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In this work we present a workflow for modeling and inversion of physical parameters using ultrasonic wave velocities measured on dry and saturated samples of Bakken, Bazhenov shales and Niobrara marls. The forward problem is based on the well known theory of Ciz and Shapiro (2007) combined with the anisotropic generalization of two empirical elastic models for the rock matrix: the critical porosity model Nur et al. (1998) and Krief et al. model (1990). Moreover, taking into account the high variability of the physical properties of kerogen and clay minerals, and their influence on the mechanical properties of these rocks, the procedure also involves the numerical inversion of such properties, using an efficient numerical routine. The results found for the effective elastic properties and density of clay minerals and kerogen are reasonable taking into account those published in the reference literature. In all cases the quality of fit between real and synthetic data is analysed by means of an adequate error measure. The stability of the predicted elastic coefficients is verified using strain energy restrictions. The calibrated models are also used to quantify the influence of the effective porosity on the computations and for a fluid substitution problem. Finally, we found that even for weak anisotropy the generalized Krief's model requires at least three empirical parameters. We conclude that our novel anisotropic critical porosity model is a simpler and more efficient choice for rock-physics applications. • We present a workflow for modeling of elastic velocities and inversion of physical parameters of organic-rich shales. • We generalize empirical isotropic rock-matrix models for anisotropic rocks. • Our workflow works properly for shales of different maturity, without changing the rock-physics models • Our novel generalized critical porosity model turned out to be a simple and efficient choice for anisotropic rock-physics applications. [ABSTRACT FROM AUTHOR]

Most subsurface rock models consider salt bodies as homogenous masses and set to evaporite minerals constant values of elastic properties such as density, compressional and shear velocities, Young's modulus and Poisson's ratio. Lithological analyzes of outcrops and wells indicate that evaporites present large vertical and lateral heterogeneities. Recent studies have demonstrated that the knowledge of the elastic properties of rock salt can substantially benefit velocity modeling, seismic imaging, reservoir geomechanical analysis, prediction of wellbore stability and calculation of optimum fluid weight. However, few papers document the spatial estimation of elastic properties for salt formations. We propose an approach to characterize the internal structures of the salt bodies in the Santos Basin, offshore Brazil, using well and 3D seismic data. It starts with a rock-physics analysis at well-log scale, which reveals that the elastic properties of rock salt are highly correlated. Once the relationships of the elastic properties are established, we explore the functionality of the empirical equations as property predictors. We demonstrate that the elastic properties can be empirically estimated from compressional velocity. The comparison between the estimated and the measured well logs validates the estimation. Then, we perform the seismic inversion to generate the spatial distribution of the acoustic impedance. We derive compressional and shear velocities, density, Young's modulus and Poisson's ratio volumes by applying the empirical equations to the acoustic impedance volume. The blind well points out that, through this workflow, the seismic data can successfully predict the elastic properties of the salt formation in undrilled portions. • Studies of in-situ elastic behavior of evaporites. • Formulation of new empirical equations as property predictors. • Compaction has null influence on the elastic properties of rock salt. • Combination of seismic inversion and rock physics for quantitative characterization. • Review of multidisciplinary applications of elastic properties of rock salt. [ABSTRACT FROM AUTHOR]

There always exists the configuration of pores and throats in real rocks, and a pore space may connect with several throats. The pore-throat configuration could lead to the complex pore structure, furthermore, it could greatly influence the rock physical properties such as rock-electric and seepage characteristics. Therefore, a simple pore network model is proposed to characterize the complex pore structure using the throat-pore radius ratio. On the one hand, a simple pore network model is used to study the effect of the pore-throat structure on rock-electric characteristics, on the other hand, it provides a new avenue to interpret the permeability property by introducing the pore network model into the NMR method. The simulation results demonstrate that the complex pore-throat structure not only leads to the non-Archie phenomena, but also results in the electrical anisotropy. Moreover, by combining NMR method with the pore network model, the inversion T 2 spectrum could be further decomposed into pore and throat spectra, and the throat spectrum distribution are closely related to the seepage characteristics. Hence, it shows the potential to directly interpret the formation permeability on the basis of the throat spectrum. By comparing the distribution characteristics of throat spectrum to the measured permeabilities of cores, the results show that when the throat spectrum mainly distributes in the long relaxation time and the spectrum amplitude is strong, it is more likely to have good permeability. In addition, the well sections with long relaxation time and high amplitude of the throat spectrum correspond well to relatively high permeability zones in the field, which further verifies the effectiveness of the proposed method. • Non-Archie phenomenon and electrical anisotropy caused by pore structure difference in different directions are studied. • The total T 2 spectrum can be further decomposed into pore and throat spectra based on the pore network model. • The formation permeability can be intuitively interpreted from the throat spectrum distribution. [ABSTRACT FROM AUTHOR]

Fractal characteristics of porous media have been a focus of research in geosciences for several decades and measuring fractal dimensions has become a common method to describe the structural properties of porous media. In this paper, the fractal dimensions of solid phase, pore phase and interface between them are studied by box counting method based on digital rocks. The process-based modeling technique is utilized to construct models with different pore structure firstly, which includes four kinds: grain-size contrast, grain-size variety, compaction and cementation. Then the fractal dimensions of solid, pore and interface of these models are calculated and analyzed using box counting method through different statistical objects. Finally, the fractal dimensions of real digital rocks are calculated, and the relationship between fractal dimensions and rock properties such as pore structure, porosity and permeability is qualitatively analyzed. The research results indicate that only the interface fractal dimension can better distinguish and characterize the pore structure of process-based digital rock models with slight variation in porosity. On the other hand, if porosity of these models varies significantly, both pore fractal dimension and interface fractal dimension are available to distinguish and represent pore structure well, and pore fractal dimension is more sensitive and active to the change of pore structure and porosity. When using fractal dimensions to represent and analyze pore structure of real rocks, the fractal dimensions of pore and interface should be considered comprehensively. Furthermore, the interface fractal dimension is better than the pore fractal dimension in characterizing the pore structure of some sandstone digital rocks. • Only interface FD can characterize the pore structure of process-based models with slight variation in porosity. • The relationship between FD and porosity can be well fitted in process-based models. • The pore FD is more sensitive to the variations of porosity and pore structure in process-based models. • The interface FD is better than the pore FD in characterizing the pore structure of some sandstone digital rocks. [ABSTRACT FROM AUTHOR]

Abstract The main objective of this study is to investigate the impact of the depositional and diagenetic processes on the petrophysical and mechanical properties of the Lower Miocene Moghra Formation sandstones exposed at the Qattara Depression, Northwestern Desert, Egypt. Wе conducted sеvеral pеtrophysical and mеchanical invеstigations on a largе numbеr of corе samplеs collеctеd from thе study area to dеtеrminе thеir pеtrophysical and mechanical charactеristics. Rеsults of pеtrographical, scanning еlеctron microscopе (SЕM), and thе X-ray diffraction (XRD) analysеs rеvеalеd that thе studiеd sandstonеs arе composеd еssеntially of quartzarеnitеs with minor limеstonе and shalе intеrcalations and can bе groupеd into thrее sеdimеntary lithofaciеs: fossilifеrous dolomitic quartzarеnitеs, fеrruginous quartzarеnitеs and calcarеous quartz arеnitе. Thе main diagеnеtic procеssеs еncountеrеd in thе Moghra sandstonеs arе compaction, cеmеntation, and dissolution. Thеsе procеssеs significantly affеctеd thе porosity and influеncеd thе pеtrophysical and mеchanical paramеtеrs of thе studiеd sandstonеs. Thе Moghra sandstonеs havе avеragе valuеs of 14.51%, 2.24 g/cm3, 22.38 mD, 45.77%, and 3377 m/s, for porosity (φ), bulk density (ρ b), pеrmеability (K), irrеduciblе watеr saturation (S wirr), and thе P- wavе vеlocity (Vp), rеspеctivеly. In addition, thеsе rocks havе avеragе valuеs of 83.98 MPa, 5.97 MPa, and 34.42, for thе unconfinеd comprеssivе strеngth (UCS dry), thе point load strеngth indеx (IS 50), and thе Schmidt hammеr numbеr (SHN), rеspеctivеly. Significant rеlationships, with modеratе/high corrеlation coеfficiеnts, havе bееn obtainеd bеtwееn thе invеstigatеd paramеtеrs of thе studiеd sandstonеs. The studied sandstones, however, showed no clustering of their petrophysical and mechanical properties based on their facies type. Thе present rеsults indicatе that both porosity and bulk dеnsity, which arе in turn thе products of thе dеpositional and diagеnеtic history of thе invеstigatеd rocks, arе major paramеtеrs controlling the othеr pеtrophysical and mеchanical propеrtiеs of the studied rocks. Graphical abstract Image 1 Highlights • The manuscript is concerned mainly with the impacts of the depositional and diagenetic processes on the petrophysical and mechanical properties of clastic rocks collected from the Qattara Depression, Western Desert, Egypt. • Thе main diagеnеtic procеssеs еncountеrеd in thе Moghra sandstonеs arе compaction, cеmеntation, and dissolution. • Thе pеtrophysical (mainly porosity) and mеchanical paramеtеrs of thе studiеd sandstonеs have been greatly influenced by the different diagenetic processes. • Porosity and bulk dеnsity, resulting from thе invеstigatеd rocks, arе major paramеtеrs controlling othеr pеtrophysical and mеchanical propеrtiеs. [ABSTRACT FROM AUTHOR]

Abstract A new Enhanced Oil Recovery (EOR) method is proposed by combining the effects of a traditional polymer flooding and exploiting the advantages that nanotechnology presents in the oil industry. Thus, a novel technique is introduced and applied to a 2D reservoir model with a two-phase, five-component system (aqueous, oil phases and water, hydrocarbon, polymer, nanoparticles and salt). For the polymer characterization, a novel approach is presented considering the polymer's architecture and its degradation in order to calculate the physical properties, which has never been reported in reservoir simulation. The presence of the nanoparticles affects mainly the rheological behavior and the wettability of the rock, increasing the oil phase mobility. Moreover, negative effects such as particle aggregation and sedimentation are also modeled using a novel formulation in reservoir simulation. The combined action of polymers and nanoparticles allowed increasing the recovery factors beyond standard EOR processes, and it represents a suitable alternative to replace traditional combined methods, such as Surfactant-Polymer (SP) or Alkaline-Surfactant-Polymer (ASP). This is due to the fact that the nanoparticles act, to a greater or lesser extent, on the wettability, rheological and interfacial properties of fluids and rock formation, which is complemented with the polymer's viscosifying properties. Moreover, economical factors could also render this technique more attractive, since the nanoparticles' associated costs are substantially lower than those from surfactant flooding. This simulation proves the potential of nanotechnology as a mean to boost traditional EOR techniques in order to further increase the operative life of mature oil fields. Highlights • A novel oil recovery technique is proposed combining nanotechnology with polymers. • The architecture of the polymer molecules is considered to calculate the viscosity. • The polymer-nanoparticles interactions are considered using a novel formulation. [ABSTRACT FROM AUTHOR]

Abstract Deterministic approach in selecting mud weight window at pre-drill condition has uncertainties for wellbore stability analysis. Quantitative Risk Assessment (QRA) technique has been successfully used in pre-drill condition addressing the variability of input parameters like, principal stresses and rock properties. The output of this process recommends the mud weight window with probability of drilling success which can avoid the wellbore collapse and lost circulation events. This kind of stochastic approach to predict safe mud weight window can assure stable wellbore with significant cost effectiveness related to drilling success. A workflow to perform QRAis demonstrated which starts with derivation of stresses in deviated wellbore. Seismic velocity data has been used to estimate pore pressure and validated with formation pressure obtained from reservoir characterization instrument data for a study well located in east coast of India. Mogi-Coulomb failure criteria have been used to estimate required mud weights to avoid shear failure. Mud weights required to avoid lost circulation has also been calculated. Then QRA has been accomplished to predict safe mud weight window sat specific depth within 14 ¾" hole and borehole section (12 ¼"). The results have been validated with real data set and based on that exercise, mechanical earth model and uncertainty associated with input parameters for study well has been established. A feasibility study has been performed to check the viability of drilling a near horizontal (75ο inclination) well along the reservoir unit with azimuth of 250ο. The wellbore collapse and lost circulation curves intersect near 35% probability of success point. The results of QRA indicate that the inclination and azimuth would not be favorable for successful drilling in this scenario. Based on these QRA, recommendations have been made in data acquisition plan for future drilling to reduce the variability in input parameters and successful completion of well. Highlights • Rock properties and principal stresses are applied in pre-drill condition for mud weight selection. • Demonstration of Quantitative Risk Assessment technique. • Sensitivity of the principal stresses and rock strength has been analysed. • Recommendations have been made in data acquisition plan for future drilling. [ABSTRACT FROM AUTHOR]

The main objective of this work is to study formation damage phenomenon associated with in-situ migration of fines in rock samples from terrigenic reservoirs of Eastern Siberia experimentally. Results of oil flooding for the wide range of flow rates and permeabilities show that oil does not lead to fine mobilization and its consequent retention with permeability reduction. The permeability decrease is observed only when water is flowing in the porous space. Water itself is shown to be a strong driver of self-colmatation, which is likely because of its intensive physicochemical reaction with pore surface. Performing multiple core flooding tests and analyzing the data, we define the range of rock properties and flow conditions corresponding to development of the situ formation damage (self-colmatation). We classify self-colmatation over 5 types characterized with different behaviors of permeability decrease. We comprehensively study the dependencies of permeability reduction specifics on rock properties and flooding conditions. The dependencies account for multiple parameters correlated with permeability reduction: absolute permeability, residual oil saturation, three characteristic pore diameters, four characteristic grain diameters and four major minerals within the rock structure. We discovered that the increase of formation damages are associated with high absolute permeability and low residual oil saturations. It was shown that characteristic size of migrating fines is 0.01–0.005 m m and the diameter of pores where these fines can be strained is 12 μ m . We derive a single numerical criterion to estimate the influence of 13 parameters on colmatation process. The absolute permeability and the fraction of pore throats with diameters higher than 30 μ m are shown to be the strongest influencers on colmatation. [ABSTRACT FROM AUTHOR]

Ultra-tight formations generally exhibit heterogeneous, anisotropic, and pressure-dependent petrophysical properties. Conventional core analyses tend to generate inconsistent petrophysical estimates when the physical measurements are performed on different core samples extracted from ultra-tight formations. The discrepancies in petrophysical estimates are further escalated due to pressure- and pore-size-dependent fluid flow mechanisms in the nanopores of ultra-tight rocks. In the first part of this two-paper series publication, a method is proposed to simultaneously estimate four petrophysical properties by inverting laboratory-based pressure-step-decay measurement on a single ultra-tight rock sample; thereby, circumventing the petrophysical inconsistencies due heterogeneity and anisotropy. In this second part, an inversion algorithm is developed to simultaneously estimate six petrophysical parameters by processing the laboratory pressure-step-decay measurements. Similar to the first part, the laboratory step-decay measurement involves nitrogen gas injection into an ultra-tight rock sample at multiple stepwise pressure increments and high-resolution pressure-decay measurement at the outlet, which is followed by a deterministic inversion of the measured downstream pressure data based on numerical finite-difference modeling of nitrogen gas flow in the ultra-tight rock sample. Unlike the first part, the forward model of the nitrogen flow through the nanoscale pores of the ultra-tight rock samples accounts for not only the gas slippage but also transitional flow and Knudsen diffusion. This work improves the petrophysical estimates previously obtained from the inversion of pressure-step-decay measurements modeled based on only a Klinkenberg-type gas slippage as proposed in the first part. A transitional transport model is implemented to account for the separate and simultaneous occurrence of gas slippage and diffusion across an ultra-tight rock sample during a pressure-step-decay measurement performed in the pore pressure range of 5 psi to 500 psi at room temperature. The proposed interpretation method was applied to nine 2-cm-long, 2.5-cm-diameter core plugs extracted from a 1-ft 3 ultra-tight pyrophyllite block. We estimated the intrinsic permeability, effective porosity, pore-volume compressibility, pore throat diameter, and two slippage-diffusion coefficients of each sample. Estimation accuracy relies on the forward model of the fluid flow in ultra-tight rock sample and on the error minimization algorithm implemented in the inversion scheme. For the nine ultra-tight samples, on an average, the estimated intrinsic permeability, effective porosity, pore-volume compressibility, and pore throat diameter are 86 nd, 0.036, 2.6E-3 psi −1 , and 195 nm, respectively. Notably, the two slippage-diffusion coefficients indicate that the gas transport mechanism in the nine ultra-tight pyrophyllite samples during the pressure-step-decay measurement is completely dominated by slip flow without any Knudsen diffusion or transitional flow, despite the Knudsen numbers across each sample during the entire duration of the pressure-step-decay measurements were determined to be in the range of 0.01–1. This observation contradicts the widely accepted qualitative classification of gas transport mechanism based on the Knudsen numbers and mandates an inversion-based approach to identify the fluid flow mechanism and an appropriate fluid flow model for nanoscale pores. [ABSTRACT FROM AUTHOR]

Many experimental observations show that the shear modulus of carbonate rocks changes in some cases upon fluid saturation. This observation is inconsistent with the presumption inherent to Gassmann's model that the shear modulus is independent of the fluid saturant. If the shear modulus change after saturation is ignored, the reliability of analyses of amplitude-versus-offset (AVO) and time-lapse seismology would be affected. So the elastic properties and velocities of saturated carbonates with complex pore structure are investigated. We made synthetic carbonate cores containing either void cracks or vuggy pores by first embedding predesigned aluminum foils or NaCl grains into the two-component matrix (carbonate cuttings and epoxy) and then leaching them out. We measured the ultrasonic P-and S-wave velocities of eight synthetic cores at different saturation conditions, and compared our measurements with theoretical predictions. The results indicate that changes in the shear modulus after saturation depend on both the pore structure and the pore saturant. Samples with cracks show shear stiffening because the viscous coupling is more active in narrow pores. Regardless of the pore structure, the shear moduli at kerosene saturation are larger than that at brine saturation, because the completely wetting kerosene provides a more shear-resistant solid-fluid boundary. The dynamic moduli changes with saturation increase as the secondary porosity increases. Gassmann's equation underestimates the velocities at shear stiffening and overestimates the velocities at shear weakening. The velocity deviation between Gassmann's prediction and experimental observations increases as the increase of shear modulus change. [ABSTRACT FROM AUTHOR]

The temperature effect on rock physical properties, including permeability, is still topical, since the available findings are quite contradictory. In the current study of temperature effect on rock permeability, the experiments have been conducted on eight rock samples of different permeability (4) and lithology (4). The results obtained strongly indicate that the temperature effect depends on the initial permeability of core samples: for low-permeability (LP) or higher-permeability (HP) rocks, the temperature-permeability dependence exhibits a negative nonlinear correlation. When the temperature increases from 20 °C to 100 °C, the permeability of LP rocks decreases by 24–70%. However, in ultra-LP rocks, a positive nonlinear correlation has been revealed between temperature and permeability: when the temperature was increased from 100 to 800 °C, the permeability of ultra-LP rocks exhibited a gradual increase within the initial range from 200 °C to 400 °C, and a sharp rise, while in the medium range from 400 to 600 °C the lithology threshold value was reached, the thermal-induced tensile stress in the rock exceeded its yield stress, which resulted in a sharp increase of permeability in the final temperature range from 600 to 800 °C. Based on the experimental data obtained in this study, a theoretical model is proposed, which implies a positive correlation between rock permeability, pressure, and temperature. [ABSTRACT FROM AUTHOR]

Geomechanical effects monitoring on reservoir rock and fluid properties response during the oil production curve are essential to improve oil recovery in a petroleum field. Incorporating geomechanics to flow models become the mathematical formulation regarding well-test and reservoir engineering more realistic because geomechanical parameters, e.g., in situ and overburden stress, as well as Biot's coefficient, play a fundamental role in pressure response. Hence, permeability stress-sensitive oil reservoirs are the scope of various research in the petroleum industry for minimizing formation damage during drilling, completion, and stimulation operations. In this context, mechanical formation damage control plays a key role in preventing early-permeability loss that may result in reservoir compaction and oil field disinvestments. This work develops a new analytical solution for the nonlinear hydraulic diffusivity equation (NHDE) with instantaneous point-source/sink effects in permeability effective stress-sensitive oil reservoirs. The proposed model considers Biot's effective stress change in the permeability response, and a new deviation factor is derived from comparing the nonlinear effect concerning the constant permeability classical solution and a decoupled case available in the literature. The calibration methodology is performed using a numerical simulator named IMEX®, widely used in formation evaluation works, and the results presented high convergence. The findings of this study allowed us to notice the role of overburden stress, oil flow rate, deviation factor, and Biot's coefficient in permeability change during production in the diagnostic plots. Thereby, the modeling developed in this paper becomes a useful and attractive tool for predicting and monitoring permeability loss, oil flow rate specification, and reservoir history matching. • Nonlinear Hydraulic Diffusivity Equation for oil flow in porous media. • Permeability-Effective Stress-Sensitive Reservoirs. • Biot's equation. • Mechanical formation damage control. • New Volterra's second kind coupled integro-differential-GF model. • Permeability variation as function of pore pressure. • Infinite-acting-nonlinear-oil-flow. • Asymptotic Series expansion. • Permeability curves are built through experimental data. [ABSTRACT FROM AUTHOR]

To explore the rock-breaking efficiency and vibration characteristics of polycrystalline diamond compact bit in heterogeneous rock, this paper analyzes the typical vibration characteristics and failure modes of polycrystalline diamond compact bit. Then, the transverse combination of rocks was innovatively used to simulate a situation of soft-hard interbedded formation, forming three kinds of transversely combined heterogeneous rock samples with different degrees of heterogeneity. We conducted a series of laboratory rock-breaking experiments and the experimental results indicate that rock heterogeneity greatly impacted vibration acceleration, lateral bending moment, rate of penetration, and drilling trend. With the increase in weight on bit and rotation speed, the rate of penetration gradually increases. However, the tangential, axial, and radial vibration acceleration amplitude of the bit all increase simultaneously, which implies that the vibration impact generated by rock-bit interaction increased. The difference in the cutting depth of the drill bit in the heterogeneous formation causes low efficiency. The stronger the heterogeneity, the lower the rate of penetration. Rock heterogeneity, especially the rock properties of the combined rock samples, significantly impact acceleration and lateral bending moment. As rock heterogeneity increased, the bit acceleration increased significantly, intensifying the bit vibration; the lateral bending moment increased slightly, but its fluctuation intensified. The strength difference of heterogeneous rock causes eccentricity, the harder rock exerts greater force on the bit, causing the bit to deviate from the original trajectory. The greater the difference, the greater the eccentricity, consequently, the more the bit shifts to the softer side. Adjusting rotation speed and depth of cut control may be feasible solutions to solve the problem of low drilling speed and high vibration in heterogeneous formation. It is hoped that the findings in this paper will be helpful to explore a reasonable way to reduce vibration while maintaining high efficiency. • Typical vibration characteristics and failure modes of PDC bit are analyzed. • Transversely combined heterogeneous rock samples are innovatively formed and used. • Rock heterogeneity greatly impacts efficiency, vibration and drilling trend of PDC bit. • Adjusting rotation speed and depth of cut control may be feasible solutions. [ABSTRACT FROM AUTHOR]

The petrophysical and elastic properties of the carbonate rocks controlled by strike-slip fault are still poor understood due to their significant complexities and strong heterogeneities, causing challenges for the exploitation and development of these carbonate reservoirs. To better comprehend the heterogeneity of petrophysical and elastic properties of the fault-controlled carbonate rocks, a small carbonate strike slip fault zone is selected, which is located in Yangjikan section in the Tarim basin. We combine the geostatistical, microscopic observation, petrophysical and ultrasonic analyses to characterize and understand the complexities and heterogeneity of petrophysical and elastic properties with different distance to the main fault core. The results show significant complexities and heterogeneities of petrophysical and elastic properties, and the variations of rocks drilled from the fault core are relatively drastic compared to those from the damage zone. The equivalent pore aspect ratios of the rocks are calculated from the differential effective medium theory, the values in the fault core are much higher compared to those from the damage zone, which can discriminate the pore network architectures and can represent reference for determination of the boundary of fractured damage zone. The controlling factors on the heterogeneity of the petrophysical and elastic properties for the selected fault zone are discussed, which mainly include the influence of fault structure position on fracture development, fluid selective filling on effective fracture and pore development, and the sequence on pore development. The results can contribute to the recognition and prediction of the petrophysical and elastic properties and hydrocarbon exploration in carbonate strike-slip fault zone in the Tarim Basin, and can provide reference for the construction of integrate multiscale heterogeneities models. • The heterogeneity of petrophysical and elastic properties of strike-slip fault are investigated. • The equivalent pore aspect ratios are calculated to discriminate pore the pore network architectures. • The controlling factors on the heterogeneity of the petrophysical and elastic properties for strike-slip fault zone are discussed. [ABSTRACT FROM AUTHOR]

Geomechanical effects monitoring on reservoir rock and fluid properties response during the oil production curve are essential to improve oil recovery in a petroleum field. Incorporating geomechanics to flow models become the mathematical formulation regarding well-test and reservoir engineering more realistic because geomechanical parameters, e.g., in situ and overburden stress, as well as Biot's coefficient, play a fundamental role in pressure response. Hence, permeability stress-sensitive oil reservoirs are the scope of various research in the petroleum industry for minimizing formation damage during drilling, completion, and stimulation operations. In this context, mechanical formation damage control plays a key role in preventing early-permeability loss that may result in reservoir compaction and oil field disinvestments. This work develops a new analytical solution for the nonlinear hydraulic diffusivity equation (NHDE) with instantaneous point-source/sink effects in permeability effective stress-sensitive oil reservoirs. The proposed model considers Biot's effective stress change in the permeability response, and a new deviation factor is derived from comparing the nonlinear effect concerning the constant permeability classical solution and a decoupled case available in the literature. The calibration methodology is performed using a numerical simulator named IMEX®, widely used in formation evaluation works, and the results presented high convergence. The findings of this study allowed us to notice the role of overburden stress, oil flow rate, deviation factor, and Biot's coefficient in permeability change during production in the diagnostic plots. Thereby, the modeling developed in this paper becomes a useful and attractive tool for predicting and monitoring permeability loss, oil flow rate specification, and reservoir history matching. • Nonlinear Hydraulic Diffusivity Equation for oil flow in porous media. • Permeability-Effective Stress-Sensitive Reservoirs. • Biot's equation. • Mechanical formation damage control. • New Volterra's second kind coupled integro-differential-GF model. • Permeability variation as function of pore pressure. • Infinite-acting-nonlinear-oil-flow. • Asymptotic Series expansion. • Permeability curves are built through experimental data. [ABSTRACT FROM AUTHOR]

To explore the rock-breaking efficiency and vibration characteristics of polycrystalline diamond compact bit in heterogeneous rock, this paper analyzes the typical vibration characteristics and failure modes of polycrystalline diamond compact bit. Then, the transverse combination of rocks was innovatively used to simulate a situation of soft-hard interbedded formation, forming three kinds of transversely combined heterogeneous rock samples with different degrees of heterogeneity. We conducted a series of laboratory rock-breaking experiments and the experimental results indicate that rock heterogeneity greatly impacted vibration acceleration, lateral bending moment, rate of penetration, and drilling trend. With the increase in weight on bit and rotation speed, the rate of penetration gradually increases. However, the tangential, axial, and radial vibration acceleration amplitude of the bit all increase simultaneously, which implies that the vibration impact generated by rock-bit interaction increased. The difference in the cutting depth of the drill bit in the heterogeneous formation causes low efficiency. The stronger the heterogeneity, the lower the rate of penetration. Rock heterogeneity, especially the rock properties of the combined rock samples, significantly impact acceleration and lateral bending moment. As rock heterogeneity increased, the bit acceleration increased significantly, intensifying the bit vibration; the lateral bending moment increased slightly, but its fluctuation intensified. The strength difference of heterogeneous rock causes eccentricity, the harder rock exerts greater force on the bit, causing the bit to deviate from the original trajectory. The greater the difference, the greater the eccentricity, consequently, the more the bit shifts to the softer side. Adjusting rotation speed and depth of cut control may be feasible solutions to solve the problem of low drilling speed and high vibration in heterogeneous formation. It is hoped that the findings in this paper will be helpful to explore a reasonable way to reduce vibration while maintaining high efficiency. • Typical vibration characteristics and failure modes of PDC bit are analyzed. • Transversely combined heterogeneous rock samples are innovatively formed and used. • Rock heterogeneity greatly impacts efficiency, vibration and drilling trend of PDC bit. • Adjusting rotation speed and depth of cut control may be feasible solutions. [ABSTRACT FROM AUTHOR]

The petrophysical and elastic properties of the carbonate rocks controlled by strike-slip fault are still poor understood due to their significant complexities and strong heterogeneities, causing challenges for the exploitation and development of these carbonate reservoirs. To better comprehend the heterogeneity of petrophysical and elastic properties of the fault-controlled carbonate rocks, a small carbonate strike slip fault zone is selected, which is located in Yangjikan section in the Tarim basin. We combine the geostatistical, microscopic observation, petrophysical and ultrasonic analyses to characterize and understand the complexities and heterogeneity of petrophysical and elastic properties with different distance to the main fault core. The results show significant complexities and heterogeneities of petrophysical and elastic properties, and the variations of rocks drilled from the fault core are relatively drastic compared to those from the damage zone. The equivalent pore aspect ratios of the rocks are calculated from the differential effective medium theory, the values in the fault core are much higher compared to those from the damage zone, which can discriminate the pore network architectures and can represent reference for determination of the boundary of fractured damage zone. The controlling factors on the heterogeneity of the petrophysical and elastic properties for the selected fault zone are discussed, which mainly include the influence of fault structure position on fracture development, fluid selective filling on effective fracture and pore development, and the sequence on pore development. The results can contribute to the recognition and prediction of the petrophysical and elastic properties and hydrocarbon exploration in carbonate strike-slip fault zone in the Tarim Basin, and can provide reference for the construction of integrate multiscale heterogeneities models. • The heterogeneity of petrophysical and elastic properties of strike-slip fault are investigated. • The equivalent pore aspect ratios are calculated to discriminate pore the pore network architectures. • The controlling factors on the heterogeneity of the petrophysical and elastic properties for strike-slip fault zone are discussed. [ABSTRACT FROM AUTHOR]

Recently, the petroleum industry has focused on deeply buried reservoir discoveries and exploring potential CO 2 storage sites close to existing infrastructure to increase the life span of already operating installations to save time and cost. It is therefore essential for the petroleum industry to find an innovative approach that exploits the existing core- and well log data to be successful in their endeavor of effectively characterizing and predicting reservoir quality. Continuous data sources (e.g. wireline logs) have a huge potential compared with expensive, time inefficient and sporadic data from cores in determining reservoir quality for use in a regional context. However, whereas core analysis offers in-depth knowledge about rock properties and diagenetic processes, continuous data sources can be difficult to interpret without a formation-specific framework. Here, we demonstrated how the pre-existing core data could be effectively used by integrating petrographic- and facies data with a pure predictive machine learning (ML) based porosity predictor. The inclusion of detailed core analysis is important for determining which reservoir parameter(s) that should be modeled and for the interpretation of model outputs. By applying this methodology, a framework for deducing lithological and diagenetic attributes can be established to aid reservoir quality delineation from wireline logs that can be used in frontier areas. With the ML porosity model, a Random Forest Regressor, the square of the correlation was 0.84 between predicted- and helium porosity test data over a large dataset consisting of 38 wells within the Stø Formation across the SW Barents Sea. By integrating the continuous ML porosity logs and core data, it was possible to differentiate three distinct bed types on wireline log responses within the Stø Formation. Particularly, the relationship between Gamma ray (GR) and porosity was effective in separating high porosity clean sand-, low porosity cemented clean sand and more clay and silt rich intervals. Additionally, in the P-wave velocity (VP) - density domain, separation of high porosity clean sand- and heavily cemented low porosity clean sand intervals were possible. The results also show that the ML derived porosity curves coincide with previously published and independent facies data from a selection of the wells included in the study. This demonstrates the applicability of the model in the region, because the Stø Formation has been described to exhibit similar lithological- and mineralogical properties over large parts of the Western Barents Sea area. Even though, continuous porosity data could be estimated from other sources like VP, neutron or density logs, this would generally require matrix and fluid information. This study demonstrated the effectiveness of the ML model in generating continuous porosity logs that are useful for characterizing and predicting reservoir properties in new wells. This methodology offers a workflow for exploiting already acquired core and well log data for frontier exploration that can be adapted to other formations and exploration scenarios worldwide. • Machine learning derived porosity can aid regional reservoir quality delineation. • Efficient use of historical core data to establish predictive frameworks. • ML guided distinct well log responses can differentiate reservoir units of varying quality. [ABSTRACT FROM AUTHOR]

Enhanced oil recovery (EOR) methods are generally applied in the tertiary mode to the depleted oil reservoir to increase the recovery factor through enhanced microscopic displacement and macroscopic sweep efficiency. Choosing a specific EOR method for a candidate reservoir characterized by specific rock and fluid properties is governed by standard EOR screening criteria. It is not uncommon that EOR researchers to come up with innovative ideas and/or good reservoir engineering practices to extend the applicability of those methods beyond that specified by the standard criteria. As per the standard criteria., nitrogen EOR can work at its best in deeper reservoirs where the chemical and thermal method fails. Further, nitrogen EOR is preferred for light oil characterized by low viscosity, high gravity, and the presence of lighter components so that miscibility needed for enhancing the microscopic displacement could be achieved. Regarding the sweep efficiency, thin reservoirs are preferred to avoid gravity override due to the low viscosity and density of nitrogen. Despite the abundance of nitrogen and advancements made to the nitrogen-based EOR, no significant efforts were made to analyze whether those advancements have exceeded the standard screening criteria. This paper attempts to narrow this gap. Initially, a detailed compilation of the relevant nitrogen EOR work performed at the laboratory, pilot, and field scale is done by extracting the results from the available literature. Then the rock and fluid properties reported in each of the compiled works are compared with that of the standard criteria's stipulation to identify and classify the parameters that are exceeding and those not exceeding the standard criteria. Then a comparative analysis is done using the reported recovery factor to provide a statement for each compilation whether those exceeding parameters have indeed improved the nitrogen EOR performance. Based on the conducted study, properties such as oil viscosity, oil gravity, thickness, and oil composition, could be exceeded only when the depth is conducive to generating high pressure. The inert nature of nitrogen makes high pressure an important requirement for inducing miscibility and therefore, the reservoir depth of more than 6000 ft, stipulated in the standard criteria remains a must for an efficient nitrogen EOR process that targets microscopic displacement efficiency. Overall, depth and therefore the pressure requirement is a major influencing factor for nitrogen EOR to operate in its best miscible mode. Most of the recent studies were conducted at high pressures in order to induce miscible flooding pressure for increasing the oil recovery. [ABSTRACT FROM AUTHOR]

Fractured-vuggy carbonate reservoirs have complex pore structure, significant heterogeneity, and irregular permeability-porosity relation, which make existing evaluation methods unable to accurately calculate the permeability. To investigate the flow characteristics of carbonate rocks with triple-porosity, 3D digital rock models were constructed from X-ray computed tomography (CT) scanning images of carbonate cores collected in the field, and the physical properties of rocks were obtained by combining digital rock analysis (DRA) and nuclear magnetic resonance (NMR) experiment. The effects of fractures and vugs on the permeability of carbonate rocks was investigated using the Stokes-Brinkman method, and then a new fractured-vuggy carbonate permeability model was developed by artificially adding vugs and fractures. The results indicate that the carbonate pores can be divided into matrix pores, vugs, and fractures according to their sizes by combining digital rock analysis and T 2 spectrums. The transport resistance is effectively reduced by fractures and vugs, which leads to the change of the flow path. For tight carbonate rocks, the dominant flow path formed through fractures is a crucial factor affecting permeability. On the contrary, unconnected vugs have less effect on permeability. Finally, the new permeability model was applied to the logging interpretation of field data. The new model is in better agreement with the permeability analysis of field cores, which greatly improves the permeability calculation accuracy of the triple-porosity reservoir in the study area. • A pore type distinction and physical properties determination method is proposed. • The fluid flow behaviors of the vugs and fractures in the digital rock models were simulated. • The effects of vugs and fractures on permeability were investigated. • A new fractured-vuggy carbonate permeability model of triple-porosity media was developed. [ABSTRACT FROM AUTHOR]

Axial-torsional coupled percussive drilling is a novel technology to enhance the rate of penetration (ROP), which takes advantage of both axial and torsional percussive drilling technologies. Our paper focuses on experimental investigations on coupled percussive drilling. A novel experiment setup, using a rock breaking tester, was developed to carry out dynamic drilling tests on granite specimens under different impact modes, weight on bit (WOB), rotation rates, and lithologies. Based on the optimization analysis of window functions, by combining the fast Fourier transform (FFT) and short-time Fourier transform (STFT) processing methods, the spectrum and 3D time-frequency-amplitude evolution characteristics of coupling impact response signals were demonstrated. According to experimental results, a high-frequency and high-amplitude rotational rate and lower torque are produced in coupling impact. The agglomeration of the cutting force is alleviated and the occurrence of "stick-slip effect" is slowed down. Compared with axial impact, the penetration depth and ROP are increased by 173.38% and 182.74% in coupling impact, respectively. As the WOB increases, a stable-high frequency and high amplitude rock breaking torque is generated, which increases the cutting force and ROP. There is an optimal ratio between the rotation rate controlled by the axial rotator and the torsional impact frequency, which takes advantage of axial and torsional percussion for a bit and obtains the optimal speed-raising effect. The variation of rock mechanical properties has a significant influence on the amplitude of time domain signals in coupling impact. Our results in this paper are of great value for future studies of axial-torsional coupled percussive drilling. • A novel experiment setup, using a rock breaking tester, was developed to carry out dynamic drilling tests on granite specimens under different impact modes in our paper. • Compared with axial impact, a high-frequency and high-amplitude rotational rate and lower torque are produced in coupling impact. • A stable-frequency and high-amplitude rock breaking torque is generated with the WOB increases. • An optimal ratio between the rotation rate and the torsional impact frequency obtains the optimal speed-raising effect. • The variation of rock mechanical properties has an effect on the amplitude of time domain signals in coupling impact, but has no effect on frequency. [ABSTRACT FROM AUTHOR]

Optimum solutions for geologic modeling and reservoir simulation in industries such as oil and gas recovery and carbon capture and storage require accurate characterization of reservoir properties, which are often heterogeneous. In this study, high-quality micro-computed tomography (CT) images (1.475-μm/pixel resolution) of a sandstone core acquired from the Bell Creek oil field, USA, were used to provide nondestructive analysis of pore- and core-scale heterogeneity across measurement scales of 94–566 μm. In addition to characterizing the as-received sample, the core sample was flooded with brine to evaluate the capacity of the core sample to receive injected fluids. The micro-CT images were systematically segmented into pore spaces and grains via machine learning (ML) steps including image preprocessing, label creation using a traditional ML method based on limited manual image annotation, and finally U-Net segmentation. The segmented image stacks were reconstructed into digital cubes of various scales of voxel lengths. The 3D porosity values were calculated for all the digital cubes, and the fractal dimensions of the cubes were estimated using a box-counting method. The results showed that smaller cubes had greater heterogeneity and that the porosity values could be accurately estimated by fractal dimension and voxel lengths using ML models. For the core sample with brine flooding, the ratio of pores filled by brine to the total pore space was related to the porosity and could also be accurately estimated by porosity, fractal dimension, and voxel lengths using ML models. The results of this study demonstrate that the concept of fractal dimension can be a useful vector to perform upscaling analysis of sandstone rock heterogeneity from the pore to core scale and that fractal dimensions can be used to estimate porosity values and pore space-filling capacity across those scales. • Heterogeneity is an issue for accurate characterization of reservoir properties. • U-Net segmentation was used to segment CT images into separate objects. • Fractal dimension was used to characterize the pore complexity of the rocks. • Porosity is correlated with voxel length and fractal dimension across scales. • Fractal dimension can be used to predict pore space-filling capacity. [ABSTRACT FROM AUTHOR]

The applications of the vibro-seismic technology in the petroleum industry are the subject of interest for many researchers. These applications are oriented to enhancing the reservoir rock and fluids properties and thus increasing reservoirs productivity. The vibro-seismic technology is based on vibrating the formation rock with a pre-determined frequency and energy (amplitude) using either an acoustic wave or a physical vibrator. Previous laboratory work reported that the combination of these parameters can result in enhancing or also damaging the rock properties. One important parameter in the vibration process that was not fully investigated by the previous published work is the effect of the vibration time (duration) on the reservoir properties. Also, none of the previous work discussed the optimum combinations of these parameters that ensures the enhancement of the rock properties. In this paper, laboratory measurements are conducted on multiple core plugs, field and outcrop, using various combinations of the parameters, frequency, amplitude, and time to determine the optimum combination that ensures the enhancement of the porosity and the permeability of the reservoir rock. The duration (time) in this work is also varied between continuous and time-steps. In the continuous time measurements, the vibrating frequency and the amplitude are kept constant for the entire period of the vibration process. In the time-steps measurements the vibration stopped after every time step and the measurements of the properties are taken to determine the optimum time that generated the maximum positive impact on the rock properties. Another angle in this research is oriented to answer an important question; can the damaged property due to the vibration be reversed or at least partially reversed by repeating the vibration with a better set of parameters. The laboratory work showed that the optimization of the vibration parameters is essential before starting any field trials. It is very critical to determine the optimum vibrating parameters in the laboratory using core plugs before the field applications. The wrong combination of the three parameters can result in damaging the rock properties specially the rock permeability. Also, a very important finding in this work is that the damaged parameters can be totally and/or partially recovered if the vibration is repeated with the optimum set of the vibration parameters. • This work aims to optimize the vibration parameters of the vibro-seismic applications in the oil fields. • It also investigated the possibility of reversing damages if occurred due to the vibration. [ABSTRACT FROM AUTHOR]

The problem of a plane strain hydraulic fracture propagating in a layered formation is considered. Fracture toughness, in-situ stress, and leak-off coefficient are assumed to vary by layer, while the elastic properties are kept constant throughout the domain for simplicity. The purpose of this study is to develop a numerical algorithm based on a fixed mesh approach, which is able to solve the above problem accurately using elements which can even be larger than the layer size. In order to do this, the concept of fictitious tip stress is first introduced for determining the fracture front location. In this technique, an additional stress is applied to the tip element to suppress the opening and to mimic the width corresponding to the actual fracture front location. A theoretical basis for this concept has been established and it is further calibrated for piece-wise constant elements. Once the ability to track the crack front location is developed, the effect of layers is included by varying properties as a function of front location. Several numerical examples benchmarking the numerical solution, as well as highlighting capabilities of the algorithm to tackle multiple thin layers accurately are presented. • Numerical algorithm for hydraulic fracture modeling with partially filled elements. • Tip asymptotic solution is used as a propagation criterion. • Multiple layers of rock properties are assigned for each tip element. • Largely mesh independent results regardless of input parameters and layers. • Ability to explicitly take into account the effect of thin layers. [ABSTRACT FROM AUTHOR]

Fracability evaluation in unconventional reservoirs is one of the most important initiatives for economic success. Most evaluation methods in geophysics and well logging are based on calculating rock mechanical properties, in which a frequently used term is brittleness. However, oil and gas production, mainly determined by effective natural fracture networks in unconventional low-permeability reservoirs, is the final goal of reservoir stimulation. In this work, a novel integrated methodology was proposed to correlate conventional post-stack seismic data to well production rate. It aims to pre-evaluate regional stimulation performance, facilitating investment decision-making in line with global oil prices and environmental consideration. Structural occurrence, seismic maximum curvature, and geomechanics parameters were combined in a physical model to evaluate underlying development and activation of natural fractures, result in the activation index F 1 . The potential of artificial induced fractures were quantified as normalized index F 2 by integrating mechanical item based on fracture mechanics and fluid flow. Accordingly, a fracability sweetness index ( F sweet ) model was built to correlate standardized well production rate ( Q eff ). A Case study of a naturally fractured igneous reservoir with 8 wells showed agreement between F sweet and Q eff . A considerable part of highly active fractures with F 1 of [0.9, 1] distributed over the area with lower curvature value. By contrast, the majority of fractures with lower F 1 of [0.8, 0.9] located in zone with higher curvature value. The weight ratio α = 0.06 indicated that in this case the overwhelming production contribution were from natural fractures, which were evidenced by well core picture. The field data demonstrates the prospect for predicting regional fracability variation, and suggests that it is possible to correlate fracability index with standardized well production rate. The insights contribute to well placement optimization and stimulation treatment design, breaking limitation of engineers' influence on individual wells, and hence reducing exploitation cost while enhancing ultimate recovery. [ABSTRACT FROM AUTHOR]

An important inspect that maximizes the stimulated reservoir volume during the hydraulic fracturing design is the multi-factor analysis and optimization. Characterizations of geological setting, geomechanical rock properties and operational factors can provide insight into the fracturing response of formations, which can, in turn be used to optimize the field fracturing treatment. In this work, the response surface methodology was employed to maximize the stimulated area in combination with numerically modeling based on a coupled flow-stress-damage approach, for the typical continental silty laminae shale in China. Seven uncertain parameters with a reasonable range based on silty Laminae Shale, Southeastern Ordos Basin, are used to fit a response of stimulated reservoir area (SRA) as the objective function, and finally identity the optimum design under the parameters base on SRA maximization The motivation of the study is to improve the artificial ability to control the fracturing network propagation by the multi-factor optimization. This work will guide the exploration and development of shale gas and is helpful in optimizing the fracturing design for continental shale, Southeastern Ordos Basin, China. [ABSTRACT FROM AUTHOR]

The characterization of 3D structures in porous media is crucial for predicting physical properties in many industries, such as CO2 capture and storage, hydrology, oil & gas. In contrast to the expensive and time-consuming acquisition of 3D images, 2D imaging can provide cheap and fast data. However, the reconstruction of a 3D image from a single 2D image is a complex non-deterministic inverse problem. Several statistical and deep learning-based algorithms have been introduced in the past, however, most of them fail to generalize structures and textures for different types of rocks, in addition to being time-consuming and only able to generate relatively small images (30 0 3 voxels cube). In this work, we propose a size-invariant multi-step 3D generation workflow from a single 2D image using a combination of Vector-Quantized Variational AutoEncoder(VQ-VAE), size-invariant Generative Adversarial Networks(GAN), and Image Transformer. The proposed workflow tackles several major challenges in the generation of 3D images since it is designed to not only satisfy the large size constraint (> 100 0 3 voxels cube) but also to generate statistically representative pore structures. The combination of these different generative techniques allows us to overcome the scalability, stability, and complexity associated with GAN approaches. We trained the proposed workflow using several types of rocks with different physical properties, sizes, and resolutions. To validate our methodology, we have generated several large-size 3D rock images and compare them to real 3D images in terms of physical properties (porosity, permeability, and Euler characteristic). • Single model for multiple types of rock using Transformer, VQ-VAE, and GAN. • Easy and stable to train, deploy, retrain and maintain. • Generate statistically representative 3D digital rock images from a single 2D image. • Generate images > 100 0 3 voxels of different rock types including carbonates. [ABSTRACT FROM AUTHOR]

In this day and age, the performance of oil and gas wells is severely affected by downhole and reservoir geomechanical problems. The key factor in predicting and solving these problems is a detailed study of the various aspects of the compressive and tensile behavior of the reservoir rock. In this study, the influence of mean sand grain size distribution as an important parameter influencing the petrophysical and geomechanical properties of the rock has been investigated using synthetic sandstone core samples. The results show that increasing the grain size range from 0.1 to 0.2 mm to 0.1–0.8 mm would result in a 23% and 64% decrease in rock porosity and permeability, respectively. However, such an unfavorable trend would be mitigated by the removal of fine particles from the rock composition. According to the results, there is a critical range of sand grains (i.e., 0.2–0.6 mm) above which rock permeability would be severely affected by a change in grain size. At the same compressive stress, the fine sandstones showed a more compressive deformation compared to the coarse specimens. In this regard, a direct relationship between rock compressive strength/Young's modulus and sand grain size was found. The results also indicate that fracture in the fine specimen initiates at lower stress conditions than in the coarse sample. This implies that the weakest grain to grain boundary (GGB) is weaker in the fine-grained samples than in the coarse-grained specimens. • Rock permeability is more sensitive to changes in mean grain size than rock porosity. • There is a critical range of sand diameter above which rock permeability decreases sharply as a function of grain size. • n interrelationship was observed between the physical and geomechanical properties of the rock and the mean particle size. • Fine-grained samples show more compressible behavior than coarse-grained specimens at the same compressive stress. • The relationship between the tensile/compressive strength of the rock and the mean grain size was investigated. [ABSTRACT FROM AUTHOR]

The volcanic rock with developed pores is important reservoir for oil and gas, but its complex pore-fracture structural characteristics lead to the hydration reaction when the volcanic strata is invaded by drilling fluid or fracturing fluid, which brings great challenges to the drilling operation and oil and gas production in volcanic rock reservoir. In order to understand the influence of clay hydration on the pore characteristics and permeability of different types of volcanic reservoirs. In this paper, we selected distilled water as the imbibition solution, and obtained the variation law of pore structure and physical properties of Permian tuff and basalt in Sichuan Basin during pressurized imbibition through a series of indoor test methods. The results show that the clay content of tuff is high, and the clay hydration produces new cracks during soaking, which leads to the increase of nuclear magnetic porosity of tuff after soaking. At the same time, it also makes some unconnected pores connected with each other, resulting in the increase of rock permeability in the later stage of soaking. During soaking, mineral particles peel off, and some clay minerals are transported to pores and fractures under hydrodynamic action, resulting in the reduction of effective porosity of tuff. The basalt is dense with poor physical properties. There are almost no cracks in the rock soaked for 0–24 h. After soaking for 48 h, new cracks are generated in the rock, which may be caused by the increase of pore pressure in the rock. The mineral particles around the crack obviously fall off and block the pore throat, resulting in the reduction of rock permeability after soaking. This study provides not only helps for avoiding the occurrence of lost circulation, well collapse and other accidents, efficient and safe drilling, but also a theoretical basis for the development of hydraulic fracturing in volcanic reservoirs. • The pore structure and physical properties of volcanic rocks with different soaking time were studied. • The influence of complex pore structure and rock type on the hydration of volcanic rocks is considered. • According to the experimental analysis, the hydration of volcanic rocks is divided into three stages. • The hydration of volcanic rock will produce cracks, accompanied by the spalling of minerals. [ABSTRACT FROM AUTHOR]

Determining the potential of reservoirs and production zones is very important to reach maximum product performance and decrease hydrocarbon recovery costs. The calculation of the Water Saturation (S W) significantly affects oil-in-place estimations. The Saturation-Height Function (SHF) is operated to predict the saturation in the reservoir for a given height above the free water level. Typical approaches for predicting water saturation as a function of rock properties and height above contact include two types, those based on capillary pressure curve averaging and log-based techniques. The goal of this study is to define an appropriate SHF and S W using the usual functions to delineate production zones using rock typing with an example from the Dorood oilfield in the Persian Gulf. In this study first, the reservoir has been divided into different rock types and water saturation is estimated by different methods in each rock type. The Reservoir Quality Index (RQI) along with Water Saturation profile for representative rock types were used for determining reservoir zones. Accordingly, a formulation was developed to model the behavior of Capillary Pressure (P C) as a characteristic of S W and to determine the Free Water Level (FWL) based on laboratory data. To achieve this goal, the appropriate saturation-height functions and their coefficients were chosen for representative reservoir rock types. The Pc curves are classified based on Discrete Rock Types (DRT) and a proper saturation-height function was assigned for individual rock types. Finally, some of the most common equations for calculating SHF were fitted to the representative Pc curve of each rock type and coefficients of the equation for any rock type were determined by using the MATLAB software in the studied carbonate reservoir. After investigating the results of fitting different SHF, water saturation was calculated using a modified lambda function and compared with the log-derived water saturation. The SHF applied, could be used to estimate saturations of unreachable zones of the field. • Classification of geological facies based on static characteristics and hydraulic flow units approach. • Including SMLP, DRT and K-means were implemented to categorize reservoir rocks based on FZI. • Results of the DRT method were used to determine saturation-height function for each individual rock type. • The generated SHF based on individual rock types generates S W in transition zone of uncored wells. • The SHF based calculated water saturation is comparable with well log-derived Sw. [ABSTRACT FROM AUTHOR]

There is a wealth of experimental evidence that fracture initiation and breakdown pressures differ depending on in-situ stress status, rock properties, and injection conditions. However, the mechanism is not fully understood from a theoretical modeling perspective. In this study, a fully coupled plain-strain fracture model is proposed to interpret the mechanism of fracture initiation and breakdown pressures. The fracture model consists of fracture initiation and propagation governed by linear elastic fracture mechanics. The effects of wellbore compliance (or compressibility), solid-fluid coupling, and fracture multiscale propagation behavior are fully considered. The solid-fluid coupling equations are solved using the Newton–Raphson iterative method. The explicit time marching method is used to capture the fracture initiation process. An implicit time-stepping with the fracture tip asymptotic solution is used to capture fracture propagation fronts. The model is validated against the analytical solutions of the plane-strain model. Sensitivity analysis demonstrates that the initiation pressure mainly depends on rock properties, especially the fracture toughness. The peak pressure (breakdown pressure) is related to rock properties and injection conditions and usually occurs before the peak of the pressurization rate is reached. It increases with the injection rate, fluid viscosity, Young's modulus, and fracture toughness. The dimensionless inlet flux into the fracture can be used to determine the fracture initiation pressure. The pressurization rate during the fracture initiation stage is constant and can be used to assess wellbore compliance. Using a low injection rate and a low-viscosity fluid is beneficial to capturing the fracture initiation pressure. This study can help understand fracture initiation and propagation and interpret hydraulic fracture initiation and breakdown pressures. • The wellbore compressibility, solid-fluid coupling, and multiscale propagation behavior are considered. • Breakdown pressure is dependent on injection conditions and rock properties. • Fracture initiation pressure and wellbore compliance can be determined by inlet flux and pressurization rate. • Low-viscosity fluid and low injection rate favor investigating fracture initiation process. [ABSTRACT FROM AUTHOR]

Bleaching of red beds, a type of hydrocarbon-induced alteration, is generally attributed to redox reactions between ferric iron minerals and hydrocarbon-bearing solutions. Herein, we report sandstone bleaching occurs interbedded with the coal- and dark mudstone-bearing strata at shallow depths below two unconformity surfaces separating sandstone formations of Triassic-Jurassic age in the Ordos Basin, China. Field observations, petrography, and geochemistry suggest that uplift events controlled the formation of red beds via supergene alteration and bleaching via hydrocarbon circulation. The color of sandstones below the unconformities grade from red, yellow, and white colors at shallow depths (few meters to tens of meters) to dark yellow, gray-green and gray colors at deeper depths. Organic matter (carbonaceous plant debris) and pyrite in the unaltered sandstone gave rise to the gray color. The red/yellow sandstones are characterized by the presence of extensive iron oxide/hydroxide grain coatings, exhibit intense dissolution and extensive kaolinization of detrital feldspar and biotite and lithics and are mainly composed of detrital quartz. The white, bleached sandstone presents similar petrographic characteristics as the unbleached sandstone except for a lack of iron oxide/hydroxide cements. δ18O VSMOW (9.8‰ to 15.8‰) and δD VSMOW (−103‰ to −119‰) values of kaolinite, and chemical indices of alteration of sandstones indicate a weathering origin for the kaolinite and the dissolution of labile minerals in the red and yellow sandstones. The original color of the bleached sandstone was gray during very early diagenesis and shifted to red/yellow due to the oxidation of pyrite and ferromagnesian silicate minerals (e.g., biotite) into hematite or goethite cements by the meteoric water circulation during regional uplift following the deposition of each formation. Supergene alteration associated with unconformities also created significant secondary porosity, and allowed later hydrocarbons to flow along the unconformities. The lithological properties of the weathered rocks below unconformities are highly heterogeneous both vertically and laterally and have a significant influence on fluid flow. This study provides direct evidence for hydrocarbon migration along unconformities and improves understanding of fluid-rock interaction in subsurface reservoirs. • Bleaching is restricted to shallow depths below two unconformities. • Uplift events controlled the formation of red beds via oxidation of iron-bearing minerals. • Secondary porosity generation allowed fluid flow along the unconformities. [ABSTRACT FROM AUTHOR]

Primary depositional and diagenetic processes exert very important influences on shale gas reservoirs. Rock electrical properties are an important basis for making reservoir prediction using the electromagnetic method (EM). However, there is still a lack of understanding about the impact of the sedimentary diagenesis process on shale electrical properties, this study focuses on the impact of diagenesis on rock properties. In this study, rock electrical properties are studied based on electromagnetic experiments. We systematically studied the lithofacies of different depositional paleoenvironments and diagenetic processes, and the influence of diagenetic evolution on the rock electrical properties was discussed, by means of X-ray diffraction (XRD) analysis, field-emission scanning electron microscopy (FE-SEM), low-temperature nitrogen adsorption (LTNA), and trace element (TE) geochemical analysis. Based on the study of mineral composition, grain assemblages and pore systems, we identified four lithofacies in the Longmaxi Formation: siliceous shale, siliceous-argillaceous mixed shale, silty shale and argillaceous shale. Redox proxies (U/Th, V/Cr, and Ni/Co) indicate that the siliceous shale was deposited in a relatively anoxic and reducing environment, indicating a deep-water shelf depositional paleoenvironment. The siliceous-argillaceous shale, silty shale and argillaceous shale were deposited under a relatively dysoxic-oxic environment, indicating a shallow-water shelf depositional paleoenvironment. The order of resistivity values of the lithofacies within the Longmaxi Formation is 36.78 Ω m (siliceous shale), 66.81 Ω m (siliceous-argillaceous mixed shale), 79.54 Ω m (silty shale), and 107.00 Ω m (argillaceous shale), and the resistivity decreases with an increase in porosity. The siliceous shale has the most abundant authigenic quartz, which filled the primary pores forming a rigid framework during the gas window, inhibited compaction, increased the distribution of organic matter (OM), and enhanced the development of OM pores. The high TOC content and high maturity of siliceous shale at the bottom of Longmaxi Formation make the OM pores more developed. Pyrite, conductive fluid and pore network under the main control of OM pores in shale form a conductive circuit when AC voltage is input, which increases the exchange capacity of cations and leads to the phenomenon of low resistivity. The interconnected OM pore network, both depositionally and diagenetically derived, affects the electrical properties of the Longmaxi shale. This study reveals that electrical properties of shale rocks and its variations can be impacted by the depositional environment and diagenetic processes. This work provides resistivity parameters for the electromagnetic exploration of shale gas under complex terrain conditions and provides a theoretical basis for later interpretation. • Shale lithfacies with different sedimentary environments and diagenetic processes have different electrical properties. • The shale of Longmaxi formation has the characteristics of high TOC content and low resistivity. • OM pores network is the fundamental factor affecting the electrical properties in Longmaxi shale. • It provides parameters of rock electricity for EM exploration of complex terrain and for inversion interpretation. [ABSTRACT FROM AUTHOR]

During drilling operations, the drill bit is worn out while breaking the rock. The roller bit is an important rock-breaking tool, but our research on its wear mechanism is still inadequate. Therefore, in response to this problem, this paper establishes a fractal characterization method for surface roughness based on the morphological features of the rock and bit surface. Combining the worn bit surface morphology and energy spectrum analysis results, it is determined that the wear mechanism of roller bit teeth is mainly abrasive wear, fatigue wear and adhesive wear, which are mainly squeezing and spalling. The rock is broken by roller bit under the action of drilling pressure and tangential force, so the contact force model of the single tooth pressed into the rock is established, and the reacting force of the rock on the bit tooth is deduced based on the rock crush conditions. According to the rolling friction characteristics of roller cone bits, the friction coefficient in rolling conditions is calculated. Then, according to the wear mechanism of the cone bit, the actual contact force and real contact area between the cone bit and rock at the bottom of the hole, a roller bit teeth wear equation is established, consisting of rock properties, bit properties and working condition parameters. The bit parameters and drilling parameters are regarded as controllable parameters, and the rock properties are regarded as uncontrollable parameters. In order to highlight the basic parameters of rock, the controllable parameters in the equation are standardized. The calculated wear degree can better reflect the wear ability of rock to drill bit. This result is of great significance for the factor prediction of formation abrasiveness and bit selection. • The wear mechanism of roller cone bits is revealed through the surface roughness of the rock. • The force and friction coefficient equations of the roller cone bit in the process of rock crushing are derived. • A standardized wear equation of roller cone bit teeth is proposed, which reflects the wear ability of rock on the bit. [ABSTRACT FROM AUTHOR]

Production decline from wells producing from shale rocks is typically quite rapid. One possible factor responsible for such decline is loss in fracture conductivity. This is true in the case of the Tuscaloosa Marine shale reservoir. In this work, the stress-dependent fracture conductivity of TMS core samples is investigated using five propped cores under varying stress conditions. In addition, the effects of static rock mechanical properties and rock mineralogy on conductivity decline are investigated. The mineralogy of each core sample was determined by X-ray Diffraction analysis. Fracture conductivity was measured using a Hassler-type pressure core holder with a pressure rating of 15,000 psi (103.42 MPa). Estimated rock mechanical properties showed that shale anisotropy could affect fracture conductivity. The time decline in conductivity revealed two possible decline trends, a) decline from the reduction in induced fracture width, and b) decline from the healing of developed micro-cracks. An exponential decline in fracture conductivity with increasing confinement pressure was observed with an average decline rate constant of 3.15 × 10 − 10 mPa−1. While rock mineralogy did not have any clear relationship with conductivity decline, the effects of rock mechanical properties were only important at 10.34 MPa confinement pressure and above. The observation showed that a high Young's modulus correlate to high conductivity, whereas a high Poisson's ratio correlate to low conductivity. This study provides useful observations for optimizing fracture design to enhance well productivity in the TMS. • Fracture conductivity decline followed an exponential trend. • Micro-cracks formed in the rock samples which later contributed to fluid flow. • Reduction in fracture width is controlled by proppant embedment for the TMS. • Fracture width reduction and healing of micro-cracks causes conductivity decline. [ABSTRACT FROM AUTHOR]

The developments of helium-3 nuclear magnetic resonance (NMR) technique to assess porous media properties such as porosity and pore size distribution (PSD) are reported. The method is suitable for use to characterize unconventional extra-heavy oil reservoirs, has a potential in application to tight shales and other unconventional formations, and has several advantages over conventional water NMR. It is based on 3He nuclear magnetic relaxation measurements for different pore loadings and inverse Laplace transform of the data. The relation between different pore types as well as their mean radii are found within the models of spherical, cylindrical and planar pores. The method was applied to study porosity and PSD of rock samples acquired at the North belt of crude oil, Republic of Cuba, the unconventional formation known for its complexity. The obtained pore sizes and porosities are in a good agreement with conventional methods which validates the proposed 3He NMR approach for porous media studies. Advantages of the 3He liquid and gas as probes are discussed. • Characterization of pore structure with the smallest probing atoms — helium-3. • Advantages over conventional water nuclear magnetic resonance technique. • No need to separate the signal from sample and probe molecules. • Access to hidden pores and pores with weak connectivity. • Porosity and pore size distributions of unconventional and clay-rich oil formations. [ABSTRACT FROM AUTHOR]

Rebound hardness (RHN) has become a widely applied rock mechanical parameter in the petroleum industry due to economic and convenient testing procedures. However, the RHN data can be under-utilized when lacking detailed integration with other rock properties. Targeting the unconventional "Mississippian Limestone"/STACK play in north-central Oklahoma, USA, and outcrops of the Vaca Muerta Formation in Argentina, this study aims to test the value of RHN in predicting rock properties. RHN data from the "Mississippian Limestone"/STACK cores show correlative trends with mineralogy and porosity. All the correlations show clusters by facies groups with overlaps being present among different clusters. Within these correlations, mineralogy and porosity show variable significance levels in affecting RHN among different facies groups. Leverage analysis suggests that bulk clay content and porosity exhibits the most significant control on RHN for the MISS/STACK data, with variabilities being present in different facies groups. These partitioning patterns of data by facies groups imply that facies variability affects the statistical pattern and that RHN can assist in rock typing, and hence, sample selection for detailed laboratory analyses. Forward regression analysis reveals that the confidence level of predicting porosity and sonic velocity can be enhanced using RHN. In addition to the correlative trends between RHN and rock properties, results from forward regression analysis indicate that RHN can help estimate these properties in a faster, cheaper, and non-destructive way relative to conventional laboratory analyses. Correlative trends are also observed in Vaca Muerta data, suggesting the value of RHN in characterizing similar types of mixed carbonate-siliciclastic reservoirs. • Rebound hardness (RHN) can help estimate bulk clay content, porosity, sonic velocity, and dynamic elastic parameters. • RHN may help estimate static rock mechanical properties, but more data are needed for further investigation. • RHN cluster by facies and thus can help design an integrated rock typing and sample selection scheme. • Multivariate methods indicate RHN is affected by multiple factors and can help apply RHN to predict rock properties. • A facies-based, integrated approach with a well-designed testing protocol is critical for using RHN in reservoir analysis. [ABSTRACT FROM AUTHOR]

Hydraulic fracturing has been widely used to stimulate oil and gas production from low permeability reservoirs. However, the geologic discontinuities, such as natural fractures, joints, and bedding planes, can significantly affect the propagation direction of the hydraulic fracture. Considering the effect of the non-singular stress term of Williams' series expression for stress field near the fracture tip (i.e., T-stress), an analytical criterion for a hydraulic fracture crossing a frictional interface (such as the natural fracture and bedding plane under compression-shearing) was proposed. The present criterion was validated by comparing it to the published experiments, and the effect of T-stress on the propagation of the hydraulic fracture crossing a frictional interface was analyzed by comparing the present criterion to the published criteria. The results show that the accuracy of the present criterion depends on the difference in geomechanical properties of the rock on either side of the interface. The effect of T-stress on the hydraulic fracture propagation can be divided into the facilitation and the inhibition, which depend on the intersection angle between the hydraulic fracture and the frictional interface. No matter what the intersection angle between the hydraulic fracture and the frictional interface is, the effect of T-stress can inhibit the change of propagation direction when the hydraulic fracture crosses the interface. • A criterion for a hydraulic fracture crossing a frictional interface was proposed. • The criterion accuracy depends on the property contrast of the materials. • Effect of T-stress on the crossing behavior depends on the intersection angle. • T-stress can decrease the crossing angle of the hydraulic fracture. [ABSTRACT FROM AUTHOR]

This paper describes a comprehensive approach to improved lithofacies characterization using the simultaneous pre-stack inversion, Bayesian classification, and multiple-point geostatistics. This integrated workflow provides an enhanced lithofacies characterization by reproducing the continuity of geological facies in the meandering-fluvial sandstone reservoir from Upper Assam, India. The simultaneous pre-stack inversion provides the rock elastic properties of the reservoir, such as P- impedance, s-impedance, density, and V P /V S ratio. Next, the probabilistic modeling approach of Baye's theorem is used to integrates seismic elastic properties with well log lithofacies identified from the cross-plot analysis for probability volumes of lithofacies. Finally, the multiple-point geostatistics based on the Single Normal equation Simulation algorithm is used to generate the improved lithofacies model by constraining of the lithofacies probability volumes (soft data) and well logging data (hard data). These results were compared with the Bayesian lithofacies classification and proved that the adopted method had successfully improved the continuation of the reservoir lithofacies by reproducing the lithofacies, hence an improvement in the reservoir characterization. • An integrated workflow is used that provides better lithofacies characterization. • Estimation of seismic elastic properties using simultaneous prestack inversion. • Prediction probability volumes of lithofacies by Bayesian classification. • The SNESIM algorithm applied with constrained by probability volumes and well data. • Improved lithofacies volume generated by the multiple-point geostatistics. [ABSTRACT FROM AUTHOR]

The fractured rock mass is a discontinuous, heterogeneous, anisotropic medium in nature, including single, multiple or a network of joints with regular or irregular patterns located between the intact rocks. Anisotropy, as an inherent feature of rock mass, is a factor that causes the mechanical properties of rock to be various in different directions, so it is very important and necessary to be considered in the design of rock engineering structures. This study aims to investigate the effect of rock anisotropy on induced stresses around an opening like a borehole located in the fractured rock mass. For this purpose, the combination of discrete fracture network (DFN) method to construct a geometric model of rock mass, with distinct element method (DEM) to the numerical analysis of stress, was used. All coupled DEM-DFN models were developed based on the field data of the rock and joint system of the Sellafield site in the UK. The discrete fracture network models with different degrees of anisotropy, including a circular opening with two different cross-section areas placed at the center of model, were used for stress analysis. In each type of model, by applying different boundary conditions, the magnitude of induced stresses at selected points around opening is calculated, and then the obtained results are compared with the Kirsch method as a popular closed-form solution. The numerical results of this study showed that the presence of irregular joints with different orientations in the model caused anisotropy in the magnitude of induced stresses obtained around the opening. This is an important issue that the Kirsch method is not able to consider in the calculations. • Fractured rock mass is a discontinuous, heterogeneous and anisotropic medium including network of joints with the stochastic pattern located between intact rocks. • Anisotropy is a factor that causes the mechanical properties of rock to be various in different directions. • Coupled DEM-DFN models are developed to numerical analysis of stress around a borehole. • Presence of irregular joints with different orientations caused anisotropy in the amount of induced stresses around the borehole. [ABSTRACT FROM AUTHOR]

In history matching, the calibration of a prior reservoir model is computationally expensive because many forward reservoir simulation runs are required. Multiple posterior (or calibrated) reservoir models need to be sampled to consider high reservoir uncertainty, which increases the computational cost significantly. In this study, we propose a novel deep-learning-based history matching method that efficiently samples posterior reservoir models for fluvial channel reservoirs. Three convolution-based neural networks (NNs) are used in the proposed method to sample posterior models quickly without conventional calibration processes: convolutional autoencoder (CAE), convolutional neural network (CNN), and convolutional denoising autoencoder (CDAE). First, low-dimensional latent features are extracted from prior models using CAE because the dimensionality of static data is too high to find the relation between the prior models and corresponding simulated dynamic (production) data. Next, CNN is used to find the relation between the latent features of the prior models and the corresponding production data, which are the output and input data of CNN, respectively. The CNN output is refined using CDAE to improve the geological connectivity of the posterior models. The performance of the proposed method is compared with non-convolution-based methods that combine fully-connected NN structures (multi-layer perceptron (MLP)) and dimension-reduction techniques (principal component analysis (PCA) and stacked autoencoder (SAE)) in the benchmark egg model. The proposed method outperforms the other methods (MLP-PCA and MLP-SAE) in terms of geological constraints for fluvial channels and the computational cost of sampling posterior models. • CAE compresses heterogeneous rock properties efficiently. • Posterior models can be sampled quickly using CAE and CNN. • The geological connectivity of posterior models can be improved using CDAE. [ABSTRACT FROM AUTHOR]

Digital rock physics (DRP) has shown promising performance and more realistic results in predicting rock properties and investigating flow mechanisms in geomaterials. However, the application of DRP for studying the effects of diagenesis on rock properties using a systematic and accurate model has not been reported. During the formation of the sedimentary rocks, they may undergo various diagenesis events (e.g., cementation and dissolution), and such events may occur along different pathways, which both make a significant effect on rock properties. With the aid of the DRP techniques, we present a comprehensive investigation of the effects of diagenesis events and diagenesis pathways on rock properties. In this paper, the original digital rock with multicomponent and irregular particles is constructed using the discrete element method (DEM). Then, the original model similarly undergoes four diagenesis events (two cementations and two dissolutions) along with two different diagenesis pathways for generating new models. The cementation and dissolution are simulated using a dilation operation and quartet structure generate set algorithm (QSGSA), respectively. Finally, some properties of pore space, transport, and elastic of all the models are analyzed and compared to investigate the effects of diagenesis events and pathways. The comparisons indicate that the final rock which experiences the cementation and then dissolution exhibits larger porosity, fractal dimension, aperture, coordination number, and permeability, and smaller tortuosity, formation factor, and elastic moduli than the one that undergoes the dissolution and then cementation. Thus, the study will help us to better understand the variations of the flow and mechanical properties of rocks without conducting extensive experiments if rocks experience different diagenesis processes along different pathways. • The technique of digital rock physics is used to simulate different diagenesis events along with different pathways. • The effects of diagenesis events and pathways on the rock properties are comprehensively investigated. • The final rocks which experienced different diagenesis pathways have different petrophysical properties. [ABSTRACT FROM AUTHOR]

Maintaining the accuracy of well-logging interpretations in igneous reservoirs has long been a difficult problem. The igneous gas reservoirs in eastern China are important exploration targets at the present time. It has been found that, when compared with sedimentary rock reservoirs, the properties of igneous rock change faster with depth, and the reservoir spaces tend to be more complex. In addition, the porosity and permeability are lower, making the evaluations of water saturation more challenging. Generally speaking, the Archie Equation parameters can be obtained through a large number of laboratory core measurements, and then applied to the logging interpretations of water saturation. However, the longitudinal heterogeneity of reservoirs is neglected by fixed parameters which are referred to as "static parameters". In the current research investigation, in order to improve the accuracy of the logging interpretations, a method of segmentation characterization was used to invert the Archie's Equation parameters from NMR logging data, based on the relationships between the transverse relaxation times (T 2) and the resistivity indexes (I). Subsequently, the dynamic Archie parameters which changed with depth were obtained using the aforementioned method, which had not only considered the longitudinal heterogeneity of the reservoirs, but also provided a new interpretation method for the water saturation of igneous reservoirs. In addition, this study also analyzed the relationships between the key parameters and pore structure parameters in the designed model. It was found that the data distributions of igneous rock and sedimentary rock had displayed opposite trends. Therefore, the results of this study confirmed that the conductivity of igneous rock is affected by the proportion of macropores. • We have verified the applicability of T 2 -I model (which we have validated in tight sandstone and shale) on igneous rocks. • According to the pore structure, the relationship between transverse relaxation time and resistivity index is established. • We provide a workflow for researchers to use our model to obtain dynamic Archie formula parameters for joint inversion of water saturation using resistivity and NMR logging data. • Finally, we found a very interesting phenomenon. The key parameters in the model are sensitive to diagenesis, and the data show a clear difference between sedimentary rocks and igneous rocks. [ABSTRACT FROM AUTHOR]

Electrical resistivity measurements of reservoir rocks are usually applied to identify fluid type and saturation. Although it has been widely studied, the effect of fluid saturation on electrical resistivity is not yet fully understood, especially when considering the spatial distribution of fluids. Hysteresis and electrical resistivity jump in the imbibition process are two of the phenomena that remain unclear. Microscopical evaluation would be useful in understanding these phenomena. In this paper, we analyzed the influence of the micro-spatial distribution of fluids on electrical resistivity. In order to achieve the objective, laboratory measurements and computer modeling of electrical resistivity were carried out. Measurements were made on unconsolidated sand samples that were saturated with brine. Two categories of samples were prepared based on the position of the brine injection to obtain fluid spatial distribution variations in rock pores. Measurement results showed that the electrical resistivity varies depending on the brine injection position. Subsequently, 3-D microcomputed tomography images were acquired to analyze sample microstructure and model fluid spatial distribution. We implemented three different saturation models made up of varying fluid filling mechanisms onto digital images of samples, then used them to compute the electrical resistivity of the sub-sample using the finite element method. The measurement and calculation of electrical resistivity showed good agreement. These results indicate that the proposed model is capable of representing spatial fluid distribution in pore spaces of measured samples. This fluid distribution is most responsible for the variation of the electrical resistivity in the samples. Furthermore, the electrical resistivity jump phenomenon in the imbibition process was successfully explained through the proposed model. Based on this study's results, it can be concluded that the spatial distribution of fluids needs to be considered in the estimation of electrical resistivity. The research findings provide insight into how micro-spatial distribution affects electrical properties of rocks of importance to the interpretation of electrical resistivity data. • The fluid spatial distribution is crucial in estimation of electrical resistivity. • A new saturation model can explain the imbibition data. • The electrical resistivity jump can be clarified by our proposed model. • The Digital Rock Physics method is effective for analyzing porous medium. [ABSTRACT FROM AUTHOR]

In recent years, the increasing energy demand has led the oil and gas industry to explore unconventional reservoirs. The hydraulic fracturing technique (fracking) has been adopted in order to increase the reservoir drainage area. Nevertheless, there is an environmental concern about the contamination of aquifers due to this technique. The operation design requires predicting the induced fracture geometry to avoid hazards related to fracking. Hydraulic fracturing changes the state of stress at crack tip leading to more uncertainties in the definition of crack geometry, especially in naturally fractured formations. For such, analytical solutions and numerical simulations have been employed in recent decades. Nevertheless, the numerical models require high computational effort. This paper proposes an artificial neural network (ANN) to predict the interaction between hydraulic fracture and natural fractures. We performed over 800 simulations to build the training database varying the rock mechanical properties and model parameters, such as the approach angle between hydraulic fracture and natural fracture, in-situ stress magnitudes, friction angle, and fracture energy. The ANN results are compared against analytical solutions and numerical models, showing excellent agreement. These results show that the trained neural network can predict fracture interaction accurately. They also suggest that the most sensible parameters were taken into account in the proposed ANN. • Considerable number of fracture interaction simulations to database. • Application of Artificial Intelligence Technique. • Verification of the results with analytical solutions and simulations using other meshes. • Applied case study. [ABSTRACT FROM AUTHOR]

Using different phaseCO 2 -brine, the effect of stress corrosion on the micro-fabric, topology of the minerals and the elemental composition of saline rock was evaluated, to understand how this affect transport properties of rocks. Image analysis was used to evaluate changes in micro-fabric, topology of mineral and elemental composition from SEM images. The micro-fabric of all the CO 2 bearing samples changed significantly according to the different phaseCO 2 -brine. Grain roundness, grain smoothness, and pore smoothness increased after compression while the roundness of pores reduced. There was a significant change in the weight percentage of silicon, carbon and oxygen in the CO 2 -bearing samples compared to the brine sample. Change in the shape, solidity and roundness of the pores led to a change in permeability of rocks by altering the tortuosity of the pores. This study provides an understanding of changes in micro-fabric and elemental changes occurring in saline CO 2 storage sites under different possible phaseCO 2 -brine and highlights their implication for storage and properties of the rock. • Change in the composition of the rock is linked to change in micro-fabric and strength of the rocks. • The micro-fabric of CO 2 bearing samples changed according to the different phaseCO 2 -brine. • Tortuosity of pores had a greater effect on the permeability than the porosity. • Stress accelerates the change in micro-fabric especially for gCO 2 -br reservoir. [ABSTRACT FROM AUTHOR]

In this investigation, a framework is proposed to find the equations to describe the fracture conductivity and fracture aperture as the functions of effective stress (the difference between geo-stress and fluid pressure), temperature difference (the difference between rock temperature and fluid temperature), and the rock mechanical properties. The framework consists of several lab experiments and a numerical model, which is time-saving to study the influences of the aforementioned influential factors on the fracture conductivity and aperture. After analyzing the lab experimental data, we find that it's almost impossible to accurately measure the fracture aperture even with high-precision displacement sensors. Therefore, the numerical model coupling the fluid flow in the rough fracture, the solid deformation, and the heat transfer between the hot rock and the injected fluid is built. Three different distributions of the fracture surfaces are analyzed, and we find that the fracture surface roughness fits the normal distribution. After the data matching between the lab experimental data and the numerical results, a large number of numerical experiments using the numerical model are carried out to study the influences of the effective stress, temperature difference and the rock properties, including the elasticity and Poisson's ratio. When fitting the single variable analysis results, we find that the fracture conductivity and aperture are in different function forms of the aforementioned factors. But the reduction of fracture aperture and the natural logarithm of the normalized fracture conductivity can be described using the binary linear function of the effective stress and the temperature difference. Two key strengths of the research lie with the fact that it is time-saving to obtain the exact formulas of fracture conductivity and fracture aperture, and it can measure the dynamic fracture aperture accurately. • It is time-saving to obtain the functions of the fracture conductivity and aperture with the frame work. • Both the fracture conductivity and aperture can be accurately described under high confining stress. • The fracture conductivity and aperture of the rough fracture do not meet the cubic law. • The influences of different factors on the fracture conductivity and aperture are investigated comprehensively. [ABSTRACT FROM AUTHOR]

For addressing the behavior of a reservoir with different fluid types, the Biot-Gassmann equation often is the base of the practical simulation. Despite the prevalence application of this equation with the isotropy conditions, the unforeseen errors always expose in simulation results because of the anisotropy state in reality. We investigated the anisotropy model with the integration of two analytical strategies using a three-component VSP data set. We obtained an initial anisotropy model in the region of acquired walkaway VSP using slowness polarization inversion, and updated the anisotropy model with the application of anisotropy ray-tracing and tomography. We applied a layer-stripping approach to the anisotropy model during raytracing to optimize the inversion. Given a computed geomechanical model and extracted rock properties of a carbonate reservoir, we developed the anisotropy Biot-Gassmann model, for finding the elastic moduli. We used the substitution strategy to generate the dynamic model of elastic moduli. We showed how the compressional modulus and rigidity change with the anisotropy model in different fluid content. We found that integration of slowness polarization and raytracing tomography increases the maneuverability to control the predicted anisotropy model and intensifies the convergence rate of the inverse problem. We observed that the isotropy assumption in modeling the elastic parameters makes around 8–10 % drift value in compressional modulus relevant to the reality, whereas rigidity showed reluctant behavior to fluid. • We updated the anisotropy geomechanical model using walkaway 3C-VSP data. • A combination of slowness polarization and raytracing used to model anisotropy. • The anisotropy Biot-Gassmann model was solved using the rock physics model. • Elastic moduli were moded for different fluid types. • Compressional modulus has 8–10 % difference with reality if supposing the isotropy. [ABSTRACT FROM AUTHOR]

Abstract: Equivalent pore radius links permeability and porosity of a porous medium. This property can be calculated from specific surface and porosity data measured in the laboratory. We can obtain porosity information from logging data but specific surface information can only be obtained from laboratory experiments on cuttings or core samples. In this study we demonstrate that elastic moduli as calculated from bulk density and velocity of elastic waves relate to equivalent pore radius of the studied shale intervals. This relationship establishes the possibility of calculating equivalent pore radius from logging data. We used cuttings samples and available well logs to characterize Cenozoic, Cretaceous and Jurassic shale sections in the Skjold Flank-1 well of Danish North Sea. Logging data and well reports were used to select 31 shale cuttings samples and experimental data for porosity, grain density and BET specific surface were obtained from these samples using kaolinite and smectite as reference. The cuttings samples were also characterized with respect to mineralogical composition, content of organic carbon and cation exchange capacity. Equivalent pore radius was calculated from porosity and BET data. It varies from 5nm for some Cretacous and Jurassic shale samples to about 25nm in some Cenozoic samples. Pore radius is controlled by shale mineralogy and the degree of compaction. We found exponential relationships between equivalent pore radius and elastic moduli, and these empirical relationships were used to calculate equivalent pore radius for the Cenozoic, Cretaceous and Jurassic shale sections in Skjold Flank-1 well from elastic moduli. Elastic moduli were calculated from sonic velocity and density logs. The calculated equivalent pore radius logs vary from 27nm at 500m to 13nm at 2000m within Cenozoic shale and from 12nm to about 6nm in the deeper Cretaceous and Jurassic shale intervals. Cross plots of the equivalent pore radius with neutron porosity and gamma ray data separate the Cenozoic shale section with high equivalent pore radius from Cretaceous and Jurassic sections. [Copyright &y& Elsevier]

Abstract: Numerous studies have focused on the problem of wellbore instability or enlargement; however, most have focused on the physical–chemical interactions between the rock (especially shales) and the drilling fluid and have ignored the effects of drill string impacts. Drill string impacts on the wellbore wall often have important effects on wellbore instability. This paper presents a model for calculating drill string impacts on a wellbore wall based on an experimental study, principles of rock mechanics and rock damage mechanics and the Drucker–Prager yield criterion. The law of rock fragmentation during drill string impacts is investigated using simulations; later, relationships between the rock fragmentation volume and the drill string impact are developed under different conditions (contact lengths of the drill string, impact speeds, rotation speeds, well depths and rock softening). Moreover, formulae describing the drill string′s critical speed and the rock fragmentation volume when the wellbore rock fails are developed based on laboratory experiments and simulations. The results show that drill string impacts greatly influence wellbore instability or enlargement. In particular, shallower formations are affected more by drill string impacts than deeper ones. After rock softening, the drill string′s critical speed decreases, whereas the wellbore rock fragmentation volume increases; compared to a radial impact by the drill string, the drill string′s rotation speed plays only a secondary role in rock failure. The two formulae can be used directly in engineering problems because they provide relevant preventive measures during drilling. The conclusions of this paper will help drilling engineers understand the relationship between drill string vibrations and wellbore instability. [Copyright &y& Elsevier]