Geomechanical models for the quantitatively prediction of multi-scale fracture distribution in carbonate reservoirs
Introduction
Carbonate stone, an important unconventional, was widely distributed in many countries such as U.S., Australia, Russia, Canada and China. Carbonate reservoirs are significantly different from traditional reservoirs due to their great burial depth, low porosity and low permeability, and developing fractures. Natural fractures, especially structural fractures, are the majorities of hydrocarbon reservoirs spaces and seepage channels, which can significantly increase reservoir permeability and enhance the ability to transport hydrocarbons to the wellbore (Laubach et al., 2009; Ju et al., 2014; Zeng et al., 2010). The formation period and location of fractures play an irreplaceable role in the exploration and development of carbonate reservoirs, especially in the direction, density and porosity of fractures. How to accurately predict fractures is a difficult problem in the world, especially the three-dimensional (3D) characterization and modeling of structural fractures in deep carbonate gas reservoirs with complex tectonics and diagenesis (Olson et al., 2009; Dai et al., 2011; Zeng et al., 2010). In the process of fractured reservoir exploration and production, fracture prediction or modeling is usually based on geometric/kinematic models, such as fault-related folds and fold curvature analysis, (Lisle, 1994; Bergbauer, 2007; Sanz et al., 2008; Ju et al., 2014), seismic techniques or logging methods. while they are limited because they cannot fully reflect the multiphase deformation behavior and mechanical properties of underground rocks. (Laubach et al., 2016; Olson et al., 2009; Smart et al., 2012). Generally, the development and distribution of tectonic fractures are mainly controlled by the tectonic stress (Ju et al., 2013; Ju et al., 2011; Li et al., 2017).
Therefore, it is very popular to determine the distribution characteristics of fractures based on the change of paleo-stress and current stress (Sanz et al., 2008; Zeng et al., 2010; Smart et al., 2012; Zhao et al., 2013). The mechanisms of fracture generating, such as rock failure criterion and strain energy density, were deeply studied since 1960. Based on laboratory experiments, the fracture intensity was positively correlated with the elastic strain energy in rocks (Price, 1966). According to the tensional and shear failure criterion, the rock fracturing index was calculated to predict the fracture development zones and leading direction (Song, 1999). The fracture density is quantitatively described by combining the failure value with the energy value, rocks with high strain energy have more fractures than those with low strain energy. (Tan and Wang, 1999; Zhou et al., 2003). The formulas of stress-strain, volume and linear density of fractures were established under the paleo-stress field based on the theory of strain energy density, according to the comprehensive rock mechanics experiments (Dai et al., 2011; Feng et al., 2016; Ren et al., 2019). Combining with the fault mechanics and diagenesis, a natural fracture analysis model was proposed to predict the network geometry, aperture distribution and preservation in the absence of underground rock samples (Olson et al., 2009). However, the geo-mechanical modeling methods are mainly based on the distribution of stress-strain, strain energy density and fault rate, the obvious relationship between fracture parameters and strain energy density in further quantitative mechanical models is much smaller at the different critical stages of tectonic deformation. There are few studies on the characteristics of multi-scale fractures. According to the technologies of FIB-SEM tomography and CT scanning, the quantitative characterization of multi-scale fractures in the bituminous and anthracite and the meso-scale fractures are simulated (Huang et al., 2015; Li et al., 2017). The micro-fracture samples were studied and evaluated by the CT scanning technology in the fracture process under the cyclic and static loadings. The results show that, particles break up to intergranular fractures under the cyclic loading, and the smooth and bright fractures developed along the cleavage surface under the static loading. Microscopic main fractures are visible in cement and there is no dust or debris material under a single load. The fractures are generally statistically clustered in brittle sandstones based on the electron microscope and cathodoluminescence imaging.
In this manuscript, the rock mechanical tests and X-ray CT scanning were firstly conducted to accurately determine the key values for the multi-scale fractures generation and development in carbonate rocks. The quantitative relationship between strain and fracture linear density was established, according to the maximum theory and maximum strain energy density, the associated mechanical models of fracture parameters (aperture and linear density) were deduced under the complex stress states. Based on the tectonic restoration of Hetianhe anticline, the finite element method was applied to better simulate the 3D paleo-stress and current stress field during the deformation of the faults and folds. Considering the affection of the current stress and filling degree on the aperture, combined with the composite fracture criterion, these mechanical models were incorporated into the numerical simulation software ANSYS to predict the distribution of tectonic fractures in the Hetianhe carbonate gas field. The simulation results were verified by the measured fracture parameters from the drilling core and imaging logging.
Section snippets
Geologic setting
The Hetianhe field was located at the central ridge of the Tarim Basin. The Mazhatage tectonic is located on the southern margin of Bachu bulge, which is a faulted tectonic belt sandwiched by two NW-SE reverse faults (Deng, 2007; Ren et. al, 2011, 2019) (Fig. 1). Carboniferous and Ordovician are the main target formation of the Hetianhe field, lacking of the Mesozoic, upper Paleozoic Permian system, lower Paleozoic Devonian and Silurian. The main gas-producing formation is the Ordovician
Core samples
The Ordovician lithology in Hetianhe gas field is dominated by bioclastic limestone, followed by bioclastic limestone. The samples are mainly obtained from different wells and different depths, all samples were 25 mm in diameter and 50 mm in height, the end is ground to 0.01 mm and the angle deviation is less than 0.25°.
Rock mechanical testing
As shown in Table 1, Table 2, a series of rock mechanical tests were conducted, including the uniaxial compression, triaxial compression and Brazilian splitting test. The
Fracture evolution under uniaxial mechanical experiments
Generally, based on the geometries and practical application in oil and gas field, most researchers classify structural fractures into three scale levels: large-scale fracture, meso-scale fracture, and small-scale fracture (Bahat, 1988; Becker and Gross, 1996; Rijken and Cooke, 2001). Due to the constraint of experimental sample size, we mainly consider the mechanism of fracture formation, the aperture size, the length and the degree of contribution to flow, and further divide the fracture into
Simulation of tectonic stress field
The finite element modeling software (ANSYS 15.0) was conducted to simulate the distribution of different scale fractures in the Hetianhe area. The software is well-performed with the geological problem in a 3D model (Smart et al., 2011). The finite element numerical simulation method could be divided into five steps, establishing of geological model, meshed model division, establishing mechanical parameters' model, loading constraints and stress and simulated results analyses. Geo-mechanical
Conclusions
The characteristic of fractures parameters was quantitatively calculated by a series of geo-mechanical models based on the finite element simulation software in the carbonate stone reservoirs in Hetianhe gas field, Tarim Basin, NW in China. And according to the multiscale fracture mechanism, the geo-mechanical method was conducted to predict the micro and macro fractures parameters with the finite element modeling.
According to the mechanic tests of the real time CT scanning, combined with the
CRediT authorship contribution statement
Qiqiang Ren: Methodology, Software, Writing - review & editing, Formal analysis. Qiang Jin: Supervision. Jianwei Feng: Conceptualization, Supervision, Funding acquisition. Zhaoyong Li: Investigation. He Du: Data curation.
Declaration of competing interest
The authors declare that they have no known competing financial interests or personal relationships that could have appeared to influence the work reported in this paper.
Acknowledgement
This study was funded by the National Science and Technology Major Project of China (2016ZX05014002-006, 2016ZX05047003-003, 2017ZX013-006-003) and the Fundamental Research funds of the Central Universities (17CX06039). The authors would like to appreciate the staff of the laboratories and Sinopec Research Institute, which supported the data, tests and analyses. Many thanks to the anonymous reviewers, whose comments will improve the quality of our manuscript.
References (40)
- et al.
Mechanism for joint saturation in mechanically layered rocks: an example from southern Israel
Tectonophysics
(1996) - et al.
Effects of internal structure and local stress on fracture propagation, deflection, and arrest in fault zones
J. Struct. Geol.
(2010) - et al.
3D meso-scale fracture modelling and validation of concrete based on in-situ X-ray Computed Tomography images using damage plasticity model
Int. J. Solid Struct.
(2015) - et al.
Mechanics of mafic dyke swarms in the Deccan Large Igneous Province: palaeostress field modeling
J. Geodyn.
(2013) - et al.
Insights into the damage zones in fault-bend folds from geomechanical models and field data
Tectonophysics
(2014) - et al.
Tectonic fractures in the lower cretaceous Xiagou formation of QingxiOilfield, Jiuxi basin, NW China. Part two: numerical simulation oftectonic stress field and prediction of tectonic fractures
J. Petrol. Sci. Eng.
(2016) - et al.
Multi-scale quantitative characterization of 3-D pore-fracture networks in bituminous and anthracite coals using FIB-SEM tomography and X-ray μ-CT
Fuel
(2017) - et al.
Role of shale thickness on vertical connectivity of fractures: application of crack-bridging theory to the Austin Chalk, Texas
Tectonophysics
(2001) - et al.
Simulation of stress fields and quantitative prediction of fractures distribution in upper Ordovician biological limestone formation within Hetianhe field, Tarim Basin, NW China
J. Petrol. Sci. Eng.
(2019) - et al.
Mechanical models of fracture reactivation and slip on bedding surfaces during folding of the asymmetric anticline at Sheep Mountain, Wyoming
J. Struct. Geol.
(2008)
Geomechanical modeling of stress and strain evolution during contractional fault-related folding
Tectonophysics
Impacts of the tectonic stress field on natural gas migration and accumulation: a case study of the Kuqa Depression in the Tarim Basin, China
Mar. Petrol. Geol.
Early single-layer and late multi-layer joints in the Lower Eocene chalks near Beer Sheva, Israel
Ann. Tect.
The shear strength of rock and rock joints in theory and practice
Rock Mech.
Testing the predictive capability of curvature analyses
Discussion on the extension law of structural fracture in sand-mud interbed formation
Earth Sci. Front.
Role of fracture in controlling the reservoir stratum in the carboniferous bioclastic Limestone member in Hetian river gas field,Tarim basin
Carsol. Sin./Zhong Guo Yan Rong
Structural framework and evolution of Bachu uplift in Tarim basin
Earth Sci. Front.
Geological model and characteristics of dissrete fracture network in tight sandstone gas reservoir constrained by multi-factors
J. China Univ. Petrol.
The phenomena of rupture and flow in solids
Phil. Trans.
Cited by (13)
Quantitative characterization of volcanic expansion fractures based on thermodynamic coupling analysis
2023, Geoenergy Science and EngineeringQuantitative prediction of multi-period tectonic fractures based on integrated geological-geophysical and geomechanics data in deep carbonate reservoirs of Halahatang oilfield in northern Tarim Basin
2021, Marine and Petroleum GeologyCitation Excerpt :Up to now, fracture prediction methods mainly include geological analysis methods of faults or folds based on outcrops (Li et al., 2017); Fracture prediction based on 3D seismic volume (Wilson et al., 2015; Schoenberg and Sayers, 1995; Gao, 2013; Olson et al., 2009), or using well logging methods, such as image log. These methods have good results for fault and large-scale fractures (Ren et al., 2020; Espejel et al., 2020; Gong et al., 2017), but it is difficult to predict medium and small-scale fractures, because of the limitation of data resolution, these data cannot truly present the deformation of reservoir rock. Tectonic fracture is the product of paleo-tectonic stress, the distribution is also mainly constrained by the stress (Gong et al., 2019; Guo et al., 2019; Liu et al., 2017a,b).
The influence of argillaceous content in carbonate rocks on the 3D modeling and characterization of tectonic fracture parameters—example from the carboniferous and ordovician formations in the hetianhe gas field, Tarim Basin, NW China
2021, Journal of Petroleum Science and EngineeringCitation Excerpt :Moderately to steeply dipping fully filled fractures, with medium apertures, were mainly developed during the Late Hercynian orogeny. The fracture porosity, aperture, permeability, linear density, and volume density are key parameters to characterize the fracture generation and distribution (Ren et al., 2020; Ju et al., 2014; Liu et al., 2018a). The gas production was highly influenced by the fracture porosity and permeability (Ortega et al., 2006; Dai et al., 2011; Feng et al., 2019).
Quantitative characterization of interlayer fractures in carbonate rocks based on finite element numerical simulation
2020, Journal of Petroleum Science and EngineeringCitation Excerpt :Carbonate rocks typically have low porosity and permeability and are poor reservoirs for oil and gas. Secondary permeability formed through fracturing is a major control on whether carbonate rock will have oil and gas or not (Walderhaug et al., 2012; Ding et al., 2015; Shrivastva and Lawatia, 2011; Nelson, 2001; Ren et al., 2020; Smart et al., 2012). Therefore, understanding the age, location, generation, orientation and intensity of fractures are important for oil and gas production and exploration.