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 (
Deisman, Nathan (University of Alberta, Edmonton, CANADA) | Flottmann, Thomas (Origin Energy, Brisbane, AUSTRALIA) | Guo, Yujia (University of Alberta, Edmonton, CANADA) | Hodder, Kevin (University of Alberta, Edmonton, CANADA) | Chalaturnyk, Richard (University of Alberta, Edmonton, CANADA) | Leonardi, Christopher (University of Queensland, AUSTRALIA)
Establishing bulk rock properties in friable material such as coal is difficult simply because retrieval of a sufficient sample is challenging particularly because fractured/cleated coal disintegrates in the coring process. This paper describes the use of synthetic rock with embedded simple discrete natural fracture (DFN) systems to establish key rock mechanical properties in synthetic rocks with varying DFN complexity and varying degrees of depletion. The ultimate goal of the work aims to inform late-life technology choices in the depleted CSG reservoirs.
To achieve this, we measured the deformation behaviour of the printed intact matrix and the printed interface (fracture) and expanded the rock mass equivalent continuum theory by
Five horizontally printed specimens were not reproducible and had an average Young’s Modulus of 4.95 GPa. The horizontally printed specimens with the same one and two fracture system, were not repeatable, and had measured fractured stiffness of 181.2 and 81.5 MPa/m for one fracture specimens and 114.8 and 142.9 MPa/m for two fracture specimens. The five vertically printed specimens were reproducible, with an average Young’s Modulus of 5.37 GPa. The one fracture system had a fracture stiffness of 86.6 and 97.8 MPa/m and the two fracture had a fracture stiffness of 58.3 and 63.8 MPa/m. The equivalent continuum theory suggests that the joint stiffness should be fracture intensity (P32) independent, therefore equal, which was not the case. The change in volumetric strain due to change in isotropic stress was also measured to calculate the bulk modulus of a specimen with zero, one and two persistent vertical fractures. Results from the testing showed that as the fracture area increased, the volumetric strain behaviour was increasingly nonlinear, until a stress magnitude where the bulk modulus became linear and equal for zero, one, and two fracture specimens (3.68, 3.68, 3.51 GPa).
Results show reduction in modulus as a function of P32i and P32 which, however, does not fit the developed theory but is promising to continue the work with the 3D printed specimens. Adjustments to the controls on the printing process may be made to reduce the specimen variability and improve repeatability. In all fractured cases, the synthetic rocks showed initial non-linear behaviour, which was expected, and important for future work and analysis. Therefore, the results of this program are sufficient to formulate a broader test matrix that will be conducted to establish fundamental rock physical parameters and in particular bulk compressibility of coals of varying permeability related to P32/P33 characteristics.
Inspired by the North American experience and success, unconventional resource exploration in China is experiencing rapid growth, and many operators in different blocks in the Sichuan area are engaged in shale gas drilling and completion. Despite the declared commercial success, the consensus is that the experience of extracting shale gas in the Sichuan basin is very different from the experience in North America or anywhere else in the world. During the completion phases, geomechanics uncertainty, proppant placement challenges, unexpected casing deformation, and inconsistent production results remain challenges as the industry seeks to understand these complex reservoirs. The multidisciplinary integration and analysis of production, reservoir, geological, and completion data provide insight into the source and potential solutions to the challenges faced in the Sichuan basin.
In this study, we review, analyze, and synthesize a broad range of information and results including fracturing data, fracturing geometry measurements, casing deformation occurrence, production analysis, and material balance analysis.
Operational data from hundreds of fracturing stages were summarized to reveal the common observation that most Sichuan gas fracturing operations result in abnormally high shut-in pressure, potentially indicating horizontal or fissure-dominated fracture planes. In addition, fracture geometry measurements, including micro-seismic data and post-fracturing height measurement, indicate fracture height containment and mixed fracture planes. A specific case study suggests that casing deformation has its root in the mixed fracture planes.
The integration of the observations and analysis from different aspects generates a plausible explanation for the complexity that dominates performance in Sichuan shale gas. Based on its unique geology and geomechanics features, the mixture of vertical, horizontal, and fissure-dominant fractures is very likely inevitable for shale gas development in this basin, and the understanding of this specific complexity is a prerequisite for future planning of the field, drilling laterals, and proper choice of completion strategy and fracturing schemes.
This paper assesses regulatory rules associated with drilling and completions activities in Queensland unconventional oil and gas plays. This assessment is based on a typology that classified rules into defined categories, defining their structure and what types of activities are required to assure them. This paper also reviewed a sample of ‘as built’ Well Completion Reports (WCR) to understand the self-assurance activities conducted by operating companies as well as to identify trends in compliance against a sample of rules.
The typology assessment identified that rulemaking was generally consistent across documents, and a clear balance existed between rules focused on design and rules focused on field operations. The assessment also identified the actual wording of rules could benefit by more standardisation in some areas. Importantly, this assessment also identified the large volume of complex assurance activities faced by inspectors.
The ‘as built’ data review identified a clear commitment to the written rules and evidence of self-assurance activities being consistently conducted by operators. This review also confirmed the value of WCR analysis and the potential to use them to measure compliance.
Whilst this paper has provided valuable insight into rule making and the approach to self-assurance taken by some operators, there are many areas of the wider regulatory system that would be well served by further analysis. This paper has proposed some recommendations for such analysis to help make a more holistic assessment of effectiveness in the future.
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.
Raza, Syed Shabbar (The University of Queensland School of Chemical Engineering & The University of Queensland Centre for Natural Gas) | Rudolph, Victor (The University of Queensland School of Chemical Engineering & The University of Queensland Centre for Natural Gas) | Rufford, Tom (The University of Queensland School of Chemical Engineering) | Chen, Zhongwei (The University of Queensland School of Mechanical & Mining Engineering)
A novel, simple, economical, and time effective method to estimate the anisotropic permeability of the coals is presented in this paper. This method estimates the coal's anisotropic permeability by avoiding the tedious experimentation using triaxial permeameter or history matching exercises. This method calculates the absolute magnitude of the permeability of the sample. In this regard it is unlike other analytical permeability models, such as given by Palmer and Mansoori (1998) and Shi and Durucan (2014), that only calculate the permeability ratio (k/k0). The motivation is to find a method by which the permeability of the coal may be determined with reasonable accuracy by using only two easy measurements: 1) Mercury Intrusion Porosimetry (MIP) and; 2) Anisotropic stress-strain (σ-ε) measurement. The main blocks of the method are based on 1) cleat size which is obtained from MIP and randomly allocated to form flow-channels/cleats through the coal; 2) these cleats form parallel paths in the orthogonal face and butt cleat directions which provide the permeability; and 3) the cleat width (b) is stress dependent. This method is further validated by comparing with the experimentally measured stress-dependent permeability of Surat Basin (Australia) coal and a German coal in face cleat and butt cleat directions.
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.
Santiago, Vanessa (The University of Queensland School of Chemical Engineering) | Ribeiro, Ayrton (The University of Queensland Centre for Natural Gas) | Hurter, Suzanne (The University of Queensland Centre for Natural Gas)
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
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.
Chen, Xingyu (Chuanqing Drilling Engineering Company Limited, CNPC) | Li, Yanchao (Chuanqing Drilling Engineering Company Limited, CNPC) | He, Feng (Chuanqing Drilling Engineering Company Limited, CNPC)
Induced stress and natural fracture mapping play important roles in well stimulation of shale gas, which determine hydraulic fracture geometry and complexity. At present, there are two methods to calculate the induced stress including analytical model and discontinuous displacement method. The analytical model is based on planar fracture assumption without considering of natural fracture impact. The DDM method is widely used to calculate induced stress by non-planar fractures.
In this paper, we designed a triaxial multi-fracture induced stress test apparatus to measure induced stress and revealed hydraulic fracture propagation. The artificial rock with different types of 3D printed natural cracks was employed to simulate impact of bedding, vertical fracture, and complex natural fracture. A series of laboratory tests to investigate the laws of multi-fracture induced stress under a triaxial stress condition. The effects of multiple factors such as fracture geometry parameters, fracture assembly types and pump injection rate on induced stress were also evaluated. Lastly, the fractal dimension method was used to quantitatively evaluate the morphology of fracture surface and fracture network complexity.
The experimental results showed that different combinations of pre-existing natural fractures can effectively reduce the fracture pressure by 25~45%. Compared with the failure test without presetting natural fractures, the induced stress at the wall position of the rock mass decreased to highly 30%. Based on the experimental test data, the different fracture induced stress ratio coefficients of shale reservoir induced stress prediction model before and after fracturing were obtained, and the coincidence rate between the calculated results and the experimental test results was verified to be 91.5%.
This study provides a feasible method for the testing and analysis of fracture induced stress, which is more suitable for the actual characteristics of shale reservoirs and thus provides the experimental basis for the accurate calculation of the induced stress between fractures in the phenomenon of well interference in shale reservoirs.
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.