ABSTRACT: The poor rock drillability of the conglomerate has restricted the development of the abundant conglomerate reservoirs in Xinjiang. Lack of downhole rock drillability makes drilling operators usually tend to use conservative drilling parameters when drilling the conglomerate formation. The conventional logging parameter methods have significant errors because of the serious heterogeneity of conglomerate formation. An experimental study is conducted to investigate the correlation between the rock drillability of the conglomerate and its components. The bottom hole cores have been collected which have varied mineralogy, the volume fraction of gravel (Vg), the median grain size (D), and the compressive strength. Rock drillability is measured under the combined pressure conditions by Rollow's micro-bit method. Through the experiment, the influence of different components on the rock drillability has been obtained. The results indicate that the volume fraction of gravel (Vg) and the median grain size (D) have a better correlation with rock drillability. Vg has a linear correlation with rock drillability of conglomerate, and D has a logarithmic correlation with rock drillability of conglomerate. A model for rock drillability of the conglomerate based on different components has been derived. The novelty of the new model considers the influence of components on the rock drillability of the conglomerate for the first time. The findings contribute significantly to optimize the bit selection and drilling parameters, which provides an efficient and economic drilling operation. 1. Introduction Rock drillability is a comprehensive characterization value to describe the difficulty of rock being invaded and destroyed, it was first proposed by Tillson (White, 1969). It is an intuitive, accurate, and easily accessible parameter to evaluate the rock mechanics of formation currently drilled in drilling engineering, and an important reference for bit selection (Yarali and Kahraman, 2011). Therefore, the technology to accurately evaluate the rock drillability plays an important role in improving the rate of penetration and reducing drilling costs in the oil and gas drilling operation. Head classified the rock drillability for the first time, he used the time of 1/16 inch drilling depth obtained by micro bit as an index to classify the formation successfully. The drilling parameters were 417lbs WOB and 110RPM. This method is the rock drillability classification DCN (Head, 1951). This method and its similar way have a huge advantage in conglomerate mechanic properties research. Because it can clearly obtain the components of the cuttings shearing down from the conglomerate. Therefore, it can help researchers to select rock-breaking regions of similar components to avoid errors caused by strong heterogeneity.

ABSTRACT: Analysis of nano-scale transport processes between pores in shale and fracture systems is essential for predicting hydrocarbon production. Accurate estimation of total hydrocarbon storage is important in reservoir management, economically and financially. Also improving EOR in unconventional reservoir requires comprehensive knowledge of the rock characteristics, such as pore size distribution. In this work we presented the results of digital rock analysis (DRA) for high-resolution micro-CT and FIB-SEM images of Bakken core plugs. The workflow includes a fundamental digital rock physics procedure to estimate porosity and absolute permeability and compare the pore-scale heterogeneities in different core samples. From the analyses that is evident that permeability can vary in even short distances of sampling in an unconventional play, such as the Bakken Fm. Therefore, assuming an average permeability for such formation may not be a promising assumption, rather upscaling techniques are recommended. Better understanding of heterogeneity in shale plays can help us to design optimal EOR operations for improved recovery. 1. Introduction Nowadays, possessing massive oil reserves with great potential of oil production is well known for unconventional reservoirs, which have a huge effect on the future of the petroleum industry. In the United States, reservoirs such as the Barnett, Woodford, Haynesville, Fayetteville, Marcellus, and Eagle Ford Shale are examples of these types of reservoirs (Chen et al, 2013). However, the complex characteristics of these reservoirs (i.e. ultra-low permeability and heterogeneity) cause the ultimate recovery factor to remain low (less than 10%). Numerous researchers have shown that nano/micro-scale heterogeneity has noticeable impact on larger scale properties, physical phenomena, and hydrocarbon recovery assessment. Therefore, it is essential to determine the microstructure information (Farajzadeh et al., 2011). In specific cases, one of the prevalent methods for enhancing oil recovery lies within CO 2 injection and huff and puff. These methods have gained the attention of researchers and have showed great recovery enhancement during both experimental and field results. This mainly happens due to low MMP (Minimum Miscibility Pressure) with oil, and small molecule size when compared to other common injected gases. Hence, obtaining internal parameters such as porosity, specific surface area, and pore size distribution is necessary to analyze the nano-scale transport processes between pores in shale and fracture systems (Chen et al., 2013). Consequently, accurate estimation of total hydrocarbon storage will improve reservoir management, economically and financially. Among all input parameters to reservoir simulation, absolute permeability is counted as an essential one to forecast hydrocarbon production. This gets even bolder when dealing with heterogeneous reservoirs, where permeability values reach nano-Darcy.

ABSTRACT: Bonded Block Models (BBMs) have become increasingly used to simulate laboratory rock samples in Unconfined Compressive Strength (UCS) and Triaxial tests. BBMs require input parameters that describe the deformation of the blocks themselves (block properties), as well as the interaction of the blocks with adjacent blocks (contact properties). For rocks with more than one mineral (i.e. block) type, there exists more than one type of contact between blocks, each of which requires a different set of input parameters. Little is known about the effect of heterogeneity of the contact properties on individual aspects of the overall behavior of the BBM. Therefore, this study has conducted a sensitivity analysis on the heterogeneity of contact input parameters. Contact input parameters were tested separately by varying the degree of heterogeneity between contact types, while keeping the weighted average of each given contact property constant for all simulations. Both a UCS and a Triaxial test with 12 MPa of confining pressure were simulated for each case to evaluate the effects of heterogeneity under unconfined and confined conditions. Rock specimen properties were computed from the model results including Young's Modulus, Poisson's Ratio, UCS and Peak Strengths, and Crack Initiation (CI) and Crack Damage (CD) parameters. While several minor influences of heterogeneity on macroscopic properties were noted, the primary influence was that of contact peak cohesion heterogeneity on CD under both unconfined and confined conditions. 1. Introduction With the advent of high-performance computing, numerical models have become increasingly used to study rock behavior. Numerical models can be used to complement laboratory testing, as they require significantly less time and labor to complete. Unconfined Compressive Strength (UCS) and Triaxial tests are laboratory tests that are commonly used to assess the material properties of intact rock. Such laboratory tests can be simulated using Bonded Block Models (BBMs) (Sinha and Walton, 2020) and can be further applied to field-scale modeling scenarios like excavations, roof stability, underground pillar design, and other scenarios that cannot be tested in a laboratory.

ABSTRACT: Material heterogeneity is commonplace in rock masses, and thus it is vital to investigate its influence on hydraulic fracture propagation in tight reservoir rocks. Here, based on the combined finite-discrete element method, two series of models with uniformly-distributed and Weibull-distributed elastic modulus of rock are assembled, respectively. The comparison with the theoretical solution demonstrates the reliability of the simulation models and simulation parameters in both the viscosity-dominated regime (VDR) and toughness-dominated regime (TDR). The effects of different Weibull distribution types on the variability of fracture length, final fracture morphology, fluid pressure at injection point, and maximum fracture aperture are evaluated. The results demonstrate that the distribution type of rock elastic modulus has a significant impact on the hydraulic fracture propagation in both the VDR and TDR. The "jump" phenomena have been observed in the TDR caused by high fracture toughness. The displacement of fracture location and asymmetrically dynamic propagation are affected by the distribution of rock elastic modulus. These results also indicate that the hydraulic fracture propagation in TDR is more susceptible to the distribution of rock elastic modulus than that in VDR. This research may shed light on the development of hydraulic fracturing technology in tight reservoir. 1. Introduction Hydraulic fracturing technology has been widely used to increase the permeability of tight reservoir rocks, with the ultimate goal of enhancing oil and gas production in unconventional reservoirs (Detournay, 2016; Wang, 2019; Wu et al., 2020). However, material heterogeneity is commonplace in reservoir rocks (Ju et al., 2016; Lei and Gao, 2019), and it may have great impacts on the propagation of hydraulic fractures. Therefore, it is necessary to investigate the influence of rock heterogeneity on hydraulic fracturing. Previously, average values of mechanical parameters of rock samples obtained at mesoscopic scale are commonly used as the equivalent mechanical parameters of oil and gas reservoir at macro scale. In fact, after many years sedimentation and diagenesis, oil and gas reservoirs usually have different degrees of heterogeneities (Doughty et al., 1994). However, due to the difficulty of implementation and limitation of monitoring tools, it is difficult to study the heterogeneity and its effect on hydraulic fracturing in laboratory experiments (Deng et al., 2018b; Wu et al., 2020). Thus, numerical models considering rock heterogeneity characteristics have to be established to evaluate hydraulic fracturing in reservoir rocks.

ABSTRACT: Proper zonal isolation is key to ensure optimum injection and production and it is highly dependent on the cement bond to the casing and the formation. Yet, in most wells, cement evaluation logs are not run. This work will describe a workflow to address the lack of cement evaluation data by creating synthetic logs to aid wellbore integrity analysis. Synthetic logs can be a reliable and cost-effective alternative to predicting the cement bond than running log tools in every well during a drilling campaign, and, with further development, has the potential to be used for well design. A machine learning framework based on Gaussian process regression (GPR) was chosen in the development of this procedure because it can assess uncertainty of the cement bond through estimation of error and confidence interval. GPR also require less training samples than conventional machine learning techniques. In this work CBL data was used for training and the model was validated through comparison with data from a different well in the same field. The results shows that the predicted case correlated very well with the base case, with some curves overlaying even in the poor bond sections. Initial assumptions given by the covariance function help capture not only the general trend relationship but also localized variations, which play a major role in the way a fracture propagates in the annulus. Additionally, the uncertainty assessment provided by this framework can assist risk management by determining worst case scenarios and potential fluid migration paths in the annulus. 1. Introduction Wellbore integrity is a fundamental aspect of the life-cycle of production, injection, and geothermal wells as well as site characterization for storage in areas with abandoned wells. The condition of well cement and its bond to the casing and formation can determine whether a well can sustain optimal hydrostatic pressures and prevent leakage. This is a critical but often overlooked aspect of assessing potential reservoirs when optimal and sustainable pressure conditions are critical for success. The integrity can ensure safe production and abandonment and may be the decision factor when selecting potential candidates for CO 2 injection (Bachu, 2017). Cement failure is a common occurrence in wells and can be evidenced by sustained casing pressure (SCP) (Bourgoyne et al., 2000). This means that most wells exhibit some kind of leakage after abandonment. To this end, regulations are becoming stricter and requiring complete elimination of SCP. Therefore, the importance early detection of cement problems to avoid costly remediations later.

ABSTRACT: The present work aims to study the influence of the bit-button geometry on the performance of percussive drilling. Here, we describe the experimental set-up and we present the results of a series of single impact tests performed using a piston drop type percussion testing system. The experiments allowed the comparison of the drilling efficiency of several insert geometry designs and were realized under dynamic loading on two confined hard and abrasive rocks using five types of inserts. Drilled rock volumes were measured by a 3D laser scanner, and the insert performance is evaluated by calculating the drilled volume, the resulting chipping and the maximum depth of the obtained crater. The study showed the effect of insert geometry on the formation of the crater and chipping upon impact and that conical inserts, with a preliminary optimal tip curvature radius, have the best performance among the tested inserts. 1. Introduction Percussive drilling is widely used in the mining industry, especially in hard rock formations. This technique is mainly used in drilling depths of roughly a thousand meters and is under development for applications in geothermal wells at greater depths. In such formations, hard and abrasive rocks are present and are subjected to high geostatic and hydrostatic pressures. These conditions alter their behavior (Hokka et al., 2016) and complicate the drilling process (Gnirk, 1965). Down-the-hole (DTH) percussive drilling is a technology that consists in applying a series of impacts via an oscillatory movement of a piston which impacts a drill bit at a frequency of 20 to 30 Hz with a velocity of 1 to 10 m/s (Haimson, 1966), leading to rock fragmentation by compressive and tensile forces under the drill bit (Hartman, 1959; Lindqvist, 1984; Hustrulid and Fairhurst, 1971; Mishnaevsky, 1995). This mechanism is ensured by the drill bit buttons, also called inserts, which are in contact with the rock surface. At each impact, compressive waves travel through the drill bit down to the rock material, which enables the bit penetration by indentation of the inserts into the rock (Hartman, 1959). An extended description of rock fragmentation under indentation can be found in (Lindqvist and Lai, 1983, Mishnaevsky, 1995; Saksala, 2010). The rock destruction mechanism is achieved by crushing the rock material under the inserts, the creation of axial cracks during the loading phase, and lateral and side cracks which are formed during loading and propagate even more during the unloading phase (Saadati et al., 2014). However, most of the material removal is achieved by the creation of larger rock fragments from lateral and side cracks (Lindqvist and Lai, 1983; Saadati et al., 2014). This is called chipping process and it occurs under the inserts and between them, this process requires a minimum amount of impact energy and it results from the tensile stresses (Saksala et al., 2014). Therefore, in order to optimize the percussive drilling process, it is important to understand the influence of the insert geometry. We highlight the fact that many experimental and numerical studies were conducted to understand the rock fragmentation process under static and dynamic loading (Harpst and Davis, 1949; Wanamaker, 1951; Whiteley and W.P., 1986; Pratt, 1987; Mishnaevsky, 1995; Liu, 2004; Han et al., 2005; Han and Lao, 2005; Wang et al., 2007; …). Among these studies, only a few have accounted for the influence of the insert geometry (Nguyen, 1978; Reichmuth, 1963; Lindqvist, 1984; Gnirk, 1965; Qayyum, 2003; Ajibose et al., 2013), and even fewer have taken into account this factor while considering percussive drilling conditions: both dynamic loading and highly confined rocks. These researches showed that the rock presents more ductile behavior and plastic response using larger inserts (Nguyen, 1978), and it is easier to penetrate the rock using finer inserts (Gnirk, 1965). Ajibose et al. (2013) have experimentally studied the matter under dynamic loading and showed the forcepenetration responses for conical and spherical inserts under atmospheric pressure.

ABSTRACT: With the increasing demand for oil and gas resources, the depth of some development wells has exceeded 8000m. The mechanical properties of reservoir rocks have been changing from elasticity to Plasticity under high temperature and high stress, and the existing constitutive equations no longer can meet the needs of modeling. As a new sequence data analysis technology, Recurrent Neural Network (RNN) can fit the complex logical and nonlinear relations in the sequence data, and can predict the next data. In this study, 72 groups of rock stress-strain curve data in the target block are taken as the training data of Long Short-Term Memory (LSTM), and the final model after training can predict the stress-strain curve under the condition where the temperature is 25-200°C and closed stress is 0-11000psi. 9 groups of new curves are used as test data, and the validity of LSTM model is proved by comparing the predicted data with the real data. In this paper, Recurrent Neural Network is applied to the experiment of rock mechanics, and a new method for predicting the constitutive relation of rock in target area is obtained, which has high application value. 1. Introduction With the increasing demand for oil and gas resources, as well as the development and progress of oil and gas exploration, the depth of wells in China has exceeded 8,000 m. It's necessary to make rock mechanical analysis for any wells. However, due to the depth of such wells, the bottom stress, temperature, porosity, permeability and saturation are also different from ordinary wells. Under the high temperature and high stress, the mechanical properties of reservoir rocks have transformed from elasticity into plasticity and the traditional constitutive equations has no longer meet the needs of this model establishment. As a kind of geological material, heterogeneity is one of the basic characteristics of rock. The heterogeneity has a great influence on the mechanical properties of rock and its mechanical behavior under load. In the experimental study of this paper, it is also found that the heterogeneity of rock has a significant influence on the rock mechanics under high temperature and high pressure, which makes the regularity obtained in the analysis of rock constitutive relations not obvious. Recurrent Neural Network (RNN), as an emerging technology of sequence data analysis, is capable of fitting the complex logical and nonlinear relationships in sequence data and making data prediction at the next moment. Through theory and analysis of experimental data, this paper deeply studies the influence of rock heterogeneity on rock mechanical properties under high temperature and high stress, and uses recurrent neural network to analyze the influence of rock heterogeneity on rock mechanical properties under external conditions (temperature, stress and pore pressure) This is beneficial to the development of ultra-deep wells in Tarim oilfield.

ABSTRACT: The presence of naturally developed collapse breccia pipes poses a risk for subsurface development of natural resources in underground excavations (wellbores, shafts and mines). These features introduce heterogeneities affecting the fluid flow and mechanical behavior of the integrated host rock and breccia pipes system. The interplay of collapse shapes and stresses, geomechanical properties and pore pressure fluctuations dictates the mechanical integrity of such systems. Injection could, through breccia pipes, breach and communicate with upper layers. This research work contemplates geomechanical simulations of an ore deposit layer-cake formation in western Canada, where breccia pipes extend from the ground level to depths beneath the injecting reservoir. The goal is to understand injection conditions that prevent water inrush of underground infrastructures and contamination of aquifers due to fracturing and loss of confinement. Pre-stack time-migrated 3D seismic data helped to characterize shapes and sizes of the collapse breccia-pipes. Results indicate that it is not strictly necessary to include lateral variations of breccia-pipes permeability as long as a calibrated average permeability for the entire system is applicable. Conversely, the Young's modulus (E) contrast (i.e., E ratio of breccia-pipe to host rock) introduces the highest uncertainty in the estimation of in-situ stress magnitudes. Low values of E ratio induces a stress barrier surrounding the collapse breccia pipes. The analysis shows that under the assumption of a closed boundary scenario, tensile fracturing occurs inside the injection layers, but none of the intersected collapse breccia pipes becomes fractured. Pore pressure transmission vertically inside a collapse breccia pipe leads to their incipient tensile fracturing at shallower depths but with relative low propagation. The workflow helps to better understand the conditions for potential risks associated with collapse breccia pipes and water inrush for underground infrastructures. 1. Introduction and Background The presence of naturally developed collapse breccia pipes, also known as inclusions, chimneys, collapse structures, karsts or paleokarst features, are widely distributed around the world. They are of significant interest as they pose some risks for subsurface development of natural resources in underground excavations (wellbores, shafts and mines). These features introduce heterogeneities that affect the fluid flow and mechanical behavior of the integrated system, that is, host rock (reservoir and surroundings burdens) and inclusions (breccia pipes). The interplay of collapse shapes, geomechanical properties, stresses around collapses and pore pressure fluctuations dictates the mechanical integrity of such systems. Brine injection could, through breccia pipes, breach and communicate with upper layers affecting underground infrastructures and petroleum reservoirs. The subject of coupled interaction between geomechanics and fluid flow of collapse breccia pipes structures under injection has not been widely explored in the literature.

Abstract Hydraulic fractures can either grow in planar structures or branch into multiple strands. However, the conditions that cause these fracture patterns to occur are unknown and the controlling parameters are yet not understood. To answer these questions, we conducted laboratory hydraulic fracturing experiments using analog-rock samples that were constructed with controlled heterogeneity for repeatable experiments. Fluids of different viscosities were injected at various volumetric rates to investigate their controls on hydraulic fracture patterns. We observed three distinct phenomena on heterogeneous samples when injection rates and fluid viscosities were varied. Specifically, slow injection of low-viscosity fluids results in diffusion-dominated injection. Injection of medium-viscosity fluids at a moderate rate leads to hydraulic fracture branching. Further increase of both factors causes planar hydraulic fracture pattern. For samples without natural fractures, hydraulic fracture branching disappeared. Our repeatable experiments suggest two key findings: (1) Hydraulic fracture branching is only possible when heterogeneity, natural fractures, or pre-existing weak planes exist. (2) Branching can be controlled by manipulating the injection rate and fluid viscosity for a given formation. Our findings can help design the injection parameters to optimize hydraulic fracture branching in the subsurface for increased hydrocarbon production and recovery. Introduction Hydraulic fracturing has launched a new era in the oil and gas industry because it permits economic hydrocarbon production from unconventional reservoirs. Significant progress has been made to understand the initiation and propagation of a fluid-driven tensile crack in tight formations (Haimson and Fairhurst, 1967; Detournay 2004; Fisher and Warpinski, 2012). Numerous numerical models have also been developed to predict the hydraulic fracture growth in the subsurface (Dahi-Taleghani and Olson, 2011; Zhang et al., 2012). However, hydraulic fracture patterns in the subsurface remain poorly understood. Hydraulic fractures in the field usually interact with geological discontinuities that include bedding planes and natural fractures. Although these geological discontinuities are most likely closed due to compression, rock creep deformation, and geological diagenesis over million years, they can affect the fracture propagation and result in a complex fracture network partially depending on the in-situ stress anisotropy (Warpinski and Teufel, 1987; Jeffrey and Settari, 1995). Researchers have investigated the crossing/arresting behavior of hydraulic fractures when they encounter geological discontinuities (Blanton 1982; Olson et al., 2012; Fu et al., 2018). These studies, however, predicted no branching of the hydraulic fractures. The branching behavior of hydraulic fractures has been observed (Tan et al., 2017; Frash et al., 2015 & 2019; Li et al., 2020), but no studies exist to explore the conditions that enable hydraulic fracture branching.

Abstract This paper aims to discuss recent studies on methods used to capture heterogeneity within a reservoir undergoing hydraulic fracturing treatment and their implication on modelling of fracture propagation. In highly laminated reservoirs with soft and/or weak layers capturing heterogeneity at an appropriate resolution is the key for successful prediction fracture growth, landing depth and in maximizing effective stimulated rock volume (eSRV). Typically, when using computational methods such as Finite Element Method, the well log and petrophysical data deduced from various measurements and observations are upscaled and/or homogenized to the element size. Naturally, toughness is one of the most delicate physical parameters to handle as application of the homogenization techniques are rather questionable here (Caiulo and Kachanov, 2010, Kachanov, 1994) and proposed averaging (if possible) depends on the problem under consideration and the toughness distribution. Fortunately, since hydraulic fracturing is probably the only stable crack propagation problem, some estimates can be provided here. In particular, in this paper we try to estimate possible errors introduced by application of two strategies how to incorporate heterogeneous fracture toughness into numerical modelling. The first is more classical one (Richards et al. 2020) and the second one is recent analysis (Dontsov et al., 2021). We present series of numerical tests utilising a few periodic toughness distributions. For the simulations, we use an extremely effective in house built time – space adaptive solver utilizing main ideas from those reported in (Mishuris and Wrobel, 2015). It is capable to compute rather arbitrary distribution of the toughness. We restrict ourselves to the KGD model without leak off only as it allows us easy handling different regimes (toughness/viscosity) that would be crucial for the analysis as follows from this research. Introduction The petroleum industry often uses hydraulic fracturing as an engineering process to extract hydrocarbons from very low porosity reservoir rock which would otherwise be economically unviable (Economides and Martin, 2007, King, 2010, Bai et al., 2011). There are several design variables defining successful hydraulic fracturing, such as achieved production (both IP and EUR), fracture geometry (height and complexity) and the effective stimulated reservoir volume (eSRV). Their value is a complex function of, amongst others, pump rates of fracking fluids in both clean and proppant laden states, the initial stress state, the density of natural fractures in the reservoir and probably most important and studied in this paper, reservoir material properties. Given the number of interacting mechanisms, it is no surprise that commonly used empirical or ‘rule of thumb’ formulations provide only a limited guide on the relationship between injected fluid and the resulting variables.

Abstract This study suggests a novel method to determine the five elastic constants of transversely isotropic rock from a single core by concentrated loading and numerical iteration. A concentrated load was applied on a cylindrical specimen in order to obtain various stress fields from a single specimen. Numerical iteration was performed by finite element numerical modeling to minimize the differences between the measured and the modeled strains. Comprehensive numerical experiments were conducted on transversely isotropic rock in order to investigate the applicability of the methods in terms of their accuracy and heterogeneity. A soft loading plate was made by 3D-printing in order to avoid the singularity of the stress at the edge of the concentrated load. When the estimation based on a concentrated load test with a single specimen was not satisfactory, the Brazilian test of a sample from the same core was additionally conducted. In all cases, numerical iterations based on several strain measurements from the specimen allowed us to determine all five elastic constants from a single core. This study suggests that all five elastic constants can be determined successfully with a single rock core. The choice of a single specimen or two depends upon the heterogeneity of the rock considered. Introduction Numerous geomechanical applications are dealing with the transversely isotropic rock of sedimentary or metamorphic origins. For anisotropic rock, the consideration of its anisotropy can be important for the analysis of stress, deformations, and in-situ stress measurement by the overcoring method, so it is necessary to determine two elastic moduli, one shear modulus, and two Poisson’s ratios. The existing methods for determining the five elastic parameters of rock are to use multiple cores with different coring angles. The specimen is cylindrical or cubic, and the loading method is uniaxial compressive loading, true triaxial loading, or diametral loading (Amadei, 1996; Chen et al., 1998; Talesnick and Ringel, 1999; Cho et al., 2012). However, obtaining multiple cores in different directions is difficult in practice.

ABSTRACT: Thermal weakening of rocks is a well-acknowledged phenomenon. However, some experimental results reveal that some rocks are strengthened due to heating in a relatively low temperature regime (25°C to 175°C). In order to investigate the mechanisms of such strengthening phenomenon, a 2-dimensional grain-based model (GBM) which can mimic the thermal expansion and microcracking of polygonal grains is developed to examine the response of Carrara marble to thermal-mechanical loading from a microscopic point of view. Two sets of GBMs with different rock textures are designed and then tested under different confining pressures and temperatures varying from 25°C to 175°C. By examining the thermally induced microcracks, stress-strain curves as well as the distribution of microcracks in the numerical specimen, the micro-mechanisms of rock strength variation can be interpreted. The simulation results provide explanations for the thermal strengthening phenomenon in such a relatively low temperature regime. Few thermal microcracks, which tend to weaken rocks, are produced during heating in the rock. In contrast, compaction between grains occurs due to grain expansion upon heating, which can be regarded as the major causative factor that increases the rock strength. The tighter compaction in response to thermal treatment is a manifestation of the dependency of rock strength on rock texture. As a result, more heterogeneous rock texture may lead to a higher degree of strengthening. In addition, the confining pressure suppresses the grain expansion, and thus affects the stress-strain behavior associated with the strengthening phenomenon. The findings can provide important insights into geotechnical applications to achieve engineering safety and economy purposes. For example, in deep mining, we can take advantage of the naturally strengthened hot rock by correspondingly reducing the scale of artificial support, potentially leading to cost saving.

ABSTRACT: Water sorption and transport behaviors are of great importance affecting hydrocarbon extraction and wellbore stability due to water-involved drilling and fracking methods. Dynamic water vapor sorption experiments on two Marcellus shales at 20 °C, 30 °C, 40 °C were performed. Based on BET multilayer theory, specific surface area estimated by water vapor sorption is apparently larger than that by low pressure nitrogen adsorption, possibly due to the complex surface chemistry and water vapor sorption heterogeneity in shale. The heat of adsorption decreases with the water content and approaches progressively to the latent heat of the condensed water, indicating an initially strong intermolecular bonding and the subsequent form of capillary condensation. Kinetic analyses of water adsorption data show that diffusion coefficient of water vapor varies under different water vapor pressures and the maximum of diffusion coefficient occurs near monolayer coverage for the case of 20 °C and 30 °C. It was found that the temperature negatively influences water adsorption capacity and positively influences water vapor diffusivity. These findings contribute to a better understanding of water distribution characteristic in shale reservoirs during soaking period and thus providing clues to gas storage and transport behavior under fully or partial water saturations.

ABSTRACT: The understanding of in situ stresses is very important in the oil and gas exploitation. To provide an effective guidance for the field operations including drilling, fracturing and production, the finite element method was employed to model the in situ stresses as well as pore pressure in Sichuan shale gas reservoir embedded fault networks. The linear elastic model was used to depict the deformation of shale gas reservoir, and the friction behavior on the surfaces of faults was considered. Enough trial numerical experiments were used to obtain an optimized prediction that is expected to agree with actual test data. The information of in situ stresses in whole the geometric model as well as main shale gas reservoir layers, and on the fault surfaces can be acquired. Case studies on Changning and Weiyuan regions, Sichuan Basin, southwest China, were conducted, and the in situ stress information including stress gradients and horizontal stress differences in three typical areas was predicted. The orientation of horizontal maximum principal stress in the Changning and Weiyuan regions is almost east-west. The fault only affects the magnitude and orientation of situ stresses near itself, but have little effect on those in the farther strata.

ABSTRACT: An approach for constructing a multi-scale parametric Rock-Physics model of effective elastic properties of fractured reservoir rock is presented. The approach provides a link between three scales - core, log and seismic that correspond to conventional works with reservoir rocks in geophysical prospecting practice. At each scale the Rock-Physics model incorporates parameters specifying rock microstructure at the respective scale including shape, orientation, volume concentration and connectivity of voids (pores, fractures, and cavities). The modeling follows the principle “from small to larger heterogeneities” and incorporates elastic anisotropy of any type caused by preferential orientation of fractures. Evidence for fractures at the core and log scales are provided by different techniques commonly used for the analysis including electronic and optical microscopy, and computer tomography for the core scale and results of FMI and UBI for log scale. Fractures at the seismic scales are inserted in the Rock-Physics model based on the results provided by the geomechanical modeling. At each scale a probabilistic solution for the model parameters is obtained.

ABSTRACT: A 3D grain-based model (3D-GBM) based on the tessellated Voronoi technology is proposed in this current work using the three-dimensional particle flow code (PFC 3D ). A dimensionless heterogeneity index is introduced to quantitatively express the spatial distribution of grain shape and size. A continuous calibrated parameter strategy was performed to examine the micro-parameters of the 3D-GBM through the QianJiang salt rock. The effect of geometrical heterogeneity caused by the shape and arrangement of the grains on the responses of stress-strain curves, strength characteristics, microcracking behavior associated with failure modes is investigated. The simulated results show that the 3D-GBM can capture the strength properties and deformation behavior associated with the failure modes of salt rock. This model provides an alternative and promising method to deeply investigate the micro-mechanical response at the grain size, deepening our understanding of the mechanical properties of salt rocks in underground gas storage during the static load.

ABSTRACT: In this paper, the main results of a series of laboratory tests, on a tight sand reservoir belonging to the Lajas formation are presented as a part of a geomechanical characterization. Almost eight years ago, the first well was drilled on such formation on the Neuquén basin in Argentina. Its relevance has been raised during the last years due to its constant growth production, becoming the most important gas tight reservoir in the basin. Lajas formation is a Jurassic age tight sand, with low porosities and permeabilities between 0.1 md to 0.0001 md.

ABSTRACT: The Fast marching method (FMM) is a class of solutions designed to obtain Depth of Investigation (DOI) which means the time-dependent point of negligible drawdown during propagation of pressure pulse away from the wellbore. FMM provides accurate results in a calculation of drainage volume and pressure distribution over the domain. It also leads to consider high heterogeneity in reservoir properties such as permeability, porosity, and compressibility in a robust and efficient way. In this study, we show the application of FMM to coupled flow and geomechanics. We take one-way coupling from flow to geomechanics only, but not from geomechanics to flow. Although the one-way coupling is less accurate than the two-way coupling, it can be justified by cases such as compressible fluid or stiff rock, where the contribution from geomechanics to flow is not significant. In the numerical simulation, we further investigate the potential for fault activation along with heterogeneous permeability fields. Specifically, we place a vertical fault in the middle, considered as a weak zone. Then, by using the coupled FMM flow-geomechanics simulator, we show the numerical results of surface deformation as well as the evolution of effectives stress at the fault plane.

ABSTRACT: The uncertainties related with spatial variability and heterogeneities, naturally present in rock masses, play an important role in geotechnical engineering practice. A more accurate assessment and characterisation is increasingly in need due to their impact on the mechanical behaviour of heterogeneous rock masses. This paper presents a modelling methodology to simulate the Rock Quality Designation (RQD) empirical system in order to more accurately identify the position of fault systems and the rock mass geomechanical quality. The main methodology hereby proposed combines geostatistical techniques, which have proved to be efficient in identifying rock mass heterogeneities and in considering the spatial variability so that a more realistic geomechanical model of the rock mass is obtained. Geostatistics allows the simulation of one or more regionalized variables taking into account their spatial correlation and structural law. The approach uses the Turning Bands algorithm to perform the 3-Dimensional conditional simulation of the empirical system D. The main results show the capacity of the approach to model heterogeneous rock mass and allows the identification of rock mass zones with poor quality. An application to a tungsten mine deposit located in the North of Portugal is finally presented in order to illustrate and validate the methodology.

ABSTRACT: Optimal design of fluid-driven fracture networks to decrease the environmental impact of hydraulic fracturing operations requires a thorough understanding of the interaction between fluid-driven fractures and heterogeneous geomaterials from both numerical and operational standpoints. Although the effect of layered geomaterials in single fluid-driven fractures has been thoroughly discussed in previous studies, their effect on multiple simultaneous fractures is not well understood. In this study, the effect of the layered media, fracture intervals, injection rate and viscosity of the fracturing fluid on the behavior of simultaneous fluid-driven fractures was investigated using a coupled 2D hydro-mechanical extended finite element method. Fluid flow was modeled by lubrication theory and was coupled with rock deformations while it was assumed no fluid leakoff from the fractures’ surfaces. The results illustrate disturbance in the stress field in the multi-layered media. It was observed that the propagating fractures tend to deviate towards the layer with lower elastic modulus due to lower resistance against their propagation. This deviation is a function of the contrast between the elastic moduli of the layers. Also, it was observed that an increase in the spacing between fractures would result in a decrease in their deviation, which appears to be caused by a reduction in the stress shadowing effect. Furthermore, an increase in both injection rate and fluid viscosity leads to wider fractures and less digression, which seems to be a result of the greater induced stresses generated by the fluid-driven fracture. In conclusion, The elastic modulus contrast, fracture spacing, injection rate and fluid viscosity significantly affect the stresses induced by the fluid-driven fractures and their geometry in the heterogeneous medium and, therefore, appear to play a critical role in the interaction between fluid-driven fractures.