Saturated Shale Research Articles

Calculation model of shale fracture compressibility and evolution of permeability under water-bearing conditions

Water saturation of shale reservoirs significantly influences the permeability and compressibility of propped fractures. This study focused on the Longmaxi Formation shale reservoir in northern Guizhou, China, where the permeability of water–saturated shale under varying gas and confining pressures was measured. A compressibility model for proppant embedment and compaction deformation was developed and validated against the experimental results. This study examined the compressibility of supported fractures considering water–rock interactions and elucidated the intrinsic relationship between compressibility and water saturation. The findings demonstrated a decreased trend in shale fracture permeability with increasing water saturation under identical conditions. Compared to dry shale, the permeability decreased by 1.2%–16.4% and 2.0%–17.8% at water saturation of 15% and 50%, respectively. The results of the model calculations demonstrate that fracture compressibility is contingent on the degree of variation of the fracture width. Prolonged water–rock interactions intensified the variation in the fracture width increasing the compressibility under the same stress conditions. As the water saturation increased from 0% to 50%, the fracture closure rate increased from 0.034 to 0.179 with the increase in effective stress. Increased water saturation also increases the sensitivity of the fracture compressibility to effective stress while decreasing the elastic modulus of the rock, thereby enhancing the proppant embedment depth and significantly increasing the fracture compressibility. This study provides critical insights into the dynamic evolution of fracture permeability during hydraulic fracturing and offers valuable implications for gas production forecasting.

Experimental investigation on the influence of NaCl concentration on triaxial mechanical behaviors of a low-clay shale

During a hydraulic fracturing operation, a large quantity of salinity fracturing fluids will be retained in the shale reservoir, which may cause the problem of wellbore instability. Previous studies mainly focused on the change mechanism of clay-rich shale after brine immersion. However, the influence of NaCl concentration on mechanical behaviors of a low-clay shale is still unclear. Therefore, in this investigation, conventional triaxial compression tests were carried out on low-clay shale specimens saturated with NaCl solutions at different concentrations (0%, 5%, 15%, 25%) under different confining pressures (0 MPa, 15 MPa, 30 MPa, 45 MPa), and their mechanical properties were analyzed systematically. Optical microscopy, polarized light microscopy and scanning electron microscopy were used to understand the microscopic changes in shale samples after saturation in NaCl solutions. The brittleness indices of saturated shale specimens were evaluated based on rock strength properties and the energy evolution law. According to the experimental results, compared with the water-saturated specimens, the peak strength, elastic modulus, cohesion and internal friction angle of specimens saturated with 5%NaCl solution all showed a downward trend. However, for the specimens saturated with the NaCl solution at concentrations of 15% and 25%, higher NaCl concentration showed a greater rebound effect on the mechanical parameters compared with the 5%NaCl saturation. The microscopic observation showed that the brine could invade the interior of shale specimens from micropores, microcracks and bedding fractures, which were mainly parallel to the bedding direction. And the bedding fractures and some of micropores seemed to be filled by deposited NaCl crystals and mineral particles. The brittleness index of the brine-saturated shale specimen decreased at the low-concentration (5%) and increased at the high-concentration (15% and 25%). This investigation could provide a theoretical basis and mechanical parameters for analyzing the stability of shale wellbore affected by the salinity fracturing fluids.

Evaluating the impact of artificial maturation on the petrophysical and geochemical properties of unconventional shale formations by integrating dielectric and NMR measurements

This paper addresses challenges in characterizing unconventional shale reservoirs. For the first time, the nuclear magnetic resonance (NMR) and dielectric responses are integrated to characterize intact, saturated, and kerogen-rich subsurface shale samples at various maturation stages. The NMR and dielectric were measured separately using independent pieces of equipment, and all NMR and dielectric measurements were carried out at surface conditions. A comprehensive assessment is provided to address the changes induced by maturation through combined geochemical and petrophysical analyses. Shale samples from the Upper Cretaceous sequence of Jordan were characterized using Rock-Eval analysis, before and after maturation treatments. The total organic carbon (TOC) was decreased from 17.4 to 13.8 and 11.3 wt% and the pyrolyzed sulfur content was decreased from 3.32 to 0.25 and 0.15 3.18%, after maturing the samples at 250 °C for 1 and 5 days, respectively. The study employed NMR to track changes in pore structure via T2 relaxation time and measured dielectric properties and conductivity dispersion across frequencies from 10 MHz to 1 GHz using a wideband open-ended coaxial probe. After the maturation treatments, the dielectric constant of saturated shale samples doubled, and the conductivity increased by over three times. These changes in dielectric properties can be attributed to increased fluid-rock interfacial polarization and the formation of new pore spaces during maturation. NMR findings also indicated the emergence of a new pore system within the organic matter and the development of new fractures, resulting in a 6 to 12% increase in total porosity. The results obtained indicate that maturation-induced microstructural changes have a more significant influence on the dielectric responses than alterations on total organic carbon.

Weakening Effect of Water on Mechanical Properties of Brittle Shale under Triaxial Compression

Abstract The mechanical properties of rock materials are remarkably affected by water. To reveal the effect of water on the mechanical properties of shale, the conventional triaxial compression tests were implemented for shale with the five kinds of water saturation coefficient. According to the test results, the influence of the saturation coefficient on strength and deformation parameters was analyzed. Based on the fitting result of the Mohr-Coulomb criterion, the relationship between the strength parameters and the water saturation coefficient was analyzed. The softening effect of water on shale is mainly due to the decrease of cohesion and internal friction coefficient with increasing of water saturation coefficient. The strength criterion considering the influence of water weakening was established according to the function relationship between the fitting parameters and the water saturation coefficient. In addition, three kinds of brittleness indexes were selected to quantitatively analyze the influence of the saturation coefficient on shale brittleness. The results indicated that the brittleness indexes all decreased with the increase of the saturation coefficient, and the brittleness of shale is weakened after water absorption. The research results can provide a reference for the evaluation of saturated shale brittleness.

Experimental Investigation on Cracking Characteristics of Dry and Saturated Shales in Nitrogen Fracturing after Liquid Nitrogen (LN2) Injection

Cryogenic LN2 fracturing is one of the environmentally friendly waterless fracturing technologies that promote the fracture complexity of shale gas reservoir. The water-ice phase transition under freezing condition causes frost heave in saturated shale. The effect of moisture in shale should be taken into account during cryogenic damage process. Therefore, the differences of cracking characteristics between dry and saturated shales were studied in this paper. A laboratory triaxial and high temperature fracturing system was developed for nitrogen fracturing dry and saturated shale after LN2 injection. The influence of moisture on breakdown pressure was studied under different confining pressures (3 MPa, 6 MPa, 9 MPa, and 12 MPa) and bedding directions (parallel bedding and vertical bedding). The experimental results demonstrated that when the confining pressure increased from 3 MPa to 12 MPa, the breakdown pressure of dry parallel bedding after LN2 preconditioning decreased 7.12 MPa, 6.06 MPa, 4.58 MPa, and 3.11 MPa, respectively. Therefore, LN2 preconditioning could damage shale resulting in a lower breakdown pressure, but the effect of cryogenic damage decreased with the confining pressure increasing. The moisture in shale had little impact on nitrogen fracturing without LN2 injection because the breakdown pressure difference between dry and saturated shales was small. However, the breakdown pressure of saturated shale after LN2 preconditioning was always lower than that of dry shale. The breakdown pressure of saturated parallel bedding shale after LN2 injection decreased 8.62 MPa, 7.67 MPa, 6.08 MPa, and 4.63 MPa, respectively, with the confining pressure increasing from 3 MPa to 12 MPa. The breakdown pressure difference between dry and saturated shales was impacted by the migration of unfrozen water and frost heave. In addition, the extent of cryogenic damage varied substantially between different bedding directions. When the confining pressure was 3 MPa, the breakdown pressure of saturated parallel bedding shale reduced by 69.18% after LN2 preconditioning, but that of saturated vertical bedding shale only decreased by 22.49%. The tensile strength of shale had a greater influence on the breakdown pressure. According to the Brazilian disc test results, the tensile strength of matrix was much higher than that of bedding planes. As a result, it is useful to wet the shale in order to reduce the breakdown pressure. The fracturing direction of horizontal drilling should be consistent with the bedding direction for better cryogenic fracturing effect.

Comprehensive Experimental Study on the Gas Breakthrough Pressure and Its Implication for the Reservoir Performance

Abstract It is challenging to interpret the gas breakthrough mechanisms, controlling factors, and its relationships with the reservoir parameters for unconventional reservoirs such as the gas shale, due to the accumulation characteristics of source-reservoir integration. Take the typical marine shale gas of the B field for example, we use the step-by-step (SBS) test to measure the gas breakthrough pressure of the water saturated shales, and investigate the influential factors such as the pore size distribution, mineral composition, and organic geochemical properties. Moreover, the implication of the gas breakthrough capability for the reservoir quality such as the porosity, permeability, the gas content, and the gas occurrence state are addressed. Based on our work, it is observed that the gas breakthrough capability in shale is influenced by many factors. Generally, the gas breakthrough pressure is positively with the amount of ductile minerals such as the clay and the plagioclase, but negatively with the amount of brittle minerals such as the quartz. In addition, the gas breakthrough pressure is decreased with the increase of the pore radius and the specific surface areas. What is more, the influences of geochemical properties on the gas breakthrough capability should not be neglected. Due to the development of organic pores in the kerogen, the gas breakthrough pressure is found to decrease with the increase of the total organic carbon content (TOC) and the residual carbon content (RC). The breakthrough pressure can be used as the significant parameter to indicate the reservoir quality of the shale gas. It is shown that the breakthrough pressure is inversely with the porosity, permeability, the total gas content, and the adsorbed gas content. It is practical and meaningful to measure and estimate the breakthrough pressure for the formation evaluation in shale gas reservoirs.

The mode I fracture toughness alternation and crack propagation behavior evolution due to long-term Sc-CO2 saturation

The mode I fracture toughness is a critical parameter which defines the rock’s resistance to crack propagation, especially in hydraulic fracturing. Recently, Supercritical carbon dioxide (Sc-CO2) has been proposed as a fracturing fluid candidate in hydraulic fracturing stimulations of shale reservoirs. However, its effects on fracture toughness transition and crack propagation behaviors have not been understood well. In this study, we performed a series of semicircular bend specimens (SCB) before the Longmaxi shale specimens’ saturation. Three-point bending tests along divider orientation showed that after Sc-CO2 saturation, mode I fracture toughness (KIC), elastic modulus (E) and absorbed energy (Ue) of shale were decreased by 22.1%, 24.5% and 44.3%, respectively. High speed camera images indicated that after Sc-CO2 saturation, mode I crack directly propagated straight along artificial pre-crack direction, decreasing the degree of crack deviation as in KIC. The results of Cronos high-precision 3D scanning system and scanning electron microscopy (SEM) revealed complicated fracture mechanisms (transgranular, intergranular and mutual coupling crack mechanisms) of shale after Sc-CO2 saturation, which reduced the roughness and area of fracture crack surface. The generation of pore and cracks was the main reason for the decrease of shale resistance to fracture. Furthermore, Sc-CO2 saturated shale specimens only needed to absorb less energy to more rapidly cause the initiation and propagation of mode I cracks with the main fracture mode being transgranular cracks.

Comparative analysis of conventional methods for the evaluation of wettability in shales

Wettability has paramount importance in the characterization of shale reservoirs, yet its determination is quite challenging. The conventional techniques popularly applied for wettability determination of shales include contact angle, spontaneous imbibition, and floatation. However, there is no consensus as to the most appropriate method of assessing shale wettability, and which method is most suitable for a given shale sample. In this study, these techniques were employed to measure the wettability of outcrop Eagle Ford, Mancos, and Marcellus shale samples simultaneously to compare their efficacy. Sessile/Captive contact angles were measured on dry and saturated shale samples. The advancing/receding contact angles were also investigated by the drop-volume inflation/deflation method to understand wettability hysteresis. A better evaluation of shale surfaces’ wettability was attained when a water drop was gently placed on the water-saturated chips submerged in the bulk of oil and the contact angle between oil and water was measured. The contact angle and floatation methods showed relatively good agreement, perhaps because both methods relate to shale surficial affinity and mineralogy. However, the wettability of Eagle Ford and Mancos samples derived from contact angle, spontaneous imbibition, and floatation methods were not entirely similar. Only the spontaneous imbibition method was able to evaluate the mixed-wet characteristics of Marcellus shale samples properly because of the overlapped oil and brine saturation due to imbibition. The observed wettabilities are only specified for the studied outcrop samples. A novel approach somewhat like the Amott method is proposed for the quantitative assessment of wettability from spontaneous imbibition datasets, especially for mixed-wet rocks like shales. Overall, the order of reliability of the conventional techniques is spontaneous imbibition > contact angle > floatation. • The inference of shale wettability from contact angle measurements alone is susceptible to reliability issues. • The spontaneous imbibition technique can reveal the extent of pore characteristics and wetting preference of shales. • The order of reliability of the conventional methods is spontaneous imbibition > contact angle > floatation. • A novel wettability assessment approach is proposed for especially mixed-wet rocks like shales.

Realignments of the Colorado River by ∼2 m.y. of rotational bedrock landsliding: The Surprise Valley landslide complex, Grand Canyon, Arizona

Abstract The Surprise Valley landslide complex is the name used here for a group of prominent river-damming landslides in Grand Canyon (Arizona, USA) that has shifted the path of the Colorado River several times in the past 2 m.y. We document a sequence of eight landslides. Three are Toreva-block landslides containing back-rotated but only mildly disrupted bedrock stratigraphy. The largest of these landslides, Surprise Valley landslide, is hypothesized to have dammed the Colorado River, cut off a meander loop through Surprise Valley, and rerouted the river 2.5 km south to near its present course at the Granite Narrows. Another bedrock landslide, Poncho's runup, involved a mass detachment from the north side of the river that drove a kilometer-scale bedrock slab across the river and up the south canyon wall to a height of 823 m above the river. A lake behind this landslide is inferred from the presence of mainstem gravels atop the slide that represent the approximate spillway elevation. We postulate that this landslide lake facilitated the upriver 133 Mile slide detachment and Toreva block formation. The other five landslides are subsequent slides that consist of debris from the primary slides; these also partially blocked and diverted the Colorado River as well as the Deer Creek and Tapeats Creek tributaries into new bedrock gorges over the past 1 m.y. The sequence of landslides is reconstructed from inset relationships revealed by geologic mapping and restored cross-sections. Relative ages are estimated by measuring landslide base height above the modern river level in locations where landslides filled paleochannels of the Colorado River and its tributaries. We calculate an average bedrock incision rate of 138 m/m.y. as determined by a 0.674 ± 0.022 Ma detrital sanidine maximum depositional age of the paleoriver channel fill of the Piano slide, which has its base 70 m above the river level and ∼93 m above bedrock level beneath the modern river channel. This date is within error of, and significantly refines, the prior cosmogenic burial date of 0.88 ± 0.44 Ma on paleochannel cobbles. Assuming steady incision at 138 m/m.y., the age of Surprise Valley landslide is estimated to be ca. 2.1 Ma; Poncho's runup is estimated to be ca. 610 ka; and diversion of Deer Creek to form modern Deer Creek Falls is estimated to be ca. 400 ka. The age of the most recent slide, Backeddy slide, is estimated to be ca. 170 ka based on its near-river-level position. Our proposed triggering mechanism for Surprise Valley landslides involves groundwater saturation of a failure plane in the weak Bright Angel Formation resulting from large volumes of Grand Canyon north-rim groundwater recharge prior to establishment of the modern Deer, Thunder, and Tapeats springs. Poncho's and Piano landslides may have been triggered by shale saturation caused by 600–650 ka lava dams that formed 45 river miles (73 river km; river miles are measured along the Colorado River downstream from Lees Ferry, with 1 river mile = 1.62 river kms) downstream near Lava Falls. We cannot rule out effects from seismic triggering along the nearby Sinyala fault. Each of the inferred landslide dams was quickly overtopped (tens of years), filled with sediment (hundreds of years), and removed (thousands of years) by the Colorado River, as is also the potential fate of modern dams.

Geochemical reactions and alteration of pore architecture in saturated shale after injection of stimulation fluid

Pore architecture regulates fluid flow between unconventional shale reservoir and hydraulically-induced fractures. Imbibition of stimulation fluid may change this architecture and alter hydrocarbon flow. Hydrothermal experiments were conducted at reservoir conditions (125 °C, 45 MPa) to test two hypotheses: 1) Shale, not stimulation fluid, dominates the geochemistry of an unconventional reservoir containing formation water; and 2) Mineral dissolution and precipitation induced by stimulation fluid is transient and manifests across micro-, meso-, and macro-scales of pore architecture. Experiments replicated a shut-in well in the Cretaceous Baxter Shale, Green River Basin, Wyoming USA. Stimulation fluid was injected into one experiment after formation water (I = 0.35 mol/kg, pH = 6.4) and core reacted for 48 days. This novel approach equilibrated rock and formation water and saturated pores with formation water before introducing stimulation fluid. The second experiment served as a control. Trends of aqueous calcium, silica and aluminum in the injection experiment suggest transient dissolution of calcite and feldspar and/or quartz as well as clay and barite precipitation; mineralogic evidence was limited to calcite dissolution and barite precipitation. The rock maintained reducing conditions (Eh = +0.08 to −0.16 V) despite injection of oxidizing stimulation fluid (Eh = 1.1 V). pH of the stimulation fluid-formation water mixture evolved from 2.3 to pre-injection values (~6) within 24 h. Results indicate that mineral dissolution and precipitation manifest in macropores with barely detectable alteration to micro- and mesopores. Formation water or organic matter in pores may have inhibited access of stimulation fluid to micro- and mesopores

Experimental study on the long-term stability of shale rock wellbore under high hydraulic pressure

Hydraulic pressure is one of the important factors influencing the stability of well rock. In this paper, the sleeve typed shale rock specimens were used to laboratory simulate the long-term stability of shale rock wellbore under hydro-mechanical coupled condition. Based on the analysis of triaxial tests data, the strength characteristic of the saturated shale specimens was first studied. The results show that the strength presents an exponential decreasing trend with increasing hydraulic pressure; 5 MPa hydraulic pressure resulted in the axial compressive strength declined by around 12.20% and about 17.78% fell under the hydraulic pressure of 10 MPa. The creep behavior of the shale was also analyzed in detail. It was found that 60% of the triaxial compression strength can easily lead to rupture of specimen under hydraulic pressure of 5 MPa, while more than 73% of the triaxial compression strength is needed under the same confining pressure without hydraulic pressure. The hydraulic pressure as well as its action time obviously affects the wellbore failure characteristics, which may lead to the damage area appearing pulverized, seriously reducing its mechanical properties. A new viscoelastic-plastic creep damage model was proposed to describe the creep behavior of shale rock, and it was found that the creep model can be used to predict the long-term stability of the wellbore.

Optimization of safe gas core retrieval using multivariate numerical simulation, based on different pore rheology and rock lamination

High gas compressibility, facies lamination, and presence of sub-lateral microfractures make shale gas reservoir rocks very sensitive to changing outer pressure and lead to severe damage of the whole core when it is recovered to surface. The approaches currently used for safe core retrieval do not adequately account for gas shale features, therefore, they are not capable of reliable modeling of this process. The article presents an extension of the recently developed optimization of the core tripping algorithm to shale gas formations featuring significant improvements. One, we show the lead role of strong inter-relation between gas flow and rock deformation process in the optimization of the core lifting process and propose a new decompression model of gas saturated shale rocks. Two, we introduce the dynamic permeability concept for shale gases, which considers individual behavior of the pores in organic matter, inorganic matrix, and microcracks. Three, we propose ways for calculation of the stress-strain state in cylindrical domain by applying numerical and semi-analytical solutions. Four, we introduce an interface failure mechanism for lamination rocks. Finally, we discuss the influence of different void types on decompression and dependence of the optimal schedule on microfracturing properties. Eventually, the article outlines several significant conclusions. In the fractured region, the degassing slows down due to crack closure near to the outer core boundary. The interface failure is an overlooked mechanism of rock failure. Frequent and long stoppages are required for preventing interface crack extension.

Coupled Damage-Plasticity Modelling of Saturated Shale under Undrained Condition

Shale is classified as a poroelastic material as the shale matrix has comparable stiffness with its constituent solid grains. Also, shales at large depth are often fully saturated. Due to their low permeability, which can be in the nano-Darcy range, shales remain undrained during typical loading conditions. Additionally, shales are quasi-brittle materials which can exhibit very pronounced peak shear stress followed by pronounced strain softening during shearing. All these unique aspects of shale behavior must be considered in developing a model that predicts the change of the pore pressure, the effective stress response and the undrained shear strength of shales during loading. This study presents a coupled plastic-damage constitutive model which considers poroelastic effect with the objective to predict the mechanical behavior of saturated shales under undrained condition. The proposed model couples the plastic mechanism, which is formulated on the effective stress space, and the damage mechanism which is responsible for the elasticity degradation and the post-peak softening of shale. Validation of the proposed model against triaxial est results demonstrates that the proposed model can predict the stress-strain behavior, the effective stress path and the pore pressure evolution of shale specimen during shearing.

Insights into NMR response characteristics of shales and its application in shale gas reservoir evaluation

To elucidate the NMR response characteristics of gas-bearing shales, NMR T2 and T1–T2 experiments were performed on 38 shale samples selected from the Longmaxi Formation in the southern Sichuan Basin in China. The NMR signals of the totally dried shales were basically distributed in a single left peak and could not be removed completely. The T2 spectra of water-saturated shales presented two- or three-peak distributions. With the increase in depth, the T2 peaks tended to be skewed to the right, indicating that the proportion of meso-macropores of the shale in the L1l1 sublayer is the largest. The T1–T2 signal peaks of the dried shales are dominantly distributed in the region where T1/T2 ratio＜100 and T2 = 0.1 ms, and that of the saturated shales are 1 mainly distributed in the region where 1＜T1/T2 ratio＜100 and 1 ms＜T2＜10 ms, respectively. A preliminary T1–T2 division method was proposed to differentiate hydrogen-bearing components in gas-bearing shales. Combining the T1–T2 maps and correlation analysis confirms that the NMR signal of dry shale is mainly from clay structural water. NMR porosity should be corrected by removing the NMR signal of dry shales. After correction, the error between NMR porosity and WIP (water immersion porosimetry) porosity was considerably reduced, and its mean absolute error was only 0.16%. Moreover, a parameter T2g was proposed to evaluate the Longmaxi shale gas reservoir, which was increased in depth and reached the maximum in the L1l1 sublayer. Moreover, the boundary value of T2g was determined for reservoir evaluation and classification.

Effect of supercritical CO2 saturation pressures and temperatures on the methane adsorption behaviours of Longmaxi shale

Abstract To investigate the effects of supercritical CO2 (SC–CO2) saturation pressures and temperatures on the methane adsorption capacity of shale, total organic carbon (TOC) analysis, X-ray diffraction (XRD) analysis, scanning electron microscope and energy dispersive spectrometer (SEM/EDS) analysis, low-pressure N2 adsorption (LP-NA), and high-pressure methane adsorption (HP-MA) were conducted on raw and SC–CO2–saturated (8, 12, 16 MPa; 40, 60, 80 °C) shale collected from the Sichuan Basin. Results indicate that the excess adsorption isotherm of shale to methane clearly exhibited excess adsorption characteristics with increasing adsorption pressures. This excess methane adsorption capacity decreased after SC-CO2 saturation and is mainly attributable to decreases in the TOC content, clay minerals and specific surface area (SSA) in the SC–CO2–saturated shale. The density of adsorbed phase methane was considered at different adsorption models, and the results suggest that the Langmuir-Freundlich (LF) and Dubinin-Astakhov (DA) models better describe methane adsorption behaviours than the Langmuir and Ono-kondo models. The methane adsorption capacity of shale is closely related to the solubility of SC-CO2, which decreased significantly with increasing SC-CO2 saturation time and pressure, while the influence of SC-CO2 saturation temperatures was not evident at low-pressure (8 MPa). This study provides a theoretical reference for CO2 enhanced shale gas recovery.

Effect of contact surface area on frictional behaviour of dry and saturated rock joints

Frictional behaviour of joints/faults is of great importance in many geo-engineering applications across different scales. It is known that the joint surface roughness is one of the critical parameters controlling the frictional behaviour of rock joints. While nominal normal and shear stresses acting across the joint asperities are calculated based on overall shearing area, the actual normal and shear stresses can be much greater due to smaller actual contact area. The actual contact area on the other hand is known to be related to the joint surface roughness. In order to investigate the effect of contact area on the shear behaviour of rock joints, an extensive set of direct shear experiments at different normal stresses on dry and saturated shale, limestone and sandstone tensile joints were undertaken. To compare the frictional properties of natural and artificial samples, synthetic samples were also fabricated, and their frictional properties were evaluated. Results of this study revealed that the predominant parameter controlling the frictional strength is the actual contact area. While the common models in predicting the shear strength of rock joints were unable to fit the experimental data based on nominal contact area, the results based on actual contact area fit the measured values accurately. In addition, it was observed that when the actual contact area is considered, Mohr-Coulomb criterion is sufficient to fit the experimental data irrespective of the rock type, joint surface roughness or whether dry or saturated. This highlights that the Mohr-Coulomb criterion can appropriately predict the frictional strength if the actual contact area can be estimated. More importantly, the results showed that the surface roughness cannot dictate the shear behaviour of rock joints without considering the actual contact area.

Experimental investigation on the influence of sub- and super-critical CO2 saturation time on the permeability of fractured shale

The permeability variation of shale due to the CO2 saturation induced deformation has significant influence on the overall CO2 injection capacity and shale gas production. In this study, the effect of subcritical (SubCO2) and supercritical CO2 (ScCO2) saturation and its action time on the permeability evolution of fractured shale sample was examined. Five saturation times (4, 10, 12, 18, 24 h), both for SubCO2 (6 MPa) and ScCO2 (8 MPa), were introduced to the shale sample. For each saturation cyclic, the permeability of shale sample was determined by helium injection with various injection pressures (2–6 MPa). Results indicated that the permeability of shale sample is significantly reduced after CO2 saturation, and is decreased with the increase of CO2 saturation time due to the time dependent adsorption-induced swelling. ScCO2 induced a higher permeability reduction and a longer permeability reduction process than SubCO2, due to its higher affinity and higher viscosity in shale. The permeability has a negative exponential relation with effective stress for SubCO2 and ScCO2 saturated shale samples. After CO2 saturation, the stress sensitivity of shale permeability increased with the CO2 saturation time, which is related to the time dependent mechanical weakening of shale induced by CO2-shale interaction. ScCO2 induced a larger increase in stress sensitivity of shale permeability than SubCO2, because it induced more remarkable weakening of mechanical properties in shale.

Crack fluid identification of shale reservoir based on stress-dependent anisotropy

Shale reservoirs are typically very tight, and crack are only a small part of the reservoir. The directional arrangement of cracks leads to the anisotropic characteristics of shale, and the type of fluid filled in cracks affects the shale reservoir evaluation and late development. Many rock physics theories and methods typically use second- and fourth-order crack density tensors to characterize the elastic anisotropy induced by cracks as well as the normal-to-tangential crack compliance ratio to distinguish between dry and saturated cracks. This study defines an anisotropic crack fluid indicator for vertical transversely isotropy (VTI) media with vertical symmetry axis which is the integration of the normal-to-tangential crack compliance ratio in three directions. A new dimensionless fourth-order tensor, including crack fluid type, azimuth distribution, and geometric shape, is constructed by substituting the normal and tangential compliance into the fourth-order crack density tensor, which can also be used to identify the type of crack fluid in the VTI media. Using the Callovo-Oxfordian shale experimental data, the variation of the elastic properties of dry and saturated shale samples with axial stress is analyzed. The results demonstrate that the anisotropic crack fluid indicator of water-bearing shale samples is less than that of the dry shale samples and that the dimensionless fourth-order tensor of water-bearing shale samples is nearly one order of magnitude greater than that of the dry shale samples. Therefore, the anisotropic crack fluid indicator and dimensionless fourth-order tensor can reflect the crack fluid type in shale samples and can be used for shale reservoir prediction and fluid identification.

Mathematical modeling of the acoustic and elastic anisotropy of the shale reservoir rocks of the Dnipro-Donetsk depression

The purpose of the work is to analyze the parameters of elastic and acoustic anisotropy in the study of a multicomponent reservoir rock model, which is represented by shale. Research theory To solve this problem, the methods of conditional moment functions using the Mori-Tanaka calculation scheme, as well as the ordinary least squares were used. The technique of effective elastic invariables mathematical modelling of unconventional shale reservoir rocks has been developed. Justification of the mathematical model Eight varieties of mathematical models that characterize the mineral composition, the structure of the void space and elastic properties that are characteristic for shale reservoir rocks of the Dnipro-Donetsk depression in Ukraine were substantiated and developed. The models are based on previous publications by the authors and the results of petrographic studies at the Institute of Geology. Results The authors for the first time carried out an analysis of elastic constant rock models, acoustic tensor components, linearity and shale parameters, isolines stereo projections of index surfaces of nine elastic anisotropy parameters, as well as Thomsen parameters. Acoustic data can be used to trace the change in the structure of the reservoir rock void space, the concentration of rock-forming minerals in the rock. Fracturing has a greater effect on rock structure than granular voids and mineral structure. The orientation of inclusions has the greatest influence on the coefficient of acoustic anisotropy, anisotropy coefficients in rocks, where the voids are oriented in the plane perpendicular to the borehole axis have the largest values (more than 20%). When calculating the Thomsen parameters, the parameters of elastic anisotropy were obtained. They characterize not only the mineral composition of the rocks but also the qualitative structure of the void space, the orientation of minerals and voids in the rocks. Thomsen parameters correlate with acoustic anisotropy parameters for shale reservoir models. The parameters of acoustic and elastic anisotropy are indicators in the studies of similar-type rocks with different types of mineral inclusions and the structure of the void space. The mathematical modelling of elastic and acoustic parameters which characterizes their anisotropy and was carried out by the authors is an important step in substantiating mathematical models of shale reservoir rocks. Such models can be used in the interpretation of geophysical data (seismic surveys and well logging) to make corrections for elastic anisotropy in prospecting and exploration of oil, gas and water saturated unconventional shale reservoir rocks of complex structure, and also to compile a database of mathematical models of reservoir rocks in the given region.

Experimental investigation of the effects of clay content and compaction stress on the elastic properties and anisotropy of dry and saturated synthetic shale

Anisotropy in shales is an important issue in exploration and reservoir geophysics, and it has been proven extremely difficult to correlate anisotropy in natural shale by means of a single variable (in this case, clay content or compaction stress) because of the influence of multiple factors, such as water content, total organic carbon content, and complex mineral compositions. Thus, we used quartz, kaolinite, calcite, and kerogen extract as the primary materials to construct two sets of synthetic shale samples, each with a different clay content by weight and a different compaction stress. Ultrasonic experiments were conducted to investigate the anisotropy of velocity and mechanical properties in dry and saturated samples of our synthetic shales. The results reveal that the velocities decrease with clay content by weight and increase with compaction stress and that these changes are significant at low compaction stress. The velocity anisotropy of the samples increases with clay content and compaction stress due to the increasing alignment of the clay platelets. S-wave anisotropy is more sensitive to the clay content or compaction stress than P-wave anisotropy. The dynamic Young’s modulus [Formula: see text] of the samples decreases with clay content and increases with compaction stress, whereas Poisson’s ratio [Formula: see text] increases with clay content and decreases with compaction stress. Young’s modulus perpendicular to the symmetry axis is always larger than that parallel to the symmetry axis, but Poisson’s ratio perpendicular to the symmetry axis may be larger or smaller than that parallel to the symmetry axis, which indicates that mechanical properties have obvious anisotropic behavior. The elastic properties and anisotropy are also affected by fluids; the values of elastic and mechanical anisotropy parameters in saturated samples are significantly lower than those in dry samples.