Geomechanical models for the quantitatively prediction of multi-scale fracture distribution in carbonate reservoirs

https://doi.org/10.1016/j.jsg.2020.104033Get rights and content

Highlights

  • Established the multi-scale fractures geomechanical models.

  • The three-dimensiona distribution of different scale fractures were quantitatively predicted.

  • The values of the volume density, linear density and aperture were determined.

Abstract

In order to predict the multi-scale fractures in carbonate, the geo-mechanical model need to be established. The key thresholds (0.82σc and σc) for the micro-fractures and macro-fractures according to the mass release of the elastic strain energy and bursting was confirmed, through CT scanning and some mechanics experiments. Then two physical models between strain energy density and fracture volume density were built based on the geomechanics theory. Combined with the Mohr-Coulomb and Griffith's criterion, the fracture parameters under the complex stress condition were modified and deduced. All geo-mechanical algorithms were written into the finite element platform, combined with the paleo-structural restoration of the Hetianhe anticline, the three-dimensional distribution of the multi-scale fracture density and aperture were quantitatively simulated. The prediction results are consistent with current in-situ core and FMI observations.

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.

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