α) relates seam radius, thickness, porosity, compressibility, permeability, and initial pressure. It is used to aid interpretation of the sensitivity study. Finally, a case study is modelled with 5 seams of different thicknesses and depths obtained from a producing well. The range in properties represents conditions found in the Walloon Coal Measures of the Surat Basin, relevant to the Australian CSG industry. The sequence in which peak of gas production rate of each seam is achieved can be estimated using α. For αtop/αbottom > 1, the bottom seam peaks first but achieves lower gas recovery than the top seam. For αtop/ αbottom < 1, the top seam experiences fast depletion and total gas production rates decrease drastically. The peak gas rate of each seam may be identified on gas production profiles depending on α. When 1 < αtop/ αbottom < 10, individual peaks merge. For 10 < αtop/αbottom < 27, individual seams can be clearly identified as dual-peaks on production curves. For αtop/αbottom > 27, the contrast between maximum rate and time to peak increases and the top seam’s contribution is significantly reduced in early production time. A more realistic case based on a section of an actual Surat Basin well with 5 seams confirmed that when the αtop/αbottom of seams of greater permeability-thickness (kh) is higher than 27, gas recovery decreases. Even with higher total kh, seams with α ratio = 100 produced less gas than seams with αtop/αbottom = 10. An increasing α ratio is associated with inhibition of less permeable seams and reduced overall well productivity.

Static and dynamic models often simplify coal measures as laterally continuous seams between interburden layers. However, coals are not always laterally continuous and are frequently heterogeneously distributed within interburden. Formation water often contains a high concentration of gas, and in many cases is likely at saturation. Groundwater extraction from coal seam gas (CSG) reservoirs, therefore, will produce free gas from both: i) gas desorption from the coal matrix, and ii) gas exsolution of dissolved gas in formation water. This generated gas could be produced from the well or it may migrate up-dip in-situ due to buoyancy effects. Accounting for solubility effects (i.e. the dissolved load degassing component of the free gas phase) while modelling gas production from coal requires additional field data gathering/analysis effort and brings extra computational cost. In this work, for both layered and heterogeneous coal-interburden systems, we use conceptual numerical simulations to demonstrate that gas dissolution/exsolution considerably affects the prediction of gas desorption rate, production rate, and gas migration flux. Two coal-interburden systems are considered in this paper. Both contain 20% coal, one with laminated coal layers and the other with heterogeneously distributed coal bodies within a shale interburden. Static geological models were built within a 1km×1km×20m cube. A vertical production well at a constant pressure of 100kPa was placed in the middle of the models and perforated along its entire thickness. Implementing a dual-porosity dual-permeability approach, multiphase flow was modelled once with, and then without, accounting for the dissolution/exsolution of the aqueous phase. Results show that allowing the aqueous phase to produce gas leads to an increase in the gas production rate from the heterogeneous case; however, it decreases the gas production from the layered coal model in early time steps. Results suggest that a detailed understanding of the dissolved gas load in CSG reservoirs will assist in improving gas production predictions at the well head.

Coal Seam Gas (CSG) is a significant resource; it makes up 90% of the gas production in Queensland, Australia, most of it from the Surat Basin Walloon Coal Measures, (WCM). However, coal connectivity and distribution are poorly understood resulting in production and modelling challenges. Simplistic, homogeneous models cannot adequately explain volumes or flow rates of gas and water. Initially, the focus of the industry was on optimizing drilling, often without the aid of seismic data, relying on correlations based on wireline logs and cores alone. Those correlations were often based on lithology, and connected sand with sand and coal with coal. Those models seem to overestimate flow between wells and volumes of hydrocarbons or water (Cardwell, 2018). Here, log interpretation is integrated with 3D seismic using a sequence stratigraphic framework. Special attention is placed on the architecture of the WCM revealed by seismic. Seismic mapping of individual coal seams in the Springbok Sandstone or the WCM is difficult on a field scale. Most coals are below seismic resolution, yet have a strong influence on seismic amplitudes. Four methods of spectral decomposition are compared and evaluated on how well they predict known geology at many well locations throughout the 3D seismic survey. Sequence stratigraphy applied to core and log interpretation integrated with seismic produces an improved view of coal distribution and geometries. Coals are mostly thin and discontinuous and segregated by channels cutting through them that appear to be meandering through flood plains. Coal forms along channels and sands are likely to be present in point bars. Therefore, sands or coals identified in wireline logs are not likely to be connected to a large sand sheet, but are rather individual channels or sand bodies likely to be hydraulically isolated. In the next phase, it will be investigated how results of spectral decomposition can be used inform geostatistical algorithms for modelling to produce more representative static geological models.

The Walloon Coal Measures in the Surat Basin are the main target for Coal Seam Gas (CSG) production in Queensland. They are overlain by the Springbok Sandstone, although consistently identifying the boundary between these two extremely heterogeneous intervals is challenging, and different stratigraphic methods may lead to quite different interpretations. This paper discusses the challenges associated with identifying the Walloon-Springbok boundary and highlights some potential impacts of using alternate interpretations of the boundary. Ulimately, resolving this challenging geology is important because different correlations impact the vertical and horizontal propagation of pressure in groundwater and reservoir models.

Carbonated water injection (CWI) is described as a chemical-enhanced oil recovery method in which CO2-enriched water is injected into oil reservoirs as a displacing fluid. Although confirmed by many that a considerable amount of recovery improvement is attainable through CWI in both lab and field scales, the interaction of salinity on the performance of CWI and its potential fines migration is not very well understood. This study examines the efficiency of oil recovery improvement during low-salinity carbonated water injection (LSCWI) in a sandstone reservoir, while total dissolved salt concentration varies. To this end, a series of coreflooding experiments were performed on homogeneous sandstone cores at 80°C and 2000psi, and the amount of oil recovery was measured. From the experiments, it was observed that CWI could extract more crude oil than conventional water flooding in all salinities. In particular, the highest oil recovery was observed in the lowest salinity (61.2% in CWI and 42% during water flooding), indicating that by carbonating low-salinity water, oil recovery is enhanced by 20%. Moreover, the influence of salinity reduction on recovery enhancement was such that 9% of recovery improvement observed during conventional water flooding when salinity decreased from 40000 to 1000ppm. At the same time, this improvement was around 15% for CWI, suggesting that salinity reduction can be more effective in CWI rather than water flooding in recovery improvement. It was also found out that while recovery improvement and fines migration are both highly affected by water salinity, there is a synergy between the efficiency of CWI and onset of fines migration, which is one of the underlying mechanisms in oil recovery improvement during LSCWI into clay-containing sandstone reservoirs.

Comprehensive understandings of the influences of negative pressure on air-leakage and its driving mechanism are critical for controlling methane concentration during coal seam gas extraction. Laboratory experiments were conducted using an integrated apparatus to study the air-leakage process of coal seam gas extraction under different negative pressures. In addition, a coupled computational fluid dynamics-discrete element approach was used to simulate the process of air flow and particle transport in a natural coal fracture to understand the influential mechanism of negative pressure on air-leakage at the mesoscale. Experimental results show that with an increase in the absolute value of negative pressure, the air-leakage experiences three stages of increase, decrease and increase at Stage I, Stage II and Stage III, respectively. It is reported for the first time and in good agreement with field test data. From experimental and numerical results, at Stage I the air-leakage increases with the absolute value of negative pressure because there is no blockage in fractures around borehole. At Stage II, the further increased absolute value of negative pressure contributes to particles motion in fractures. It gradually leads to the formation of blockage structure composed of aggregated particles in fractures, and the decrease of fracture conductivity and air velocity. With the absolute value of negative pressure rising continuously, the contact forces between the aggregated particles increase. Therefore, the balance of the blockage structure tends to be broken, which helps to understand the air-leakage increase with the absolute value of negative pressure at Stage III. Between Stage II and Stage III, there is a valley point corresponding to the minimum air-leakage, which is important to the improvement of gas extraction performance. The contact forces on the aggregated soft particles are larger than those on the aggregated hard particles under the same negative pressure. Therefore, the blockage structure consisting of soft particles is much easier to be broken than that formed by hard particles. This explains why the absolute value of negative pressure corresponding to the valley point for hard coal model is larger than that for the soft coal model.

This paper focuses on investigating the dynamic behaviour of foam flows, including flow regimes, their transitions and pressure profiles in relation to foam characteristics (foam holdup and wetness) at different surfactant concentrations (0–500 ppm). The experiments cover a wide range of gas and water flowrates in a 4.3 m long vertical acrylic pipe with 44 mm internal diameter. Flow regimes and their underlying mechanisms are characterised through Power Spectral Density analysis of the associated pressure fluctuation signals, collected at 100 Hz frequency. A flow map is developed for foam flow in a vertical pipe based on the gas and liquid Webber numbers, representing different flow regimes. The results from this study reveal that, even at small concentrations, the surfactant attenuates flow fluctuations, as observed in the pressure data, resulting a relatively uniform flow compared with air-water flows. The results also indicate the promoting effect of surfactant on the flow transition from churn to annular flow at much lower gas velocities compared to air-water flows. The flow transition from slug to churn and churn to annular in foam flows is shown to be associated with an increase in foam wetness. The lowering effect of surfactant on the pressure gradient is most pronounced at lower gas rates. Increasing the gas rate in the foam flow encourages bubble breakup, leading to the formation of a denser foam, composed of smaller bubbles carrying more liquid in the lamella of the foam network. This therefore leads to a higher pressure gradient at higher gas rates.

The present work simulated a hypothetical 4D delta-canyon-fan depositional system using stratigraphic forward modelling (SFM) to: 1) investigate the differences and linkages of the sea-level control on the evolution of each sub-environment; 2) explain the evolution under the constraints of sea-level change from the perspective of channel activities. The SFM approach LECODE applied in this study combines an open-channel flow approach with a non-uniform sediment transport algorithm, with former to simulate water dynamics of turbidity currents and river flows and latter to simulate the transportation, deposition, and erosion of sediments. The input data is calibrated via sensitivity analysis and survey of analogue records. The results are compared with three sets of actual seismic data as verification. After introducing the general characteristics of the model, this study compares the influence of sea-level change on the delta, canyon, and fan, respectively, by analysing stratigraphic framework, the architecture of channel-levee complex, channel distribution and migration, sedimentation/erosion rate, and peak velocity. Moreover, a higher sediment supply case and a lower sediment supply case are compared to test the situation when sediment supply is less dominant. Finally, the influence of sea-level change on channel migration is discussed and the system evolution, especially the canyon evolution, is explained from the view of channel activities. The results show that sea-level control will be weakened from the delta to the fan via the canyon along with sediment transport. With higher sediment supply, the weakening is stronger. With lower sediment supply, the whole system is more sensitive to the sea-level change and this sensitivity lasts longer. The channel migration is more influenced by local topography, even adjacent topography, rather than sea-level change. The inner bank erosion near the canyon head is directly related to the shelf morphology. The translation and asymmetrical distribution of turbidity channels result in the translation and asymmetrical erosion of canyon bends. The insights extracted from this study could discriminate sea-level control on submarine canyon and fan instead of regarding them as an entirety of ultimate sink in source-to-sink research. Also, the integrated investigation with both qualified perspectives and quantified data could refine sequence stratigraphic concepts and provide a prototype for hydrocarbon exploration on high-sediment-supply river-fed delta-canyon-fan systems.

The petroleum industry uses high level dynamic simulations applied to geocellular models to guide forecasts of oil, gas and water production. Uncertainty in model choice and input variable selection is often addressed through large numbers of computationally slow Monte Carlo simulations designed around physics based models. Here, an alternate approach is proposed, which uses a relatively small amount of data and a reduced number of simulations of the high level physics model to train a fast (to evaluate) proxy or surrogate model based on a Polynomial Chaos Expansion. We give details of the theory and incorporated techniques, which significantly increase flexibility. Input variables (e.g. cell-by-cell variations in porosity and permeability) are sampled from unknown probability distributions and sensitivity analysis is based on low level proxy models. The theory is tested by developing proxy models to predict total gas production from a five-spot well configuration in the Hermitage area that taps into the Walloon Coal Measures of the Surat Basin in Queensland. Synthetic training data is simulated using commercial dynamic simulation software based on a high level physics model.

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.

A new sequence stratigraphic framework (SSF) for the Early–Late Jurassic Surat Basin, eastern Australia, is evolving. A second and third order framework based upon an integrated methodology of well-to-well correlations supported by well tied seismic data is being developed. The integration of an additional dataset (palynology) to test for regionally consistent sequence stratigraphic well correlations offers an improvement in defining sequence boundaries related to the geological timescale. The palynological data from 33 wells covering the north-east Surat Basin were extracted from the Queensland Digital Exploration (QDEX) open-file reports, some of which date back to the 1960s. These data were correlated and superposed on the SSF for age comparison. The dataset used in this study represents only a subset of all existing palynology information, as not all data are captured in QDEX. However, the palynology data in this exploratory study generally fits and supports the new SSF with only one exception, the reason for which is not understood at this stage. We recommend expanding this study to include more data because palynology can support stratigraphic interpretation, especially in wells that do not intercept, or have log data across, regional datums.

In the context of pre-tenement application studies, Monte Carlo simulations of steady state (initial) CO 2 injectivity for the Precipice Sandstone in the Surat Basin have been used together with discrete dynamic models to assess injection rate uncertainty. Such uncertainty analyses are used to guide exploration work programs. This paper considers an analysis of steady state injection rates based on a modified form of Darcy's Law, using parameter probability probability density functions (PDF) for 4 different tenement areas. Uncertainty in absolute permeability and upscaled permeability (as seen in an injection well) typically accounted for around 70% of variation in estimated steady-state injectivity. Uncertainty in gross thickness and net-to-gross ratio accounted for most of the remaining variation. Due to changes in depositional setting and depth, the P50 initial injectivity estimates for the Precipice Sandstone varies by an order of magnitude from 0.2 to 2.4 megatonne per anum (Mt/a) across the 4 areas. P10/P90 ratios were between 10 and 20 and are indicative of the relative immaturity of the technical assessment. Concepts including several wells will likely be required for industrial scale, multi-Mt/a developments. Dynamic well testing specifically to determine compartmentalisation and heterogeneity and the departure from steady state will be essential in designing and costing any field development plan. Therefore such data will be essential in any exploration or appraisal program.

The level of confidence in sub-surface containment related to potential industrial-scale injection of carbon dioxide (CO 2 ) is investigated in advance of applications for CO 2 exploration tenements. Evidence for seal retention pressures is evaluated based on hydrocarbon accumulations and hydrostatic gradients. Fracture propagation and fault reactivation pressures are also scoped. Evidence for vertical migration through a proposed seal is investigated through oil shows analysis. Analyses are synthesized and compared to required pressure retention performance, indicated by dynamic modeling, to give an overall view of pre-licensing, pre-drill containment confidence. The resultant uncertainty analysis is used to guide an exploration strategy.

A specific workflow to identify sites of sustaining CO2 injection rates of 1 Mt/a for decades was applied to the Gippsland Basin. Dynamic simulations attained injection rates of about 0.4-10 Mt/a (extreme cases). Permeability was the most important parameter determining injectivity. Total injected CO2 ranged from 10-34 Mt up to 130-240 Mt. Without a portion of the offshore, injectivity and capacity are reduced considerably. At the end of the injection period, modeled overpressure at the seal is less than retention pressures. In some cases, CO2 does not reach the seal, even after 1000 yrs. In other cases, seal is reached after the pressure begins to decline.

Twelve clastic core samples from the Walloon Coal Measures, Surat Basin were tested for disintegration in artificially produced fluids varying in ionic strength. XRD data confirm the presence of smectite (water sensitive clay) in the samples. Flow-through rock disintegration experiments demonstrate that the higher the concentration of smectite and soluble plagioclase is, the quicker rock disintegrates in artificial low ionic strength fluid. Pre-soaking of rocks with high ionic strength fluid reduces rock disintegration rate in low ionic strength fluids. This is explained by very strong clay-clay and clay-sand attraction forces, evidenced through zeta-potential measurements, which inhibit rock degradation. For the studied samples it is clear that rock disintegration rate is proportional to fluid velocity. Experimental rock disintegration data are fitted by a power erosion model with two adjusted parameters: fluid ionic strength and Reynolds number. The experimental results satisfactorily agree with theoretical data. Rock disintegration rates are calculated as released particle volume per thickness of interburden layer per day at a fixed Reynolds number and low ionic strength. The laboratory work suggests that keeping wells under strong ionic fluid during shut-in times and a reduction of water production rate will preserve rock integrity for a longer period of time.

Since the end of June 2008, carbon dioxide (CO 2 ) is being injected in the Stuttgart Formation at Ketzin, Germany as part o f the European Union’s CO2SINK project. The injection well (Ktzi 201) is roughly 50 and 100 m away from observation wells Ktzi 200 and Ktzi 202, respectively. CO 2 was detected at the closest observation well on the 15th of July 2008, approximately 20 days after injection commenced. Breakthrough at the Ktzi 202 well was recorded on March 21, more than 8 months after injection was initiated. Dynamic simulations of the injection and flow of CO 2 into the subsurface at Ketzin will be described. The three dimensional (3D) geological model was built based on a 3D seismic survey as well as logging and core analysis data. The formation consists of fluvial sandstone channels within a muddy flood plain at mean depth of 650 m within an anticlinal structure. The geological model uses a cell size of 20×20 m and a layer thickness of 0.5 m, resulting in a total of ∼7 million cells. The model is upscaled (i.e., coarsened) and the grid is refined locally in the zone comprising the injection and observation wells. This upscaled model has corner point geometry with 78×74×91 (525, 252) grid cells in X, Y, and Z directions. X and Y direction grid sizes around the wells are respectively 4 m and 5 m. Average grid size in Z direction is about 0.5 m. Following the upscaling of the geological or static model, a blackoil commercial streamline simulator was used to simulate the flow of injected CO 2 according to the actual injection rate history. The phase behavior of CO 2 and brine were described by blackoil pressure-volume-temperature (PVT) tables. The blackoil PVT was modeled by imposing brine properties to the simulator oil model and CO 2 properties to the simulator gas model. In this manner, solubility of CO 2 into water was taken into account. Salinity of the brine is represented by the appropriate density. Fluid properties (density, viscosity) are pressure dependent and isothermal (at reservoir temperature). The outcome of the simulation is the time for injected CO 2 to arrive at the observation wells and the history of bottom-hole pressures (BHP) as a function o f time that can be compared to measurements taken in the bottom of the injection well. History matching was performed by adjusting the permeability (along and across bedding) until model BHPs agreed with the measured ones. Permeability was chosen as history matching parameter because of its high degree of uncertainty and relies on the porosity/permeability relation derived from core measurements. Good agreement was obtained with a multiplicator of 0.1 applied to the permeability across and along bedding. Breakthrough time for the closest observation well was in good agreement with reality. However the breakthrough time at the most distant well was underestimated by several months. We believe that geological features at distances greater than 50 m from the injection well may be responsible for the mismatch and should be investigated further.

At the Ketzin test site significant differences of wellhead pressures and temperature anomalies have been recorded at two observation wells after the arrival of CO2. Analysis of the measured well temperature and pressure data, and the deduced fluid density data shows that two-phase fluid conditions are prevailing in the upper 400 m of the wells. Implications on reservoir monitoring and well logging are discussed.

In 2006, the CO2ReMoVe project funded by the European Commission was launched with the objectives of developing new and common methodologies and technologies to improve site based R&D for the monitoring, measurement and verification of the injection and storage of CO2 at multiple sites. The In Salah Gas Krechba Field Joint Industry Project has been in operation since 2004 when gas from several fields was put on production. To comply with export regulations, the high content of carbon dioxide (CO2), 1–10% in the produced gas is removed and re-injected down dip from the producing gas horizon, through three horizontal injection wells at approximately 1800 m below surface. Within the framework of CO2ReMoVe, this paper discusses the site characterization and the short term system performance for the In Salah Krechba field.Prior to the injection, the reservoir unit and the seals were characterized. The resulting geological (static) model is consistent with the information obtained from the drilling activities in 2004 and 2005 and from the reprocessed 3D seismic done by Compagnie Générale de Géophysique (CGG) in 2006. A fracture study carried out on information obtained from resistivity and acoustic images available on the Krechba field had shown the existence of an open fracture network oriented along the NE-SW direction parallel to the maximum stress direction.Typically, monitoring data serves as a calibration yardstick for the static model. It was therefore valuable information to detect the CO2 breakthrough at KB-5, a suspended well located 1.7 km away from the KB-502 injector well. Tracer analysis confirmed the CO2 detected at KB-5 came from KB-502. A multi-phase, multi-component compositional simulator specially designed for CO2 sequestration (ECLIPSE11Mark of Schlumberger. 300 with the CO2SOL option) was used to simulate and predict the properties of the injected carbon dioxide as well as that of the gas in place (mainly methane) and of the saline aquifer. History matching was used to calibrate the dynamic model by iteratively modifying parameters until a satisfactory match between model results and field measurements was obtained. The resulting dynamic model is used for short term predictions of the behaviour of injected CO2. The history matching parameters are the fracture porosity, permeability and matrix permeability (difficult to measure permeability in a fractured medium). In each iteration, the simulated bottomhole pressures, gas (CO2) injection rates were compared against field data as well as the CO2 breakthrough time at KB-5. Iterations were repeated until a good match was obtained.Predictive simulation results indicate that CO2 would reach the northern part of the gas field in 2010 and would spread out over an area including production wells in 2015, both in the northern (KB-502, KB-503) and the eastern part (KB-501) of the gas field.Although a good match has been obtained in the history matching process, some observed discrepancies could still not be explained only by fluid dynamics. Possibly, the application of coupled fluid flow and geomechanical simulations would aid in explaining the remaining discrepancies.

The geothermal resources of most European countries have been estimated and compiled in the recently published Atlas of Geothermal Resources in Europe, a companion volume to the Atlas of Geothermal Resources in the European Community, Austria and Switzerland. Publication of this Atlas comes at a time when the promotion of a sustainable and non-polluting energy is high on the agenda of local energy suppliers, municipal administrations and all European governments. The participating countries are: Albania, Austria, Belarus, Belgium, Bosnia-Herzegovina, Bulgaria, Croatia, Czech Republic, Denmark, Estonia, Finland, France, Germany, Greece, Hungary, Iceland, Ireland, Italy, Latvia, Lithuania, Netherlands, Poland, Portugal, Romania, Russia, Slovakia, Slovenia, Spain, Sweden, Switzerland, Ukraine and the UK. A volumetric heat content model for porous reservoirs was the basis for calculating the resources, assuming that exploitation of the geothermal resources would take place in a doublet well system. The geothermal reservoirs are defined in a set of 4 maps, by depth, thickness, temperature and resources. The assessment methodology is simple and is based on a small number of parameters so that regions with very limited data coverage can also be evaluated. An example is given in this paper of the eastern North German Basin. The maps presented in the Atlas permit a first order evaluation of the geothermal potential in terms of technical and economic viability. This uniform procedure applied to all countries and regions allows comparisons and serves as a guide for setting priorities and planning geothermal development. This Atlas also helps in the search for appropriate partners for international cooperation in geothermal exploration in Europe.

A multidisciplinary approach to make generation of geothermal electricity possible in the NE German basin (NEGB) wasinitiated in 2000. To attain this goal, formation fluids from the 4-km-deep Rotliegend rocks (a known gas reservoir) of the NEGB need to be extracted and their geochemistry determined. An in situ laboratory was established by opening and deepening the former gas well GrSbk 3/90. Hydraulic tests and stimulation experiments focussed on the aeolian sandstones. In situ samples of the 150 °C deep fluids contain high amounts of dissolved solids (salinity: 265 g/l). The most important inflows of geothermal water were detected in the Permo-Carboniferous volcanic rocks and not, as anticipated, from overlying sandstones. Furthermore, the geochemical investigations of the fluid samples indicate that they originated in the andesitic volcanic rocks.

We present 56 new heat flow values from the intracratonic Parana Basin in southern Brazil. This large basin is filled with up to 5 km of Paleozoic and Mesozoic sedimentary rocks. In the Late Jurassic-Early Cretaceous a great igneous event capped most of the basin surface with flood basalts up to 1700 m thick. Geothermal gradients computed from 79 deep exploration boreholes range from 20 K km -1 to 30 K km -1 with the lower gradients generally located in the central part of the basin. Thermal conductivities were determined on 247 core samples. The harmonic mean thermal conductivity of the section encountered by the boreholes decreases from 3.0 W m -1 K -1 at the eastern basin margin to 2.0 W m -1 K -1 in the basin center ; this variation is related to the thickening of the basalt cap toward the basin center. Surface heat flow values for the 56 sites range from 40 mW m -2 to 75 mW m -2 , with larger and more variable values (50-70 mW m -2 ) occurring along the eastern margin of the basin in the region without basalt cover. The heat flow in the central part of the basin (40-50 mW m -2 ) is less than that on the basin margin by about 15 mW m -2 and is more uniform. We discount advective effects as an explanation of the heat flow pattern because if a topographically driven flow system existed, it would diminish heat flow in the elevated recharge area along the basin margin and augment heat flow in the discharge area along the basin axis, opposite to what is observed. Wholly conductive models show that larger-scale thermal conductivity contrasts produced by the flood basalts do not refract significant heat into the surrounding higher-conductivity sedimentary section on the periphery of the basalts. Other model calculations show that the heat flow at the surface reflects the heat input from the basement with only minor, if any, redistribution within the basin. We conclude that the thermal data indicate a dominantly conductive thermal regime within the basin and that the observed heat flow pattern is not likely to result from intrabasinal causes. The observed pattern likely reflects the larger-scale thermal structure of the lithosphere of this region, developed at the time the flood basalts were generated and extruded.

We investigate the effects of the cooling of intrusive and extrusive igneous bodies on the temperature history and surface heat flow of the Parana Basin. The Serra Geral igneous event (130-135 Ma) covered most of this basin with flood basalts. Associated with this event numerous sills and dykes intruded the sediments and basement, and extensive underplating may have occurred in the lower crust and upper mantle beneath the basin. We develop an analytical model of the conductive cooling of tabular intrusive bodies and use it to calculate temperatures within the sediments as a function of time since emplacement. Depending on the thickness of these igneous bodies and the timing of sequential emplacement, the thermal history of a given locus in the basin can range from a simple extended period of higher temperatures to multiple episodes of peak temperatures separated by cooling intervals. The cooling of surface flood basalts, sills and dykes is capable of maintaining temperatures above the normal geothermal gradient temperatures for a few hundred thousand years, while large-scale underplating may influence temperatures for up to 10 million years. We conclude that any residual heat from the cooling of the Serra Geral igneous rocks has long since decayed to insignificant values and that present-day temperatures and heat flow are not affected. However, the burial of the sediments beneath the thick basalt cap caused a permanent temperature increase of up to 50 degrees C in the underlying sediments since the beginning of the Cretaceous.

This paper reports the well design, drilling and completion operation as well as the coring technique applied in the CO2SINK project. Three boreholes, one injection well and two observation wells have been drilled to a total depth of about 800 m. 200 m of recovered 6” core material has been real-time analysed in a research field lab. The wells have been completed as “smart” wells, containing a variety of permanently installed down-hole sensors for the continuous monitoring of the CO2 in the reservoir. All wells were cased with stainless final casings equipped with pre-perforated sand filters in the reservoir zone and wired on the outside with fiber-optical and multi-conductor copper cables. The reservoir casing section is externally coated with a fiber-glass-resin wrap for electrical insulation.

This study examines the suitability of thermal methods, especially DTS (Distributed Temperature Sensing) cables (in the annulus or behind casing) to monitor the fate of injected CO2 for emissions reduction purposes. The static temperature signal of CO2 stored in pores of sandstone and claystone examples is calculated as a function of porosity, CO2 saturation, and CO2-filled reservoir thickness. The dynamic temperature signal associated with the movement of CO2 in the well and the porous rock is discussed and results of numerical simulations are presented. The detectability of these temperature signals is assessed and found to be useful in detecting leakage over short time intervals and saturation changes in the storage reservoir over the longer term.

Since April 2004, preparatory work prior to CO2 injection has been conducted in the CO2SINK Project, the European Union's first research and development activity on the in-situ testing of geological storage of CO2 near the town of Ketzin, Germany. Carbon dioxide will be injected into a saline aquifer of the Triassic Stuttgart Formation in an anticlinal structure of the northeast German Basin. The drilling of one injection and two observation wells will commence at the end of 2006. The predrilling phase focuses on the baseline geological parameters of the anticline. The Stuttgart Formation is lithologically heterogeneous; it consists of sandy channel-(string)-facies rocks, with good reservoir properties alternating with muddy flood-plain-facies rocks of poor reservoir quality. Playa-type rocks form the immediate cap rock above the CO2SINK reservoir. A geostatistical approach has been applied to describe the reservoir architecture between and beyond well control. This model forms the basis for the generation of reservoir-dynamic models of CO2 injection that assist in the planning of injection operations and in the understanding of CO2 plume evolution. A verification of the geometry of the reservoir and the structural situation of its overburden is expected from a three-dimensional baseline seismic survey that was conducted in the autumn of 2005. Laboratory experiments under simulated in-situ conditions were performed to evaluate the geophysical signature of rocks saturated with CO2. The chemical composition of the groundwater and the CO2 flux in the soil were analyzed across the Ketzin anticline, providing the baseline for a monitoring program during and after injection of CO2, targeted at the detection of potential CO2 leakage from the storage reservoir.

Temperatures of 100°C are measured at 3 km depth in a well located on the resurgent dome in the center of Long Valley Caldera, California, despite an assumed >800°C magma chamber at 6–8 km depth. Local downflow of cold meteoric water as a process for cooling the resurgent dome is ruled out by a Peclet-number analysis of temperature logs. These analyses reveal zones with fluid circulation at the upper and lower boundaries of the Bishop Tuff, and an upflow zone in the metasedimentary rocks. Vertical Darcy velocities range from 10 to 70 cm a −1 . A 21-km-long geoelectrical profile across the caldera provides resistivity values to the order of 10 0 to >10 3 Ωm down to a depth of 6 km, as well as variations of self-potential. Interpretation of the electrical data with respect to hydrothermal fluid movement confirms that there is no downflow beneath the resurgent dome. To explain the unexpectedly low temperatures in the resurgent dome, we challenge the common view that the caldera as a whole is a regime of high temperatures and the resurgent dome is a local cold anomaly. Instead, we suggest that the caldera was cooled to normal thermal conditions by vigorous hydrothermal activity in the past, and that a present-day hot water flow system is responsible for local hot anomalies, such as Hot Creek and the area of the Casa Diablo geothermal power plant. The source of hot water has been associated with recent shallow intrusions into the West Moat. The focus of planning for future power plants should be to locate this present-day flow system instead of relying on heat from the old magma chamber.