Jarrett, Amber (Geoscience Australia, Energy Systems Branch) | Bailey, Adam (Geoscience Australia, Energy Systems Branch) | Hall, Lisa (Geoscience Australia, Energy Systems Branch) | Champion, David (Geoscience Australia, Mineral Systems Branch) | Wang, Liuqi (Geoscience Australia, Energy Systems Branch) | Long, Ian (Geoscience Australia, GA Laboratories) | Webster, Tara (Geoscience Australia, GA Laboratories) | Webber, Simon (Geoscience Australia, GA Laboratories) | Byass, Jessica (Geoscience Australia, GA Laboratories) | Gilmore, Stewart (Geoscience Australia, GA Laboratories) | Hong, Ziqing (Geoscience Australia, GA Laboratories) | Chen, Junhong (Geoscience Australia, GA Laboratories) | Henson, Paul (Geoscience Australia, GA Laboratories)
Shale gas plays require technology such as fracture stimulation to increase rock permeability and achieve commercial rates of flow. The brittleness of shales are a major control on the ease of fracture stimulation. The Brittleness Index (BI) is a proxy for rock strength, based on geomechanical parameters, and/or rock mineralogy, and provides an indication of hydraulic stimulation effectiveness. Legacy drill core does not always have the geophysical logs needed for assessment of shale brittleness, therefore mineralogical and geochemical derived proxies for shale brittlenesss are often used with varying success. Shales from the Paleoproterozoic Lawn Hill Platform of north-west Queensland and the Northern Territory are known to contain organic-rich sedimentary units with the potential to host shale-gas plays. The Egilabria 2 DW1 well demonstrated a technical success in flowing gas from the Lawn Supersequence and recent geomechanical logging in the Egilabria prospect have demonstrated the presence of brittle rocks favourable for fracture stimulation with similarities between logged geophysics and X-Ray Diffraction (XRD) derived brittleness (
Bailey, Adam H.E. (Geoscience Australia) | Jarrett, Amber J.M. (Geoscience Australia) | Bradshaw, Barry (Geoscience Australia) | Hall, Lisa S. (Geoscience Australia) | Wang, Liuqi (Geoscience Australia) | Palu, Tehani J. (Geoscience Australia) | Orr, Meredith (Geoscience Australia) | Carr, Lidena K. (Geoscience Australia) | Henson, Paul (Geoscience Australia)
The Isa Superbasin is a Paleoproterozoic to Mesoproterozoic succession (approximately 1670-1575 Ma), primarily described in north-west Queensland. Despite the basin's frontier status, recent exploration in the northern Lawn Hill Platform has demonstrated shale gas potential in the Lawn and River supersequences. Here, we characterise the unconventional reservoir properties of these supersequences, providing new insights into regional shale gas prospectivity.
The depths, thicknesses and mappable extents of the Lawn and River supersequences are based on the 3D geological model of Bradshaw et al. (2018). Source rock net thickness, total organic carbon (TOC), kerogen type and maturity are characterised based on new and existing Rock-Eval and organic petrology data, integrated with petroleum systems modelling. Petrophysical properties, including porosity, permeability and gas saturation, are evaluated based on well logs. Mineralogy is used to calculate brittleness (see also
Abundant source rocks are present in the Isa Superbasin succession. Overall, shale rock characteristics were found to be favourable for both sequences assessed; both the Lawn and River supersequences host thick, extensive, and organically rich source rocks with up to 7.1 wt% total organic carbon (TOC) in the Lawn Supersequence and up to 11.3 wt% TOC in the River Supersequence. Net shale thicknesses demonstrate an abundance of potential shale gas reservoir units across the Lawn Hill Platform.
With average brittleness indices of greater than 0.5, both the Lawn and River supersequences are interpreted as likely to be favourable for fracture stimulation. As-received total gas content from air-dried samples is favourable, with average values of 0.909 scc/g for the Lawn Supersequence and 1.143 scc/g for the River Supersequence
The stress regime in the Isa Superbasin and the surrounding region is poorly defined; however, it is likely dominated by strike-slip faulting. Modelling demonstrates limited stress variations based on both lithology and the thickness of the overlying Phanerozoic basins, resulting in likely inter- and intra-formational controls over fracture propagation. No evidence of overpressure has been observed to date, however, it is possible that overpressures may exist deeper in the basin where less permeable sediments exist.
This review of the shale reservoir properties of the Lawn and River supersequences of the Isa Superbasin significantly improves our understanding of the distribution of potentially prospective shale gas plays across the Lawn Hill Platform and more broadly across this region of northern Australia.
Li, Shi Zhen (China Geological Survey) | Wang, Yue (Schlumberger) | Liu, Xu Feng (China Geological Survey) | Zhao, Xian Ran (Schlumberger) | Zhao, Hai Peng (Schlumberger) | Xu, Lei (GeoReservoir Research)
Production from the Lower Silurian Longmaxi formation shale gas reservoir in Fuling, Changning, and Weiyuan fields in the Upper Yangtze area has reached over 10 billion cubic meters. The Wufeng-Gaojiabian formation of the Lower Yangtze area is a new area of shale gas exploration in China. The objective of this study was to evaluate the potential of the shale gas reservoir in this area.
An innovated lithofacies classification method was developed that incorporates total organic carbon (TOC), grain size, matrix mineralogy, and lithology. An integrated workflow with input derived from microscopic observation, thin section analysis, ion-milled backscatter scanning electron microscope (BSE), X-ray diffraction, X-ray fluorescence (XRF) element analysis, gas adsorption test, and other organic geochemical experiments provides significant advantages for lithofacies classification. This paper applies an advanced technology in pore geometry analysis of various lithofacies, which has demonstrable value in guiding the shale gas exploration in new areas such as the Lower Yangtze area.
Reservoir characterization was performed on an exploration well in the Tangshan area of China. The lithofacies of the Wufeng–Gaojiabian formation shale can be classified into four types: organic-rich argillaceous/siliceous shale, organic-rich/clay-rich siliceous shale, organic-rich siliceous shale, and organic-lean micritic dolomitic mudstone. The first three lithofacies types have potential for shale gas accumulation, and the organic-rich siliceous shale has the best potential. Careful BSE analyses were done on different shale samples, and an interactive algorithm was used to determine the porosity of the organic-rich siliceous shale, which ranges from 5% to 7%. The shale shows heterogeneity in pore geometry; intergranular pores and intragranular pores dominate the pore spaces. The pores are well connected, but organic pores are rarely seen under microscope. Nutrition adsorption tests performed on organic-rich siliceous shale samples show dual pore size distribution characteristics; one set ranges from 2 to 60 nm, and the other ranges from 85 to 125 nm. Macropores dominate the pore space and account for 53% of the total porosity. Mesopores account for 28%, and micropores account for 19%. The percentage of various pore size gives insight into the potential shale reservoir.
The comprehensive reservoir characterization of the shale gas reservoir of the Wufeng-Gaojiabian formation in the Lower Yangtze area, which investigated depositional settings, organic geochemical features, lithofacies, and reservoir properties, suggests that the Lower Yangtze area may have potential as a shale gas exploration frontier. The workflow can also be applied to other shale gas plays in China.
Optimized landing zone has been proven the critical decision for successful unconventional play development, and it’s also the one of the most challenging topics largely due to the complex and heterogeneities of rock mechanics and reservoir properties. To make a robust decision for landing the horizontal well in the unconventional play, a better workflowintegration of geomechanics and reservoir properties have been developed. In this workflow, a novel model has been developed in order to quickly evaluate the vertical and horizontal fracture growth in a given reservoir, this model is based on Lagrangian formulation using the Least Action Principle, which captures the elastic energy of the rock matrix, surface energy of opened fracture and viscous dissipation in fracture fluids. The workflow provides a quick screening tool for hydraulic fracture growth across mechanical and stress barriers by integration of leak off due to high permeability streaks. Finally, the potentially accessed hydrocarbon volume within the SRV will be evaluated for each landing interval, which will help to make reasonable and objective decisions for landing strategy. The proposed workflow has been demonstrated in the appraisal and development in global unconventional assets, i.e. Vaca Muerta play in Argentina, Wolfcamp play in Permian basin and secondary reservoir in CB tight gas field. After calibration with pressure data from DFITs and miniFracs, the model quickly provides scenarios of fracture height growth and length propagation as a function of time for different landing depths. The fracture growth both upward and downward that was predicted from this model for Changbei secondary reservoir have a good match with the diagnostic data (micro seismic, tracer log and temperature log interpretations). As the final outcome, the normalized accessed hydrocarbon in-place index (HCCAi) of each frac stage candidate has been computed, and this HCCAi has a positive correlation with well performance (initial production and EUR), thereby assisting landing zone optimization and stage ranking. The uncertainties of fracture geometries also have been analyzed and integrated into HCCAi for well performance evaluation.
Shale has been a major destination for unconventional hydrocarbon resources for its wide stratigraphic coverage as well as high volumetric hydrocarbon potential. Contemporary success in North American shale plays has intrigued operators worldwide in shale exploration. Organic richness has been a key factor to determine the potential of shale as it is proportional to the amount of hydrocarbon likely to be generated and stored in available spaces within the shale. The other important factor in this context is shale brittleness as it indicates how fracable the potential shale is. Attempts are made here by strategically using standard wireline logs in order to evaluate potential of Eocene Vadaparru Shale in Krishna Godavari Basin, India qualitatively and quantitatively.
The technique used in this study involves identification of organic lean ‘clean shale’ interval and establishing a ‘clean shale’ relation of resistivity as a function of compressional sonic transit time in the study wells, as both the logs respond comparably to shale and its organic content. Using this relation a proxy ‘clean shale’ resistivity log is generated in shale and compared with measured wireline resistivity. A positive separation between calculated and measured resistivity is then assessed as proportionate shale organic richness, owing to the presence of relatively less dense (corresponding to longer sonic transit time) and more resistive organic content. Shale brittleness is predicted from Young's modulus and Poisson's ratio using compressional, shear and Stoneley wave velocities obtained from sonic measurements, assuming transversely isotropic nature of Vadaparru Shale.
The Eocene marine transgressive Vadaparru Shale is a dominant stratigraphy in KG basin as evident from seismics and drilling. Petrophysical analyses in study wells indicated appreciable brittleness within Vadaparru Shale. The organic richness i.e. amount of positive separation between calculated and measured resistivity combined with brittleness quantitatively indicate fair to excellent unconventional potential of Vadaparru Shale. Considerable thickness, Type-II, III kerogen content and geochemical measurements support the study and highlight it as a promising ‘shale reservoir’ destination. In the context of rapidly growing energy demand of India Vadaparru Shale can be considered as serious unconventional player.
Overall this study presents quick strategy for shale potential quantification, thus allowing operators to focus spatially in the quest of unconventional hydrocarbon resources.
Undershultz, Jim (University of Queensland) | Mukherjee, Saswata (University of Queensland) | Wolhuter, Alexandra (University of Queensland) | Xu, Huan (China University of Petroleum, East China and The University of Queensland) | Banks, Eddie (Flinders University) | Noorduijn, Saskia (Flinders University) | McCallum, Jim (University of Western Australia)
There is an increasing need to understand the influence of faults in both gas production performance and the resulting potential impact on adjacent groundwater resources.Faults can exhibit a wide variety of hydraulic properties. Where resource development induces changes in pore pressure, the effective stress and thus the permeability can be transient. In this study, w explored strategies for characterizing fault zone properties for the initial purpose of evaluating gas production performance. The same fault characterization can then be incorporated into regional groundwater flow models to more accurately represent stress, strain and the resulting transmissivities when assessing the impact of gas development on adjacent aquifers.
Conventional fault zone analysis (juxtaposition, fault gouge or shale smear, fault reactivation) is combined with hydrodynamic analysis (distribution of hydraulic head and hydrochemistry) and surface water hydrology and hydrochemistry to evaluate across fault or up fault locations of enhanced hydraulic conductivity at specific locations of complex fault systems.
The locations of identified vertical hydraulic communication from the hydraulic analysis are compared with the fault zone architecture derived from the 3D seismic volume overlain with the
Considerable interest exists for better understanding the gas storage and transport properties for shale gas reservoirs in Australia’s Beetaloo Basin. In these reservoirs, fluid transport through natural and induced fractures may be described by Darcy’s Law, whereas transport in nanopores of the shale organic and inorganic matrix can occur via diffusion (
In this work, a high-precision high-temperature adsorption/diffusion rig was used to characterise methane adsorption and diffusion behaviour on an intact cube-shaped sample of Beetaloo Basin shale from the Amungee C member. The fixed-volume volumetric method was used to measure across a temperature range of 35 to 150°C and a pressure range of 0.6 to 21 MPa. The adsorption was modelled using the Langmuir isotherm, and the diffusion behaviour modelled using the unipore model. The TOC, thermal maturity, mineralogy and pore structure of the shale was characterised.
Pore characterisation indicated the presence of multiple scales of porosity in the shale (micro, meso and macro). The Langmuir isotherm model was applicable to the measured adsorption data indicating that a homogeneous distribution of monolayer adsorption may predominate in the sample. The pore scales and experimental conditions indicate diffusion is the primary transport mechanism occurring in the shale. The unipore diffusion model provided a good fit to measured CH4 uptake data, and alongside the measured diffusion coefficients suggested that transport is primarily governed by the sample mesoporosity. Increases in diffusivity with respect to CH4 pressure were observed, which reflected an established direct correlation observed in shales and coals between diffusion coefficient and adsorbate density.
This study assists in developing an understanding of the relationship between adsorption and diffusion behaviour and reservoir conditions for shales in the highly prospective Beetaloo Basin. The importance of non-Darcy fluid flow behaviour to shale gas production, and the limited availability of physical samples of Beetaloo basin shales underscores the importance of developing relationships that can help to understand diffusion behaviour where existing data are sparse.
Piane, Claudio Delle (CSIRO Energy, Perth, Australia) | Clennell, Ben (CSIRO Energy, Perth, Australia) | Josh, Matthew (CSIRO Energy, Perth, Australia) | Dewhurst, Dave (CSIRO Energy, Perth, Australia)
Recovery of hydrocarbons from organic-rich shales has played a significant role in changing the distribution of reserves worldwide and has also impacted on carbon dioxide emissions where extracted gas has been used to replace coal to power electricity grids. Such extraction is predicated on a good understanding of local and regional geological history as well as close examination of the rocks involved from seismic to nano-scale. This study looks at the impact of thermal maturity on the organic and diagenetic mineral fabrics observed in gas shales from different parts of the world, highlighting similarities and differences in their impacts on rock properties. Organic fabrics can present as pore filling migrated bitumen visualized in scanning and transmission elctron microsopy and the degree of thermal maturity directly impacts for example on the electrical properties, shown by contrasting examples from the Marcellus (ultra-high maturity) and Utica (moderately high maturity) shales; the former has extremely low resitivity while the latter extremely high. Dielectric properties are shown to be useful for rock typing in the Utica shale where standard resistivity logs are off the scale as the material is so resistive. Such properties have also been shown to be useful for estimating water saturation in the Roseneath-Epsilon-Murteree Formations of the Cooper Basin. Mineral diagenesis and its timing are also shown to be important for quartz cementation and pore structure modification in the Marcellus, Bongabinni and Goldwyer formations, with the latter two contrasted in terms of elastic and strength properties. Overall, micro-structural, laboratory and wireline log studies combined have given significant insights into the interplay between organic and diagenetic fabrics and resultant rock properties.
The North American success of unconventional oil development from marine shales has inspired the global liquid-rich shale (LRS) exploration and production trend. Resource evaluation and screening are always important for emerging shale basins. In contrast to North America, 95% of the LRS resources in China are found within lacustrine shales. Songliao, Ordos, Junggar and Bohai Bay basin are the four major lacustrine oil basins in which LRS plays are claimed and considered to be of huge resource in China. Lacustrine system differs from marine systems in many aspects with high impact on the LRS commercial development. Adopted from the classic Darcy’s law, resource potential, flow ability and drive energy are the three key factors influencing estimated ultimate recovery (EUR). Unlike routine in-place volume driven play assessment, this paper presents a multi-component EUR driven evaluation and screening that has been applied to the four major lacustrine basins in China. 1) Compared with ocean, lake usually developed in a confined area which result in the thick shale pack (more than 100m in most cases). However, in some basin, single layers with high total organic content (TOC) is thin and their distribution is disrupted by low TOC mud rocks, which would impact play resource potential. 2) Regarding the difference in kerogen type between marine and lacustrine shales, it was observed that Type I dominated lacustrine shales have a lower HC conversion rate than Type II kerogens for a given maturity, indicating that a higher maturity would be essential to achieving better fluid properties. These higher maturities tend to be found more toward the basin centers, that are often characterized by deeper burial and increased clay content. As deeper burial and higher clay content can lead to increased drilling and completion (fracability) challenges that may be costly, so a careful balance must be achieved when seeking higher maturity. 3) Considering of heterogeneity of lacustrine system, highly frequented alternation among different lithologies were observed in some lacustrine plays. The high stress contrast between different lithologies would consume energy of hydraulic fracture and impact the fracture growth.
Vahrenkamp, Volker (King Abdullah University of Science and Technology) | Khanna, Pankaj (King Abdullah University of Science and Technology) | Petrovic, Alexander (King Abdullah University of Science and Technology) | Ramdani, Ahmad (King Abdullah University of Science and Technology) | Putri, Indah (King Abdullah University of Science and Technology) | Sorrentino, Ranglys (King Abdullah University of Science and Technology)
The characterization and modelling of carbonate reservoirs can still be significantly improved to account for complex property and fracture network heterogeneities at scales difficult to resolve in the subsurface. The objective of this research is to develop and establish workflows for high fidelity geological modelling and characterization using modern and ancient carbonate outcrop analogues.
As a first step, we carefully selected high quality modern and ancient analogues to create comprehensive data sets on depositional heterogeneities. Advanced instrumentation and techniques were used such as 3D drone surveys, high-resolution surface geophysical surveys (50 MHz-100 MHz, and seismic), chirp sub- bottom profiler and high-resolution bathymetry mapping. These high-end techniques are paired with tried and tested standard geological techniques of measuring stratigraphic sections anchored by outcrop spectral gamma ray logs, analysis of sediment samples (texture, grain size, mineralogy, geochemistry) and fracture/fault surveys all integrated with full cores drilled in the outcrops. Using these, data models can be created for depositional and fracture heterogeneities at different scales and populated with ranges of property data like those found in actual reservoirs. The outcome will be a series of models for various carbonate reservoir settings and well location patterns with the goal of supporting drilling/exploration operations and reducing future development costs.
The project is based on two large-scale research projects of Jurassic carbonates outcropping in central KSA and a large modern carbonate platform in the Red Sea. Jurassic outcrops were analyzed using a unique dataset of measured sections including spectral gamma ray logs (300 vertical m), drone photogrammetry data (4x4 km2 overflight and several km's of vertical cliffs), seismic data (2 km), and GPR data (8 km). Data expose lateral heterogeneities, facies dimensions, and fracture networks at different scales. The modern carbonate outcrops are an ideal laboratory to investigate lateral facies heterogeneities and their relation to environmental factors influencing sediment distribution (prevailing winds versus storms, climate and nutrients). Around 800 km of hydroacoustic data, 50 sediment cores and 200 sea-floor samples were collected exposing significant and complex heterogeneities.
The outcome of these research projects significantly increases our understanding of property heterogeneity, facies distribution, fracture networks, and architecture of complex carbonate reservoirs. Resulting multi-scale modelling approaches and associated facies templates will improve the prediction of spatial heterogeneities of facies in subsurface reservoirs of similar settings. In addition, these datasets can be used as input for static analogue models and dynamic simulations to test sensitivities and determine optimum development scenarios for improving ultimate recovery.