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Describing cuttings is routine work for wellsite geologists on a drill rig. The time-consuming nature of this analysis and the lack of consistency of the results between different interpreters are the two major concerns for this task. Wellsite geologists spend approximately 70% of their time on cuttings descriptions. In addition, 2 to 3 wellsite geologists are generally assigned to a drilling campaign, and they are replaced at the end of a shift. ML/AI techniques have the potential to solve these issues because of their advantages in prediction speed, objectivity, and consistency. The authors’ aim is to automate the task of cuttings descriptions with ML/AI techniques. We are targeting four lithologies, namely sandstone, mudstone, volcanic (volcanic rocks), and carbonate (carbonate rocks). The cuttings were collected from six wells in the Browse Basin (Australia). Of these four lithologies, a total of 1978 cuttings images were taken under a stereomicroscope. We chose a semantic segmentation technique using Convolutional Neural Network (CNN) algorithms to perform the image classification task. The images were labelled using the open-source annotation software. This annotated data were used for the network training. The labelled images were split into training, validation, and test sets. The accuracy of the trained model was evaluated using the intersection-over-union metric (IOU). The mean IOU of the final model on the validation dataset was 82.3%. Prediction results on the cuttings that are represented by single lithologies are qualitatively very accurate. On the other hand, the prediction for the non-typical lithology (e.g., siltstone, dark-colored volcanic rocks, mixed lithology samples) has room for improvement. The fragments with similar textures (e.g., dark colored volcanic and dark mudstone) are complex for the CNN to identify. The final goal of our project is not only the lithology identification but also the quantitative estimation of lithology abundances in the cuttings. Additional model improvements, such as hyperparameter optimization and significantly more training data, are required to accomplish this task successfully. The trained model for cuttings description has the potential to realize quantitative and high-speed cuttings description. Well-trained AI/ML models have the potential to assist well site geologists by automating the cuttings description process simplifying, speeding up and improving the consistency on the rig floor.

Correct lithofacies interpretation sourced from wireline log data is an essential source of prior information for joint seismic inversion for facies and impedances, among other applications. However, this information is difficult to interpret or extract manually due to the multivariate and high dimensionality of wireline logs. Facies inference is also challenging for traditional clustering-based approaches because pervasive compaction trends affect a number of petrophysical measurements simultaneously. Another common pitfall in automated clustering approaches is the inability to account for underlying diagenetic processes that correlate with depth. Here, we address these challenges by introducing a rock-physics machine learning toolkit for joint litho-fluid facies classification. The litho-fluid types are inferred from the borehole data within the objective framework of a maximum-likelihood approach for latent facies variables and rock-physics model parameters, explicitly accounting for compaction and depth effects. The inference boils down to an expectation-maximization (EM) algorithm with strong spatial coupling. Each litho-fluid type is associated with an instance of a particular rock-physics model with a unique set of fitting parameters, constrained to a physically reasonable range. These fitting parameters in turn are inferred using bound-constrained optimization as part of the EM algorithm. Outputs produced by the toolkit can be used directly to specify the necessary prior information for seismic inversion, including per-facies rock-physics models and facies proportions. We present an example application of the tool to real borehole data from the North West Shelf of Australia to illustrate the method and discuss its characteristic features in depth.

We present the results of a low‐frequency study of Mancos shale, where we first elaborate a stress–strain methodology of laboratory low‐frequency experiments to estimate the elastic moduli of shales, and then apply this methodology to investigate the influence of partial water saturation on the elastic and anelastic parameters, velocities and P‐wave anisotropy of Mancos shale. We also analyse the applicability of the anisotropic Gassmann theory for predictions of the stiffness tensor components of the water‐saturated shale with non‐expandable clay content presented in our case by illite (33%) and chamosite (9.1%) minerals. The effect of water saturation was studied using two samples drilled in vertical and parallel directions to the formation bedding. The experiments were carried out at a confining pressure of 10 MPa in the frequency range from 0.1 to 100 Hz. Prior to measurements, the samples were saturated in desiccators at six different values of relative humidity ranging from 9% to 97.5%. The results of our study demonstrate a reduction of Young's modulus and P‐wave anisotropy with saturation accompanied by a decrease in shear stiffnesses. The latter indicates the inapplicability of the anisotropic Gassmann theory to Mancos shale. Our measurements of attenuation carried out on the vertical and horizontal samples saturated at a relative humidity of 97.5% revealed prominent attenuation peaks associated with partial saturation. We showed that the measurement results of the attenuation and Young's modulus dispersion are consistent with the causality principle presented by the Kramers–Kronig relations.

In rock physics one of the important purposes of the determination of P- and S-wave velocities is to obtain the elastic constants and anisotropy parameters. This method is standardised in American ...

Predicting the mineralogical composition of shales is crucial for drilling operations related to hydrocarbon exploration/production as well as for the assessment of their sealing capacity as hydroc...

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

The ultrasonic measurements technique is well established to measure the elastic properties of rocks in the laboratory for seismic and well-log data interpretation. The key components of every laboratory ultrasonic setup are piezoelectric transducers, which generate and register elastic waves in rock samples. The elastic properties of rocks are determined through the velocities of elastic waves, which are measured by the times of the waves' travel from the source to the receiver transducer. Transducers can be specifically designed to generate P-waves (P-transducers) or S-waves (S-transducers). In limited studies, the measurement of P-wave velocities with S-transducers is mentioned. Such measurement is possible due to specific aspects of the operation of S-transducers. Namely, S-transducers are known to emit parasitic low-energy P-waves, which travel faster than high-energy S-waves and hence can be registered. However, no justification or elaboration of this method of measuring P-wave velocities was reported. To fill this gap, we first compare P-wave velocities measured with S-transducers against P-wave velocities measured with P-transducers in different rocks and materials. We show that the discrepancy between velocities measured with the two methods in homogeneous materials is less than 1% and can be up to 4% for natural rocks. Second, we numerically simulate the operation of S-transducers, show that parasitic P-waves have a dipole structure, and explain how the receiver transducer can register this compressional dipole. Finally, we use laser doppler interferometry to measure the displacement of the free surface of a sample caused by elastic waves emitted by the source S-transducer. We observed the dipole structure of the sample's surface displacement upon P-wave arrival on the surface.

Shales have always been a difficult target for drilling of deviated and horizontal wells. In the presence of azimuthal stress fields, inclined boreholes in smectite-rich shales exhibit geomechanical instabilities and can result in borehole failure. The complex geology of the major gas fields in the Northern Carnarvon Basin on the North West Shelf of Australia makes it necessary to drill deviated wells through the smectite-rich shale seal extending more than 1 km in thickness. Predicting the mineralogical composition of shales in the area is therefore crucial for the success of drilling operations related to hydrocarbon exploration and production. Here we introduce a novel workflow that combines seismic data, well logs, and laboratory measurements to rapidly infer smectite content in shale. The workflow is applied to the Duyfken 3D seismic survey in the central part of the Northern Carnarvon Basin. The results of our quantitative interpretation are verified against the laboratory X-ray diffraction measurements from the test well that was not used for interpretation, and they match the test data well within the determined uncertainty bounds.

Summary Predicting the mineralogical composition and hydraulic permeability of shales is of utmost importance for drilling operations related to hydrocarbon exploration/production and for the assessment of their sealing capacity as hydrocarbon or CO2 barriers, respectively. Despite the importance of inferring these two parameters for industrial applications few methods have been developed. Here we introduce a workflow to infer shale composition at a regional scale and asses its background hydraulic permeability that combines seismic data, well logs, and laboratory measurements. The workflow is applied to the Duyfken 3D seismic survey acquired in the central part of the Northern Carnarvon Basin where a regional smectite-rich seal with a thickness of more than 1 km is hindering hydrocarbon exploration. Results of the quantitative seismic interpretation for shale mineralogical composition are verified against laboratory XRD measurements from a test well that was not used for interpretation. The results have a good match to test well data within the determined uncertainty bounds. Using these results background permeability of shales is estimated using empirical relationship derived from the experiments on artificial shales.

[enter Abstract Body]The CSIRO In-Situ Laboratory has been a world first injection of CO2 into a large faulted zone at depth. A total of 38 tonnes of CO2 was injected into the F10 fault zone at approximately 330 m depth and the process monitored in detail. The site uses a well, Harvey-2, in SW Western Australia (the South West Hub CCS Project area). The top 400 m section of Harvey-2 was available for injection and instrumentation. An observation well, ISL OB-1 (400 m depth) was drilled 7 m to the north east of Harvey-2. ISL OB-1 well was cased with fibreglass to provide greater monitoring options. The CSIRO In-Situ Laboratory was designed to integrate existing facilities and infrastructure from the South West Hub CCS Project managed by the West Australian Department of Mines, Industry Regulation and Safety. While new equipment was deployed for this specific project, the site facilities were complemented by a range of mobile deployable equipment from the National Geosequestration Laboratory (NGL). The geology of the area investigated poses interesting challenges: a large fault (F10) is estimated to have up to 1000 m throw overall, the presence of packages of paleosols rather than a contiguous mudstone seal, and a 1500 m vertical thickness of Triassic sandstone as the potential commercial storage interval. This unique site provides abundant opportunities for testing more challenging geological environments for carbon storage than at other sites. While details of this first project are described elsewhere, lessons were learned during the development and execution of the project. A rigorous risk register was developed to manage project risk, but not all events encountered were foreseen. This paper describes some of the challenges encountered and the team’s response. Relocation of the project site due to changes in landholder ownership) and other sensitivities resulted in the need for rapid replanning of activities at short notice resulting in the development of the site at Harvey-2. The relocation allowed other research questions to be addressed through new activities, such as the ability to consider a shallow/controlled release experiment in an extensive fault zone, but this replanning did cause some timing stress. The first test at the In-Situ Laboratory was reconfigured to address some of those knowledge gaps that shallow/controlled release experiments had yet to address. Novel approaches to drilling and completing the monitoring well also threw up unanticipated difficulties. Loss of containment from the wellbore also posed significant challenges, and the team’s response to this unintended release of gas and water from the monitoring well at the conclusion of the field experiment will be discussed. Other challenges that we encountered, their impacts, and our response are also catalogued here (Table 1 and below) to enable broad knowledge exchange.

The CSIRO In-Situ Laboratory Project (ISL) is located in Western Australia and has two main objectives related to monitoring leaks from a CO2 storage complex by controlled-release experiments: 1) improving the monitorability of gaseous CO2 accumulations at intermediate depth, and 2) assessing the impact of faults on CO2 migration. A first test at the In-situ Lab has evaluated the ability to monitor and detect unwanted leakage of CO2 from a storage complex in a major fault zone. The ISL consists of three instrumented wells up to 400 m deep: 1) Harvey-2 used primarily for gaseous CO2 injection, 2) ISL OB-1, a fibreglass geophysical monitoring well with behind-casing instrumentation, and 3) a shallow (27 m) groundwater well for fluid sampling. A controlled-release test injected 38 tonnes of CO2 between 336-342 m depth in February 2019, and the gas was monitored by a wide range of downhole and surface monitoring technologies. CO2 reached the ISL OB-1 monitoring well (7 m away) after approximately 1.5 days and an injection volume of 5 tonnes. Evidence of arrival was determined by distributed temperature sensing and the CO2 plume was detected also by borehole seismic after injection of as little as 7 tonnes. Observations suggest that the fault zone did not alter the CO2 migration along bedding at the scale and depth of the experiment. No vertical CO2 migration was detected beyond the perforated injection interval; no notable changes were observed in groundwater quality or soil gas chemistry during and post injection. The early detection of significantly less than 38 tonnes of CO2 injected into the shallow subsurface demonstrates rapid and sensitive monitorability of potential leaks in the overburden of a commercial-scale storage project, prior to reaching shallow groundwater, soil zones or the atmosphere. The ISL is a unique and enduring research facility at which monitoring technologies will be further developed and tested for increasing public and regulator confidence in the ability to detect potential CO2 leakage at shallow to intermediate depth.

Understanding of shales elastic properties behaviour with saturation changes is important for geological storage of nuclear waste, CO2 sequestration as well as for development of conventional and unconventional shale oil and gas reservoirs. Existing data describing effects of saturation on elastic properties of shales are sparse and contradictory. To improve understanding of the effects of changing water content on elastic properties in shales, we conduct an experimental study on Opalinus shale samples. We measure vertical and horizontal ultrasonic P- and S-wave velocities of the same set of samples with controlled water content. The measured velocities are used to calculate components of elastic stiffness tensor in the shale at different saturations assuming its vertical transverse isotropy. Obtained results show increasing C11 and decreasing C33 with drying of the samples. Moreover, we observe 80% and 60% increase of shear moduli C44 and C66, respectively, with reduction of the water content from 5.5% weight in the preserved state to 0.3%. Conventional rock physics models are not designed to explain the observed dynamics. Here we perform a theoretical investigation of the influence on the shale moduli of following factors: (1) mechanical softening of the rock with the decrease of water saturation; (2) shrinkage of clay leading to reduction of porosity; (3) chemical hardening of clay particles; and (4) enhancing stiffness of contacts due to removing of water between clay particles.

Understanding of compaction trends of elastic and hydraulic properties in anisotropic shales is crucial for exploration of energy resources, ecological disposal of nuclear waste, and hydrogeological applications. However, complexity of the natural shale mineralogy and lack of quality data available for analysis results in poor knowledge of these compaction trends. Careful control over the shale mineralogy, pore fluid composition and applied stresses allows us to simulate the natural environments and acquire quality data on the properties of artificial shales. Here for the first time we present methodology and describe a setup that allows simultaneous acquisition of all five independent elastic constants and extremely low hydraulic permeability values of transversely isotropic artificial shale samples during mechanical compaction experiments (porosity decrease from 40% to 10%). Hydraulic permeabilities of artificially compacted samples are comparable to the ones of natural shales. Permeability drops exponentially with compaction. Silt fraction and clay mineralogy are the two key parameters that are responsible for broad variations of permeability in shales with the same porosity. We provide analytical equations that allow calculating permeability if porosity and silt fraction are known. Elastic constants of clay matrix exhibit positive linear trends with the porosity decrease. Small variations in clay mineralogy have a minor effect on absolute values of elastic coefficients or anisotropy but lead to noticeable increase of the compressional (VP) to shear (VS) velocities ratio at the same porosity. Finally, strong correlations (R2 above 0.95) of the hydraulic permeability with acoustic impedance and VP/VS ratio are observed for all the prepared samples.

Overburden shales that overlie and seal hydrocarbon reservoirs usually exhibit polar anisotropy, also called Vertical Transverse Isotropy (VTI). This anisotropy is important for correct seismic inversion, seismic-to-well ties as well as having geomechanical implications. P-wave anisotropy cannot usually be determined from a vertical well unless a walkaway vertical seismic profile (VSP) has been obtained, however, such measurements are still rare. S-wave anisotropy though can be estimated from logs if the speed of sound in mud and the Stoneley wave velocity in the shale are known. Then, the P-wave anisotropy can be computed using theoretical models or empirical trends. The Stoneley wave velocity is nowadays routinely measured by sonic tools and, if a reliable mud velocity is known, the horizontal shear wave velocity (parallel to and polarised in the bedding plane) can be estimated. Thomsen’s gamma parameter for S-wave anisotropy can then be calculated. If mud velocity is not known, the horizontal shear wave velocity can be obtained using calibration in an isotropic interval. Using this method, we analyse the VTI anisotropy in the Torosa-6 well in the Caswell Sub-basin of the Browse Basin, Australia. Torosa-6 drilled through the Jamieson and Echuca Shoals shaly formations where Vclay reaches ~75%. Elastic anisotropy of the shaly Jamieson and Echuca Shoals Formations has been analysed. Thomsen’s gamma shows a good correlation with the clay fraction in each of these formations. However for the same clay fraction, anisotropy is about 20% higher in the Jamieson Formation compared to the Echuca Shoals. This Jamieson Formation contains up to 15% of smectite, and we are investigating how this may lead to higher levels of VTI anisotropy compared with illitic clays predominant in the Echuca Shoals Formation.

Shales play an important role in many engineering applications such as nuclear waste, CO2 storage and oil or gas production. Shales are often utilized as an impermeable seal or an unconventional reservoir. For both situations, shales are often studied using seismic waves. Elastic properties of shales strongly depend on their hydration, which can lead to substantial structural changes. Thus, in order to explore shaly formations with seismic methods, it is necessary to understand the dependency of shale elastic properties on variations in hydration. In this work, we investigate structural changes in Opalinus shale at different hydration states using laboratory measurements and X-ray micro-computed tomography. We show that the shale swells with hydration and shrinks with drying with no visible damage. The pore space of the shale deforms, exhibiting a reduction in the total porosity with drying and an increase in the total porosity with hydration. We study the elastic properties of the shale at different hydration states using ultrasonic velocities measurements. The elastic moduli of the shale show substantial changes with variations in hydration, which cannot be explained with a single driving mechanism. We suggest that changes of the elastic moduli with variations in hydration are driven by multiple competing factors: (1) variations in total porosity, (2) substitution of pore-filling fluid, (3) change in stiffness of contacts between clay particles and (4) chemical hardening/softening of clay particles. We qualitatively and quantitatively analyse and discuss the influence of each of these factors on the elastic moduli. We conclude that depending on the microstructure and composition of a particular shale, some of the factors dominate over the others, resulting in different dependencies of the elastic moduli on hydration.

The nanoscale elastic properties of moist clay minerals are not sufficiently understood. The aim of the present study was to understand the fundamental mechanism for the effects of water and pore size on clay mineral (K+-smectite) elastic properties using the General Utility Lattice Program (GULP) with the minimum energy configurations obtained from molecular dynamics (MD) simulations. The simulation results were compared to an ideal configuration with transversely isotropic symmetry and were found to be reasonably close. The pressures computed from the MD simulations indicated that the changes due to water in comparison to the dry state varied with the water content and pore size. For pore sizes of around 0.8–1.0 nm, the system goes through a process where the normal pressure is decreased and reaches a minimum as the water content is increased. The minimum normal pressure occurs at water contents of 8 wt.% and 15 wt.% for pore sizes of around 0.8 nm and 1 nm, respectively. Further analyses of the interaction energies between water and K+-smectite and between water and water revealed that the minimum normal pressure corresponded to the maximum rate of slope change of the interaction energies (the second derivative of the interaction energies with respect to the water content). The results indicated that in the presence of water the in-plane stiffness parameters were more correlated to the pressure change that resulted from the interplay between the interactions of water with K+-smectite and the interactions of water with water rather than the water content. The in-plane stiffness parameters were much higher than the out-of-plane parameters. Elastic wave velocities for the P and S waves (VP and VS) in the dry K+-smectite with a pore size of ~1 nm were calculated to be 7.5 and 4.1 km/s, respectively. The P and S wave velocity ratio is key in the interpretation of seismic behavior and revealed that VP/VS = 1.64–1.83, which were values in favorable agreement with the experimental data. The results might offer insight into seismic research to predict the mechanical properties of minerals that are difficult to obtain experimentally and can provide complimentary information to interpret seismic surveys that can assist gas and oil exploration.

The ultrasonic pulse transmission (UPT) method has been the gold standard for laboratory measurements of rock elastic properties for decades, and it is used by oil and gas industry and service companies routinely. In spite of the wide acceptance and use of the UPT method, experimentalists are still looking for ways to further extend the limits of its applicability and to improve its state-of-the-art practices. One of the problems that limits wider application of the method is the length of the standard samples used (approximately 40–100 mm). This is a crucial limitation either in the case of a damaged core when preparation of a standard size sample is impossible or in the case when an ultrasonic experiment is combined with saturation or desiccation processes that might be extremely time-consuming on the long samples. On the other hand, thinner samples are not typically used due to the implication of inhomogeneity of stress fields inside and whereas few results of the measurements on thin disc samples have been reported in the literature, detailed justifications of the procedures have not been done yet. To fill this gap, we compare ultrasonic velocities measured at confining stresses up to 50 MPa done on standard and thin samples with lengths of 60 and 15 mm, respectively. First, we evaluate a new developed experimental setup for ultrasonic measurements on thin discs and develop a detailed experimental procedure. Then, we use finite-element modeling to numerically simulate stress fields in both types of samples. Finally, we compare the ultrasonic velocities measured on the thin discs and on standard samples and determine how to obtain reliable elastic properties on thin samples.

The In-Situ Laboratory Project (In-situ Lab) entails a configuration of wells at approximately 400 m depth for monitoring the controlled release of CO2 in a fault zone at the South West Hub CCS Fla...

The physics of gas uptake in coal constrains the feasibility of coal seam gas extraction and carbon sequestration in coal measures. While X-ray tomography using xenon as an X-ray opaque tracer gas has been used in the past to study gas uptake in coal specimens, synchrotron sources enable high-resolution micro-tomography datasets of high quality to be acquired in minutes adding the ability to quantify the dynamics of gas sorption over time in five coals of similar rank on the microscopic scale. In the present work we describe a synchrotron micro-computed-tomography (micro-CT) study of gas uptake in coal using Xe, Kr and CO2 gases. Measurement of gas uptake over time for Xe and Kr in different specimens and of CO2 induced swelling are reported, together with an analysis of gas diffusion profiles and their correspondence to those expected from diffusion models.The rate of penetration was CO2 > Kr > Xe in all cases, though the rates of penetration varied enormously between different coals. In some cases even 2 months was not enough to allow the Xe to equilibrate fully. The gas distribution was also shown to respond rapidly to flushing with CO2.

Summary We present a methodology and describe a set-up that allows simultaneous acquisition of all five elastic coefficients of a transversely isotropic (TI) medium and its permeability in the direction parallel to the symmetry axis during mechanical compaction experiments. We apply the approach to synthetic shale samples and investigate the role of composition and applied stress on their elastic and transport properties. Compaction trends for the five elastic coefficients that fully characterize TI anisotropy of artificial shales are obtained for a porosity range from 40 per cent to 15 per cent. A linear increase of elastic coefficients with decreasing porosity is observed. The permeability acquired with the pressure-oscillation technique exhibits exponential decrease with decreasing porosity. Strong correlations are observed between an axial fluid permeability and seismic attributes, namely, VP/VS ratio and acoustic impedance, measured in the same direction. These correlations might be used to derive permeability of shales from seismic data given that their mineralogical composition is known.

A good consistence between the grand canonical Monte Carlo (GCMC) simulation results and the adsorption experimental measurements is an important precondition to reveal the shale gas adsorption mechanisms by the GCMC method. To better link the simulations and the experiments, we investigated the expression of the excess adsorption amount and the reasonability of selecting the critical parameters by performing the GCMC simulations of CH4 in the Na-Montmorillonite simulation cell with the pore size of 4 nm at the temperature of 90 °C under varying pressures. It is found that the excess adsorption amount in the nanopore in the simulations and between the simulations and the experiments are comparable by expressing it in per unit surface area of the adsorbent. The accessible volume probed by the corresponding gas molecule is the theoretical value of the free volume, and the determination of the bulk gas density from the GCMC method, which keeps the same method with the calculation of the absolute loading number of gas molecules, will eliminate the system error. We expect the findings are useful in the further investigation on the shale gas adsorption mechanisms by combing the GCMC simulations and the adsorption experiments.

Accurate pore-pressure interpretation and prediction play important roles in understanding the sedimentary history of a basin and in reducing drilling hazards during hydrocarbon exploitation. Unlike typical reservoir rocks, in which pore pressures can be directly measured, pore pressures in shale must be inferred via their state of compaction. We have used the shale acoustic properties to accomplish this. Shale P- and S-wave velocities were first calculated using an anisotropic differential effective medium model. This model was built using elastic properties of wet clay mineralogy, and the total porosity of the shale was obtained from basic open-hole well-log measurements. These simulated shale velocities were systematically higher than sonic velocities observed on a test data set from a Gulf of Mexico well, penetrating a 1200 m vertical section of overpressured shale. The difference between the modeled velocities and the sonic measurements was then evaluated to estimate the abnormal pore pressure based on an exponential relationship between the pore pressure and the ratio of measured to modeled velocity. Using a reasonable exponent, the predicted pore pressure was shown to be in good agreement with direct pore-pressure measurements either made in adjacent sand layers that are thought to be in pressure equilibrium with the shales or inferred from drilling mud weights.

Sonic [Formula: see text] ratio obtained from full-waveform acoustic logs in conventional sandstone reservoirs is known to be sensitive to the presence of gas, and it is regarded as a potential diagnostic tool for saturation discrimination. However, it is not known if such a saturation diagnostic tool will be applicable in unconventional reservoirs, such as in gas-saturated shales. We have analyzed the monopole and dipole waveform logs acquired from a shale gas exploration well in the Cooper Basin, South Australia. The depth interval of interest is 300 m thick, and it intersects three shale units in which the two underlying formations contain gas saturation of more than 30% and are identified as the primary exploration targets. We use the statistical average method to extract the [Formula: see text]- and the [Formula: see text]-wave attenuation profiles and obtain an average [Formula: see text]-wave quality factor of [Formula: see text] and [Formula: see text]-wave quality factor of [Formula: see text]. The gas saturation of the lithological layers having [Formula: see text] is appreciably larger than the gas saturation of the others having [Formula: see text]. The net difference indicates that the saturation is a dominant factor in controlling the [Formula: see text] ratio in these shale formations. Based on the criterion [Formula: see text], we identify the intervals with high gas potential. This result is in good agreement with the prediction from an independently obtained saturation log based on petrophysical analysis. Furthermore, we found that the [Formula: see text] ratio can be jointly interpreted with the [Formula: see text] ratio to differentiate between the saturation and the lithology effects for a shale reservoir interbedded with sandstone layers. Our results underpin the concept of using the [Formula: see text] ratio as a hydrocarbon saturation indicator and provide insights into application of this technique for shale gas detection.

Qualitative and quantitative evaluations of resource potential are of significant importance for both exploration and exploitation of shale oil. We investigate the shale oil resource potential in E2s4L (the lower submember of the fourth member of the Paleogene Shahejie Formation) of Damintun Sag by both qualitative and quantitative methods. From the viewpoint of qualitative evaluation, it is reasonable to hope that the target shale, with adequate oil-prone organic matter (OM) in the peak and late oil generation stage, forms a shale oil reservoir. The total oil content in shale is evaluated from free hydrocarbons in shale (S1) by correcting the heavy and light hydrocarbons and the resins and asphaltenes. The total oil content is found to be over 4.45 times greater than the original S1. The evaluation threshold of high-abundance oil is determined by both the total oil content (ST) and the ratio of ST to the total organic carbon content with values that are greater than 8 mg/g and 1, respectively. Based on t...

Shales comprise more than 60% of sedimentary rocks and form natural seals above hydrocarbon reservoirs. Their sealing capacity is also used for storage of nuclear wastes. The world's most important conventional oil and gas reservoirs have their corresponding source rocks in shale. Furthermore, shale oil and shale gas are the most rapidly expanding trends in unconventional oil and gas. Shales are notorious for their strong elastic anisotropy, i.e., so-called vertical transverse isotropy. This vertical transverse isotropy, characterised by a vertical axis of invariance, is of practical importance as it is required for correct surface seismic data interpretation, seismic to well tie, and amplitude versus offset analysis. A rather classical paradigm makes a clear link between compaction in shales and the alignment of the clay platelets (main constituent of shales). This would imply increasing anisotropy strength with increasing compaction. Our main purpose is to check this prediction on two large databases in shaly formations (more than 800 samples from depths of 0–6 km) by extracting the major trends in the relation between seismic anisotropy and compaction. The statistical analysis of the database shows that the simultaneous increase in density and velocity, a classical compaction signature, is quite weakly correlated with the anisotropy strength. As a consequence, compaction can be excluded as a major cause of seismic anisotropy, at least in shaly formations. Also, the alignment of the clay platelets can explain most of the anisotropy measurements of both databases. Finally, a method for estimating the orientation distribution function of the clay platelets from the measurement of the anisotropy parameters is suggested.

Shales play important roles in sedimentary basins, acting as both seals and reservoir rocks, and knowledge of their anisotropic velocity trends is of practical importance for correct seismic image processing and inversion, and for seismic to well tie. Whereas velocity-depth trends are extensively studied for conventional reservoirs and critical factors that control their compaction are well understood, little work has been done on shales. Compaction trends of shaly formations are controlled by a number of parameters such as clay mineralogy, silt fraction and depositional environment. This large number of parameters, which are difficult if not impossible to control in naturally deposited shales, make the study of shale compaction a statistically complex, multivariate and non-unique problem. In such a situation, laboratory experiments that allow precise planning of mixture mineralogy and chemical compositions of pore fluids as well as an accurate control of microstructural changes seems to be an attractive alternative. In this work, we have conducted two sets of compaction experiments on quartz-kaolinite mixtures with 100%, 75% and 60% of kaolinite powders (dry weight). In the first set, the use of a KCl brine solution to saturate the mixtures has led to the aggregation of the existing clay particles with each other and with silt particles. In the other set, the mixtures have been treated with a dispersant to separate existing clay aggregates into individual platelets. The mixtures have been further compacted in an oedometric cell at uniaxial stresses up to 30 MPa. Compressional (in vertical and horizontal directions) and shear (in vertical direction) ultrasonic wave velocities have been measured during these compaction experiments and the P-wave anisotropy has been estimated. The effect of the chemical composition of the pore fluid on shale microstructure has been studied using the micro-CT and SEM image analysis. Neutron diffraction experiments have been conducted to understand the orientation of clay platelets at the final stage of the compaction. Our research shows that the chemical composition of pore fluid significantly affects the microstructure of the clay component and via this the elastic properties of the artificial shales. The samples with the dispersed clay microstructure (DCM) have shown larger elastic anisotropies at the same porosity and significantly larger anisotropies at the same stress. The dispersed clay platelets have orientated preferably parallel to bedding plane while the clay platelets in the samples with the aggregated clay microstructure (ACM) show a wider angle distribution in the absence of quartz particles (100% kaolinite samples). In the case of 40% of quartz fraction though, the clay particles are more aligned in the ACM sample than in the DCM one.

Ultrasonic pulse velocity method is a standard method for measuring elastic properties of rock cores in laboratories. Cylindrical plugs of 40–100 mm length are usually used for such measurements. It was recently shown that thin disc samples (~15 mm in length) were suitable for such measurements in the case of an advanced experimental set-up. Here we present results of numerical simulations to support the outcome of the previous work and to improve the understanding of wave propagation in the samples during laboratory ultrasonic measurements. The finite element method within Abaqus/Explicit (Dassault Systemes, Simulia) is used to simulate wave propagation along the experimental rig and the rock sample caused by transmitted ultrasonic pulse. The computational domain mimics the real geometry. The results of the numerical modelling prove that an S-wave transducer also produces a compressional wave that propagates along the sample and can be recorded by a receiver. Simulations are performed for three configurations used in real laboratory experiments. The numerically simulated waveforms are compared with the signals, recorded during laboratory experiments. Simulated travel times of elastic waves are in a good agreement with experimentally obtained results.

Total organic carbon (TOC) is directly associated with total porosity and gas content and is a critical factor in assessing the potential of unconventional reservoirs. TOC content is only known at the depths where the laboratory measurements on recovered core samples are performed. However, reliable estimation of potential resources can only be based on information about vertical and lateral distribution of organic matter throughout the prospective gas shale reservoir. This information is commonly obtained from conventional wireline logs, such as gamma ray, density, transit time and resistivity. Due to the complexity of unconventional reservoirs, traditional methods based on distinct differences of resistivity, density and sonic velocity of organic matter from those of the inorganic matrix are not always successful. We investigate the best way to predict the TOC using gamma-ray, density, porosity, resistivity and sonic transit time log responses by applying machine learning methods such as Artificial Neural Network (ANN) and Support Vector Machine (SVM). The analysis is done on the data from seven wells drilled through onshore unconventional reservoirs in the McArthur Basin (Northern Territory) and Georgina Basin (Northern Territory and Queensland), Australia. The prediction quality of traditional, multiple liner regression (MLR) and machine learning methods was compared. The most accurate TOC estimates were generated by ANN- and SVM-based nonlinear predictors, followed by the MLR and traditional models. This indicates that geologic complexity affects the relationship between the log response and TOC in the area of interest.

The adsorption of hydrocarbon (pure CH4 and C2H6) on illitic clay was investigated at temperatures of 333, 363, and 393 K (60, 90, and 120 °C) over a range of pressures up to 30 MPa using grand canonical Monte Carlo (GCMC) simulations. We first discussed the comparability of molecular simulation results with experimental measurements. Our results indicate that molecular simulation results of the excess adsorption are comparable with the experimental measurements if they are both expressed per unit surface area available for adsorption instead of per unit mass. The gas density profiles indicate that the adsorption of CH4 and C2H6 is mainly affected by the clay surface layers. In micropores smaller than 2 nm, the overlapping of the interaction of the simulated pore walls with the gas results in enhanced density peaks. For pore sizes of 2 nm or larger, the overlapping effect is significantly reduced, and the height of the gas density peak close to the surfaces is no longer affected by pore sizes. The maximum...

A quantitative study of pore structure connection is presented based on the microscopic void volume distribution in a dolomitic limestone sample. The method combines a 3D clustering analysis algorithm with a critical porosity determination scheme to study percolation properties of connected pore spaces and obtain a theoretical estimation of effective porosity of the rock sample at the percolation threshold. The percolation threshold depends on pore structures of the sample and defines the smallest connected pore network that the flow of fluids can pass through. The dolomite rock sample was selected for its relevance as a petroleum resource reservoir medium. The calculated effective porosity at percolation threshold for the limestone sample suggests a minimum requirement on sample porosity in order to form a connected transport path for oil and gas extraction. Such information is important in evaluating recoverable resources from the reservoir. The outputs from this research would be helpful in better understanding of porous media and their transport behaviours, which are crucial for oil and gas exploration and production.

An understanding of gas transport in nano-scale porous media is crucial for many industrial applications, for example, processes associated with CO2 injection, storage and enhanced coalbed methane (ECBM) production. In this study, we carried out combined molecular dynamics (MD) and Grand Canonical Monte Carlo (GCMC) simulations on the transport properties (i.e. self- and transport diffusivities and permeability) of CO2, in a realistic intermediate rank bituminous coal (flexible coal model) at a temperature of 328 K (55 °C) and a range of pressures up to 25 MPa. Self-diffusivity and sorption isotherms of CO2 are obtained directly from the MD and GCMC simulations. The Maxwell–Stefan diffusion model was then applied to correlate the self- and transport diffusivities. The permeability was computed through an integration of the transport diffusivity over the sorption concentration obtained from the simulations. The results show that CO2 self-diffusivity decreases with increasing reservoir gas pressure up to 8 MPa, then increases with pressure due to the interaction between coal and CO2. The transport diffusivity increases with the reservoir gas pressure as a result of an enhanced thermodynamic factor. The simulation results reveal a negative correlation between the sorption-induced coal swelling and CO2 self-diffusivity due to the interaction between CO2 and coal. Rigorous modeling of gas recovery and production thus requires consideration of specific interaction of the gas and coal matrix. Permeability of CO2 exponentially increases with the decreasing reservoir gas pressure, which is comparable with published field data.

Self-consistent (SC) models are commonly used for simulating elastic and electrical properties of reservoir rocks. We have developed a technique to test the capability of SC models to jointly model elastic velocity and electrical conductivity of porous media using a database of measurements of these properties on reservoir sandstones. The pores were represented by randomly oriented spheroidal shapes with a spectrum distribution of aspect ratios, and elasticity theory was used to compute the variation of aspect ratios and volume fractions of the pores subject to varying differential pressures. Using this method, the pore aspect ratio spectra of a reservoir sandstone were obtained separately from the measured elastic (P- and S-waves) velocity and electrical conductivity under loading. We have determined that when the SC formalism is used, there is a systematic discrepancy in the estimated pore structure predicted by the two measurements. Despite the supposed applicability of the SC method to this class of problem, the pore aspect ratio spectrum inverted from one physical property (e.g., velocity or conductivity) failed in practice to predict the other physical property (e.g., conductivity or velocity), at least for porous sandstones. Our results suggested the requirement of a new model to link the elastic and electrical properties to a unified pore aspect ratio spectrum of rocks.

We used a common microstructural model to investigate the cross-property relations between elastic wave velocities and dielectric permittivity in carbonate rocks. A unified model based on validated self-consistent effective medium theory was used to quantify the effects of porosity and water saturation on both elastic properties (compressional and shear wave velocities) and electromagnetic properties (dielectric permittivity). The results of the forward models are presented as a series of cross-plots covering a wide range of porosities and water saturations and for microstructures that correspond to different predominant aspect ratios. It was found that dielectric permittivity correlated approximately linearly with elastic wave velocity at each saturation stage, with slopes varying gradually from positive at low saturation conditions to negative at higher saturations. The differing sensitivities of the elastic and dielectric rock properties to changes in porosity, pore morphology and water saturation can be used to reduce uncertainty in subsurface fluid saturation estimation when co-located sonic and dielectric surveys are available. The joint approach is useful for cross-validation of rock physics models for analysing pore structure and saturation effects on elastic and dielectric responses.

CO2 geosequestration is an efficient way to reduce greenhouse gas emissions into the atmosphere. Carbonate rock formations are one of the possible targets for CO2 sequestration due to their relative abundance and ability to serve as a natural trapping reservoir. The injected supercritical CO2 can change properties of the reservoir rocks such as porosity, permeability, tortuosity, and specific surface area due to dissolution and precipitation processes. This, in turn, affects the reservoir characteristics, i.e., their elastic properties, storage capacity, stability, etc. The tremendous progresses made recently in both microcomputed X-ray tomography and high-performance computing make numerical simulation of physical processes on actual rock microstructures feasible. However, carbonate rocks with their extremely complex microstructure and the presence of microporosity that is below the resolution of microcomputed X-ray tomography scanners require novel, quite specific image processing and numerical simulation approaches. In the current work, we studied the effects of supercritical CO2 injection on microstructure and elastic properties of a Savonni`eres limestone. We used microtomographic images of two Savonni`eres samples, i.e., one in its natural state and one after injection and residence of supercritical CO2. A statistical analysis of the microtomographic images showed that the injection of supercritical CO2 led to an increase in porosity and changes of the microstructure, i.e., increase of the average volume of individual pores and decrease in the total number of pores. The CO2 injection/residence also led to an increase in the mean radii of pore throats, an increase in the length of pore network segments, and made the orientation distribution of mesopores more isotropic. Numerical simulations showed that elastic moduli for the sample subjected to supercritical CO2 injection/residence are lower than those for the intact sample.

Well-log data is a cost-effective means to characterize the petrophysical properties of a geological formation. Among the data, compressional- and shear-slowness (DTC and DTS, respectively) are the most reliable and have been widely applied in the interpretations. However, the availability of DTS data tends to be limited because of its high acquisition cost. This study proposes a method to reproduce or reconstruct the DTS data using other well-log data, such as gamma ray, neutron porosity, bulk density, and DTC. The developed method is based on the conditional variational autoencoder (CVAE) and effectively considers uncertainty associated with the variability of the measured data. The performance of this developed method is validated by applying the well-log data acquired from Satyr-5 and Callihoe-1 wells in the Northern Carnarvon Basin, Western Australia, and the prediction accuracy of the developed method is compared to recently developed data-driven methods (i.e., long short-term memory (LSTM) and bidirectional LSTM (bi-LSTM)). The results reveal that the developed method produces a better DTS estimation than LSTM and bi-LSTM. Furthermore, the effectiveness of the proposed method remains unaltered regardless of whether the data contain a specific trend over the depth or amount of training data are insufficient. As a further application of the developed method, an uncertainty relative to DTS estimation is quantitatively obtained from Monte-Carlo estimation, which uses a trained probability model of the developed method. Sensitivity analysis reveals the high effectiveness of DTC in improving the performance of the CVAE method. From our results, we can conclude that the proposed CVAE-based method is an effective tool for improving the efficiency and accuracy of DTS estimation.

An investigation of the frequency dependent dielectric polarizability of water molecules bound to clay mineral surfaces using molecular dynamic simulation is essential to improve understanding of the bulk electrical transport properties of shales in petrophysics and other clay science. The aim of the present study was to quantify the frequency-dependence of the complex permittivity of K+-smectite partially and fully saturated with water and to determine the relaxation frequency of the K+-smectite for pore size of ~1 nm and smectite matrix basal space of 1.66 nm with water saturations that varied from 20 to 100 wt% using molecular dynamics simulations. The simulation results of the dielectric spectra showed an unchanged polarization mechanism occurring within the K+-smectite with nano pore size, characterized by a water saturation dependent static permittivity. The characteristic frequency of the dielectric relaxation was found to be ~30 GHz for the system studied. The permittivity relaxation was found to be non-Debye type relaxation, with a circular arc locus providing a good representation of the simulated data. The deviation from pure Debye behavior reduced and the dielectric permittivity became much more significant as water saturation increases. The results presented here identified the dielectric relaxation as resulting from the orientational correlation of the water molecules near the K+-smectite surface and gave support to the idea that the relaxation frequency reflects the dimension of pores. This work constituted a novel contribution to the dielectric spectra of overall wet K+-smectite by extending the dielectric behavior of the clay mineral-water system to a microscopic level description.

A controlled-release test at the In-Situ Laboratory Project in Western Australia injected 38 tonnes of gaseous CO2 between 336-342 m depth in a fault zone, and the gas was monitored by a wide range of downhole and surface monitoring technologies. Injection of CO2 at this depth fills the gap between shallow release (600 m) field trials. The main objectives of the controlled-release test were to assess the monitorability of shallow CO2 accumulations, and to investigate the impacts of a fault zone on CO2 migration. CO2 arrival was detected by distributed temperature sensing at the monitoring well (7 m away) after approximately 1.5 days and an injection volume of 5 tonnes. The CO2 plume was detected also by borehole seismic and electric resistivity imaging. The early detection of significantly less than 38 tonnes of CO2 in the shallow subsurface demonstrates rapid and sensitive monitorability of potential leaks in the overburden of a commercial-scale storage project, prior to reaching shallow groundwater, soil zones or the atmosphere. Observations suggest that the fault zone did not alter the CO2 migration along bedding at the scale and depth of the test. Contrary to model predictions, no vertical CO2 migration was detected beyond the perforated injection interval. CO2 and formation water escaped to the surface through the monitoring well at the end of the experiment due to unexpected damage to the well’s fibreglass casing. The well was successfully remediated without impact to the environment and the site is ready for future experiments.